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UNITED STATES


SECURITIES AND EXCHANGE COMMISSION


WASHINGTON, D.C.  20549





FORM 10-Q





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


OF THE SECURITIES EXCHANGE ACT OF 1934





For the quarterly period ended June 30, 2014





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)


Delaware73-0785597(State or other jurisdiction of incorporation or organization)(I.R.S. employer identification number)1001 Noble Energy WayHouston, Texas77070(Address of principal executive offices)(Zip Code)(281) 872-3100(Registrant’s telephone number, including area code)





Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.


Yes ý No o


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


Yes ý No o


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


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


in Rule 12b-2 of the Exchange Act.


Large accelerated filerxAccelerated fileroNon-accelerated fileroSmaller reporting companyo(Do not check if a smaller reporting company)


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


Yes o No ý





As of June 30, 2014 , there were 361,732,310 shares of the registrant’s common stock,


par value $0.01 per share, outstanding.





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Table of Contents





Part I.Financial Information3Item 1.Financial Statements3Consolidated Statements of Operations3Consolidated Statements of Comprehensive Income4Consolidated Balance Sheets5Consolidated Statements of Cash Flows6Consolidated Statements of Shareholders' Equity7Notes to Consolidated Financial Statements8Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations23Item 3.Quantitative and Qualitative Disclosures About Market Risk41Item 4.Controls and Procedures42Part II.Other Information43Item 1.Legal Proceedings43Item 1A.Risk Factors43Item 2.Unregistered Sales of Equity Securities and Use of Proceeds43Item 3.Defaults Upon Senior Securities44Item 4.Mine Safety Disclosures44Item 5.Other Information44Item 6.Exhibits44Signatures45Index to Exhibits46





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Part I. Financial Information


Item 1. Financial Statements


Noble Energy, Inc.


Consolidated Statements of Operations


(millions, except per share amounts)


(unaudited)


Three Months EndedJune 30,Six Months EndedJune 30,2014201320142013RevenuesOil, Gas and NGL Sales$1,338$1,112$2,665$2,196Income from Equity Method Investees45379796Total1,3831,1492,7622,292Costs and ExpensesProduction Expense248210481398Exploration Expense5990133151Depreciation, Depletion and Amortization413368837734General and Administrative127104266216(Gain) Loss on Divestitures(44)4(42)(12)Asset Impairments34—131—Other Operating Expense, Net17122320Total8547881,8291,507Operating Income529361933785Other (Income) Expense(Gain) Loss on Commodity Derivative Instruments236(161)311(89)Interest, Net of Amount Capitalized52339958Other Non-Operating Expense, Net831312Total296(125)423(19)Income from Continuing Operations Before Income Taxes233486510804Income Tax Provision41128118214Income from Continuing Operations192358392590Discontinued Operations, Net of Tax—19—49Net Income$192$377$392$639Earnings Per Share, BasicIncome from Continuing Operations$0.53$1.00$1.09$1.64Discontinued Operations, Net of Tax—0.05—0.14Net Income$0.53$1.05$1.09$1.78Earnings Per Share, DilutedIncome from Continuing Operations$0.52$0.99$1.07$1.63Discontinued Operations, Net of Tax—0.05—0.13Net Income$0.52$1.04$1.07$1.76Weighted Average Number of Shares OutstandingBasic361359361358Diluted366363365362





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


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Noble Energy, Inc.


Consolidated Statements of Comprehensive Income


(millions)


(unaudited)








Three Months EndedJune 30,Six Months EndedJune 30,2014201320142013Net Income$192$377$392$639Other Items of Comprehensive IncomeNet Change in Pension and Other551011Less Tax Benefit(1)(2)(4)(4)Other Comprehensive Income4367Comprehensive Income$196$380$398$646





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





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Noble Energy, Inc.


Consolidated Balance Sheets


(millions)


(unaudited)





June 30, 2014December 31, 2013ASSETSCurrent AssetsCash and Cash Equivalents$958$1,117Accounts Receivable, Net1,004947Other Current Assets312547Total Current Assets2,2742,611Property, Plant and EquipmentOil and Gas Properties (Successful Efforts Method of Accounting)24,08822,243Property, Plant and Equipment, Other600517Total Property, Plant and Equipment, Gross24,68822,760Accumulated Depreciation, Depletion and Amortization(7,712)(7,035)Total Property, Plant and Equipment, Net16,97615,725Goodwill621627Other Noncurrent Assets704679Total Assets$20,575$19,642LIABILITIES AND SHAREHOLDERS’ EQUITYCurrent LiabilitiesAccounts Payable - Trade$1,369$1,354Other Current Liabilities866988Total Current Liabilities2,2352,342Long-Term Debt5,1604,566Deferred Income Taxes, Noncurrent2,4832,441Other Noncurrent Liabilities1,1431,109Total Liabilities11,02110,458Commitments and ContingenciesShareholders’ EquityPreferred Stock - Par Value $1.00 per share; 4 Million Shares Authorized, None Issued——Common Stock - Par Value $0.01 per share; 500 Million Shares Authorized; 402 Millionand 400 Million Shares Issued, respectively44Additional Paid in Capital3,5663,463Accumulated Other Comprehensive Loss(111)(117)Treasury Stock, at Cost; 38 Million Shares(674)(659)Retained Earnings6,7696,493Total Shareholders’ Equity9,5549,184Total Liabilities and Shareholders’ Equity$20,575$19,642





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





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Noble Energy, Inc.


Consolidated Statements of Cash Flows


(millions)


(unaudited)


Six Months EndedJune 30,20142013Cash Flows From Operating ActivitiesNet Income$392$639Adjustments to Reconcile Net Income to Net Cash Provided by Operating ActivitiesDepreciation, Depletion and Amortization837736Asset Impairments131—Dry Hole Cost223Deferred Income Taxes24108Income from Equity Method Investees, Net of Dividends(3)(18)(Gain) Loss on Commodity Derivative Instruments311(89)Net Cash Received (Paid) in Settlement of Commodity Derivative Instruments(83)9Gain on Divestitures(42)(67)Stock Based Compensation4538Other Adjustments for Noncash Items Included in Income3833Changes in Operating Assets and Liabilities(Increase) Decrease in Accounts Receivable55(193)Increase in Accounts Payable126131Decrease in Current Income Taxes Payable(86)(81)Increase (Decrease) in Other Current Liabilities25(33)Other Operating Assets and Liabilities, Net(15)8Net Cash Provided by Operating Activities1,7571,244Cash Flows From Investing ActivitiesAdditions to Property, Plant and Equipment(2,321)(1,929)Additions to Equity Method Investments(40)(23)Proceeds from Divestitures146114Other—3Net Cash Used in Investing Activities(2,215)(1,835)Cash Flows From Financing ActivitiesExercise of Stock Options4131Excess Tax Benefits from Stock-Based Awards1712Dividends Paid, Common Stock(116)(96)Purchase of Treasury Stock(15)(14)Proceeds from Credit Facilities600—Repayment of Senior Notes(200)—Repayment of Capital Lease Obligation(28)(23)Net Cash Provided by (Used in) Financing Activities299(90)Decrease in Cash and Cash Equivalents(159)(681)Cash and Cash Equivalents at Beginning of Period1,1171,387Cash and Cash Equivalents at End of Period$958$706





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





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Noble Energy, Inc.


Consolidated Statements of Shareholders' Equity


(millions)


(unaudited)





CommonStock(1)AdditionalPaid inCapital(1)Accumulated OtherComprehensiveLossTreasuryStock atCostRetainedEarningsTotalShareholders'EquityDecember 31, 2013$4$3,463$(117)$(659)$6,493$9,184Net Income————392392Stock-based Compensation—45———45Exercise of Stock Options—41———41Tax Benefits Related to Exercise of Stock Options—17———17Dividends (32 cents per share)————(116)(116)Changes in Treasury Stock, Net———(15)—(15)Net Change in Pension and Other——6——6June 30, 2014$4$3,566$(111)$(674)$6,769$9,554December 31, 2012$4$3,302$(113)$(648)$5,713$8,258Net Income————639639Stock-based Compensation—38———38Exercise of Stock Options—31———31Tax Benefits Related to Exercise of Stock Options—12———12Dividends (27 cents per share)————(96)(96)Changes in Treasury Stock, Net———(14)—(14)Net Change in Pension and Other——7——7June 30, 2013$4$3,383$(106)$(662)$6,256$8,875





|    |                                                                                                
|--- | -----------------------------------------------------------------------------------------------
|(1) | Amounts reflect impact of 2-for-1 stock split which occurred during the second quarter of 2013.




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


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 Noble Energy, Inc.
 Notes to Consolidated Financial Statements





Note 1.  Organization and Nature of Operations


Noble Energy, Inc. (Noble Energy, we or us) is a leading independent energy company engaged in worldwide crude oil and natural gas exploration and production. Our core operating areas are onshore US, 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 June 30, 2014 and December 31, 2013 and for the three and six months ended June 30, 2014 and 2013 contain all normally recurring adjustments considered necessary for a fair presentation of our financial position, results of operations, cash flows and shareholders’ equity for such periods. Operating results for the three and six months ended June 30, 2014 are not necessarily indicative of the results that may be expected for the year ending December 31, 2014 .


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, 2013 .


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.


Discontinued Operations In 2012, we initiated a strategy to exit the North Sea geographical area through sales of our non-operated working interests in the assets. The North Sea geographical segment was classified as held for sale and the operations were reflected as discontinued operations in 2012 and 2013.


The most significant North Sea assets were sold during 2012 and 2013. However, we have been unable to locate purchasers for the remaining assets, and a sale is no longer considered probable. Therefore, during first quarter 2014, we reclassified the remaining North Sea assets to held and used, and the North Sea geographical segment is included in continuing operations in first and second quarters 2014. In addition, we recorded impairments for the North Sea assets in both the first and second quarters of 2014. See Note 4. Asset Impairments .


North Sea revenues and operating expenses for the six months ended June 30, 2014, except for the impairments recorded in the first and second quarters 2014, were de minimis.  See Note 3. Divestitures ,  Note 4. Asset Impairments , and Note 7. Fair Value Measurements and Disclosures .


Common Stock Split On April 22, 2013 , Noble Energy’s Board of Directors approved a 2 -for-1 split of its common stock to be effected in the form of a stock dividend. The stock dividend was distributed on May 28, 2013 to shareholders of record as of May 14, 2013 . Earnings per share and common shares outstanding are reported giving retrospective effect to the common stock split.


Recently Issued Accounting Standards In April 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2014-08: Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (ASU 2014-08). ASU 2014-08 changes the criteria for reporting discontinued operations while enhancing disclosures in this area and is effective for annual and interim periods beginning after December 15, 2014. Early adoption is permitted for disposals or for assets classified as held for sale that have not been reported in previously issued financial statements.  We elected to early adopt ASU 2014-08 on a prospective basis, and the adoption did not have a material impact on our consolidated financial statements.


In May 2014, the FASB issued Accounting Standards Update No. 2014-09 (ASU 2014-09), which creates Topic 606, Revenue from Contracts with Customers, and supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, including most industry-specific revenue recognition guidance throughout the Industry Topics of the Codification. In addition, ASU 2014-09 supersedes the cost guidance in Subtopic 605-35, Revenue Recognition—Construction-Type and Production-Type Contracts, and creates new Subtopic 340-40, Other Assets and Deferred Costs— Contracts with Customers. In summary, the core principle of Topic 606 is that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Additionally, ASU 2014-09 requires enhanced financial statement disclosures over revenue recognition as part of the new accounting guidance. The amendments in ASU 2014-09 are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, and early application is not permitted.  We are


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 Noble Energy, Inc.
 Notes to Consolidated Financial Statements


currently evaluating the provisions of ASU 2014-09 and assessing the impact, if any, it may have on our financial position and results of operations.


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


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


Three Months EndedJune 30,Six Months EndedJune 30,(millions)2014201320142013Production ExpenseLease Operating Expense$154$140$299$257Production and Ad Valorem Taxes534310286Transportation and Gathering Expense41278055Total$248$210$481$398Other Non-Operating (Income) Expense, NetDeferred Compensation Expense(1)$8$3$12$14Other (Income) Expense, Net——1(2)Total$8$3$13$12





|    |                                                                                                   
|--- | --------------------------------------------------------------------------------------------------
|(1) | Amounts represent increases in the fair value of shares of our common stock held in a rabbi trust.




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 Noble Energy, Inc.
 Notes to Consolidated Financial Statements


Balance Sheet Information Other balance sheet information is as follows:


(millions)June 30, 2014December 31, 2013Accounts Receivable, NetProceeds Receivable from China Asset Sale(1)$150$—Commodity Sales464495Joint Interest Billings310382Other9181Allowance for Doubtful Accounts(11)(11)Total$1,004$947Other Current AssetsInventories, Materials and Supplies$94$96Inventories, Crude Oil2325Deferred Income Taxes, Net6362Assets Held for Sale74292Prepaid Expenses and Other Current Assets5872Total$312$547Other Noncurrent AssetsEquity Method Investments$484$437Mutual Fund Investments121114Commodity Derivative Assets216Other Assets97112Total$704$679Other Current LiabilitiesProduction and Ad Valorem Taxes$111$103Commodity Derivative Liabilities19965Income Taxes Payable77156Asset Retirement Obligations14139Interest Payable6163Current Portion of Long Term Debt(2)—200Current Portion of Capital Lease(2)5958Liabilities Associated with Assets Held for Sale14111Other204193Total$866$988Other Noncurrent LiabilitiesDeferred Compensation Liabilities$276$253Asset Retirement Obligations563547Accrued Benefit Costs108155Commodity Derivative Liabilities8910Other107144Total$1,143$1,109


|    |                                                                                                      
|--- | -----------------------------------------------------------------------------------------------------
|(1) | The sale was completed on June 30, 2014; bank transfer of the proceeds was completed on July 2, 2014.

|    |                 
|--- | ----------------
|(2) | See Note6. Debt.




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 Noble Energy, Inc.
 Notes to Consolidated Financial Statements


Note 3.  Divestitures


Onshore US Properties During the first six months of 2014 , we sold certain non-core onshore US crude oil and natural gas properties. The information regarding the assets sold is as follows: Three Months EndedJune 30,Six Months EndedJune 30,(millions)20142014Sales Proceeds$18$110LessNet Book Value of Assets Sold(11)(118)Goodwill Allocated to Assets Sold—(6)Asset Retirement Obligations Associated with Assets Sold—20Gain on Divestitures$7$6


China On June 30, 2014, we closed the sale of our China assets. We determined the sale of our China assets did not meet the criteria for discontinued operations presentation under ASU 2014-08. See Note 2. Basis of Presentation - Recently Issued Accounting Standards . The information regarding the China assets sold is as follows:


Six Months EndedJune 30,(millions)2014Sales Proceeds(1)$186LessNet Book Value of Assets Sold(149)Other Closing Adjustments(2)Gain on Divestiture$35


(1) Proceeds included $36 million cash received prior to June 30, 2014 and $150 million cash received on July 2, 2014, which was recorded as accounts receivable at June 30, 2014.


Offshore Israel Properties Assets held for sale as of June 30, 2014 , include two natural gas discoveries, offshore Israel. We expect to divest these assets pursuant to an agreement we and our partners reached with the Israeli Antitrust Authority in March 2014 on various antitrust matters. The agreement is subject to final approval of the Israeli government.


North Sea Properties During the first six months of 2013 , we sold non-operated working interests in properties located in the North Sea. The sales resulted in a $55 million gain based on net sales proceeds of $54 million .  See Note 2. Basis of Presentation - Discontinued Operations .


Summarized results of discontinued operations are as follows: Six Months EndedJune 30,(millions)2013Oil and Gas Sales$21Income Before Income Taxes4Income Tax Expense10Operating Loss, Net of Tax(6)Gain on Sale, Net of Tax55Discontinued Operations, Net of Tax$49


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 Noble Energy, Inc.
 Notes to Consolidated Financial Statements


Note 4. Asset Impairments


Pre-tax (non-cash) asset impairment charges were as follows: Three Months EndedJune 30,Six Months Ended June 30,(millions)2014201320142013US Properties, Primarily Shelf and Deepwater Gulf of Mexico$18$—$23$—Mari-B (Offshore Israel)14—14—McCulloch and Other North Sea Properties2—94—Total$34$—$131$—


US and Offshore Israel In the US and offshore Israel, the asset carrying values of certain oil and natural gas assets increased when we recorded associated increases in asset retirement obligations. We determined that the recorded asset carrying values of some of these assets were not recoverable from future cash flows and recorded impairment expense. US properties included the currently-producing Raton natural gas well, as well as the Conquest and Gemini fields, which are being abandoned.


North Sea In March 2014, the operator of one of our remaining North Sea fields notified the working interest owners that expected field abandonment costs would be higher than originally projected. The operator also notified the working interest owners that it would begin working with the appropriate regulatory agency for approval of cessation of production and subsequent field abandonment sooner than anticipated.


As a result of this new information, we adjusted the asset retirement obligation to reflect the updated estimate of abandonment  costs and timing. We assessed the asset for impairment and determined that it was impaired. The impairment charge was included in consolidated income from continuing operations.


See Note 2. Basis of Presentation and Note 7. Fair Value Measurements and Disclosures .


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 Notes to Consolidated Financial Statements


Note 5.  Derivative Instruments and Hedging Activities


Objective and Strategies for Using Derivative Instruments We are exposed to fluctuations in crude oil and natural gas prices on the majority of our production. In order to mitigate the effect of commodity price volatility and enhance the predictability of cash flows relating to the marketing of our global crude oil and domestic natural gas, we enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production. 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 7. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of our derivative instruments.


Unsettled Commodity Derivative Instruments As of June 30, 2014 , we had entered into the following crude oil derivative instruments: SwapsCollarsSettlementPeriodType of ContractIndex(1)Bbls PerDayWeightedAverageFixedPriceWeightedAverageShort PutPriceWeightedAverageFloorPriceWeightedAverageCeilingPriceInstruments Entered Into as of June 30, 20142014SwapsNYMEX WTI37,000$92.67$—$—$—2014SwapsDated Brent13,000103.21———2014Three-Way CollarsNYMEX WTI12,000—75.6790.67100.882014Three-Way CollarsDated Brent8,000—84.3898.25121.562015SwapsNYMEX WTI27,00088.80———2015SwapsDated Brent9,000100.16———2015Three-Way CollarsNYMEX WTI20,000—70.5087.5594.412015Three-Way CollarsDated Brent13,000—76.9296.00108.492016SwapsNYMEX WTI6,00087.95———2016SwapsDated Brent9,00097.98———2016Three-Way CollarsNYMEX WTI3,000—72.0085.0094.822016Three-Way CollarsDated Brent6,000—80.0095.00105.87


|    |                        
|--- | -----------------------
|(1) | West Texas Intermediate

As of June 30, 2014 , we had entered into the following natural gas derivative instruments: SwapsCollarsSettlementPeriodType of ContractIndex(1)MMBtuPer DayWeightedAverageFixedPriceWeightedAverageShort PutPriceWeightedAverageFloorPriceWeightedAverageCeilingPriceInstruments Entered Into as of June 30, 20142014SwapsNYMEX HH60,000$4.24$—$—$—2014Three-Way CollarsNYMEX HH230,000—2.833.754.982015SwapsNYMEX HH140,0004.30———2015Three-Way CollarsNYMEX HH150,000—3.594.255.06


|    |          
|--- | ---------
|(1) | Henry Hub

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 Notes to Consolidated Financial Statements


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


Fair Value of Derivative InstrumentsAsset Derivative InstrumentsLiability Derivative InstrumentsJune 30, 2014December 31, 2013June 30, 2014December 31, 2013(millions)BalanceSheetLocationFairValueBalance Sheet LocationFairValueBalance Sheet LocationFairValueBalance Sheet LocationFairValueCommodity DerivativeInstrumentsCurrentAssets$—Current Assets$1Current Liabilities$199Current Liabilities$65Noncurrent Assets2Noncurrent Assets16Noncurrent Liabilities89Noncurrent Liabilities10Total$2$17$288$75





The effect of commodity derivative instruments on our consolidated statements of operations was as follows: Three Months EndedJune 30,Six Months EndedJune 30,(millions)2014201320142013(Gain) Loss on Commodity Derivative InstrumentsCrude Oil$238$(118)$292$(69)Natural Gas(2)(43)19(20)Total (Gain) Loss on Commodity Derivative Instruments236(161)311(89)Cash (Received) Paid in Settlement of Commodity Derivative InstrumentsCrude Oil4667314Natural Gas3(8)10(23)Total Cash (Received) Paid in Settlement of Commodity Derivative Instruments49(2)83(9)Non-cash Portion of (Gain) Loss on Commodity Derivative InstrumentsCrude Oil192(124)219(83)Natural Gas(5)(35)93Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments$187$(159)$228$(80)


AOCL Accumulated other comprehensive loss (AOCL) at June 30, 2014 included deferred losses of $23 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 term of our senior notes due March 2041 . The amount of deferred losses (net of tax) which will be reclassified to earnings during the next 12 months, and recorded as an increase in interest expense, is de minimis.


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 Notes to Consolidated Financial Statements


Note 6.  Debt


Debt consists of the following: June 30, 2014December 31, 2013(millions, except percentages)DebtInterest RateDebtInterest RateCredit Facility, due October 3, 2018$6001.41%$——%Capital Lease and Other Obligations353—359—51⁄4% Senior Notes, due April 15, 2014(1)——%2005.25%81⁄4% Senior Notes, due March 1, 20191,0008.25%1,0008.25%4.15% Senior Notes, due December 15, 20211,0004.15%1,0004.15%71⁄4% Senior Notes, due October 15, 20231007.25%1007.25%8% Senior Notes, due April 1, 20272508.00%2508.00%6% Senior Notes, due March 1, 20418506.00%8506.00%51⁄4% Senior Notes, due November 15, 20431,0005.25%1,0005.25%71⁄4% Senior Debentures, due August 1, 2097847.25%847.25%Total5,2374,843Unamortized Discount(18)(19)Total Debt, Net of Discount5,2194,824Less Amounts Due Within One Year51⁄4% Senior Notes, due April 15, 2014, net of discount(1)—(200)Capital Lease Obligations(59)(58)Long-Term Debt Due After One Year$5,160$4,566


|    |                                              
|--- | ---------------------------------------------
|(1) | We repaid the Senior Notes on their due date.

Credit Facility Our Credit Agreement provides for a $4.0 billion unsecured revolving credit facility (Credit Facility), which is available for general corporate purposes. The Credit Facility (i) provides for facility fee rates that range from 12.5 basis points to 30 basis points per year depending upon our credit rating, (ii) includes sub-facilities for short-term loans and letters of credit up to an aggregate amount of $500 million under each sub-facility and (iii) 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.


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





Note 7.  Fair Value Measurements and Disclosures


Assets and Liabilities Measured at Fair Value on a Recurring Basis


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


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


Mutual Fund Investments Our mutual fund investments, 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 may include: variable to fixed price commodity swaps, two-way collars, and/or three-way collars. 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 and the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract terms.  See Note 5. Derivative Instruments and Hedging Activities .


Deferred Compensation Liability The value is dependent upon the fair values of mutual fund investments and shares of our common stock held in a rabbi trust.  See Mutual Fund Investments above .


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 Notes to Consolidated Financial Statements


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


Fair Value Measurements UsingQuoted Prices inActive Markets(Level 1)(1)Significant OtherObservable Inputs(Level 2)(2)SignificantUnobservableInputs   (Level 3)(3)Adjustment(4)Fair Value Measurement(millions)June 30, 2014Financial AssetsMutual Fund Investments$121$—$—$—$121Commodity Derivative Instruments—11—(9)2Financial LiabilitiesCommodity Derivative Instruments—(297)—9(288)Portion of Deferred Compensation Liability Measured at Fair Value(194)———(194)December 31, 2013Financial AssetsMutual Fund Investments$114$—$—$—$114Commodity Derivative Instruments—28—(11)17Financial LiabilitiesCommodity Derivative Instruments—(86)—11(75)Portion of Deferred Compensation Liability Measured at Fair Value(176)———(176)





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|(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.

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

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

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

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis


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


Asset Impairments Information about impaired assets is as follows: Fair Value Measurements UsingDescriptionQuoted Prices in Active Markets (Level 1)Significant Other Observable Inputs (Level 2)Significant Unobservable Inputs (Level 3)Net Book Value(1)Total Pre-tax (Non-cash) Impairment LossmillionsThree Months Ended June 30, 2014Impaired Oil and Gas Properties$—$—$8$42$34Three Months Ended June 30, 2013Impaired Oil and Gas Properties—————Six Months Ended June 30, 2014Impaired Oil and Gas Properties$—$—$14$145$131Six Months Ended June 30, 2013Impaired Oil and Gas Properties—————


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


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 Noble Energy, Inc.
 Notes to Consolidated Financial Statements


The fair value of impaired oil and gas properties was determined as of the date of the assessment using a discounted cash flow model based on management’s expectations of future crude oil and natural gas production prior to abandonment date, commodity prices based on NYMEX WTI, NYMEX Henry Hub, and Brent future price curves as of the date of the estimate, estimated operating and abandonment costs, and a risk-adjusted discount rate of 10% .  First and second quarter 2014 impairments were due to increases in asset carrying values associated with increases in asset retirement obligations (ARO). ARO increases were due to higher cost and change in timing of abandonment activities.  See Note 4. Asset Impairments .


Additional Fair Value Disclosures


Debt The fair value of public, fixed-rate 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 amount of our Credit Facility at June 30, 2014 approximates fair value because the interest rate paid on such debt is set for periods of three months or less. As such, we consider the fair values of our Credit Facility to be a Level 2 measurement on the fair value hierarchy. See Note 6. Debt .


Fair value information regarding our debt is as follows: June 30, 2014December 31, 2013(millions)Carrying AmountFair ValueCarrying AmountFair ValueTotal Debt, Net of Unamortized Discount(1)$4,866$5,617$4,465$4,959


|    |                                              
|--- | ---------------------------------------------
|(1) | Excludes capital lease and other obligations.




Note 8.  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 charged to exploration expense as dry hole cost.


Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the same period: (millions)Six Months Ended June 30, 2014Capitalized Exploratory Well Costs, Beginning of Period$1,301Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves195Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves or to Assets Held for Sale(80)Capitalized Exploratory Well Costs Charged to Expense(2)Capitalized Exploratory Well Costs, End of Period$1,414





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


(millions)June 30, 2014December 31, 2013Exploratory Well Costs Capitalized for a Period of One Year or Less$517$568Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling897733Balance at End of Period$1,414$1,301Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling1313





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 Noble Energy, Inc.
 Notes to Consolidated Financial Statements


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 June 30, 2014 : Suspended Since(millions)Total2012 - 20132010 - 20112009 & PriorProgressCountry/Project:Offshore Equatorial GuineaDiega (including Carmen)$111$6$52$53Evaluating regional development scenarios for this 2008 crude oil discoveryCarla14913712—Evaluating regional development scenarios for this 2011 crude oil discoveryFelicita383629Evaluating regional development plans for this 2008 condensate and natural gas discoveryYolanda192314Evaluating regional development plans for this 2007 condensate and natural gas discoveryOffshore CameroonYoYo463934Working with the government to assess commercialization of this 2007 condensate and natural gas discoveryOffshore IsraelLeviathan18070110—Targeting to sanction initial phase of development for this 2010 natural gas discovery by early 2015Leviathan-1 Deep764927—Well did not reach the target interval; we are developing future drilling plans to test this deep oil conceptDalit253220Submitted a development plan to the government to develop this 2009 natural gas discovery as a tie-in to existing infrastructureDolphin 124222—Reviewing regional development scenarios for this 2011 natural gas discoveryOffshore CyprusCyprus1095257—Submitted an appraisal plan to the Cyprus government to develop this 2011 natural gas discovery; planning additional appraisal activities including interpretation of seismic dataFalkland IslandsScotia7171——Analyzing recently acquired seismic dataOtherProjects less than $20 million493946Continuing to drill and evaluate appraisal wellsTotal$897$437$304$156


Note 9.  Asset Retirement Obligations


ARO consists primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Changes in ARO are as follows: Six Months EndedJune 30,(millions)20142013Asset Retirement Obligations, Beginning Balance$586$402Liabilities Incurred222Liabilities Settled(43)(10)Revision of Estimate1207Accretion Expense(1)1914Asset Retirement Obligations, Ending Balance$704$415


(1) Accretion expense is included in DD&A  expense in the consolidated statements of  operations.


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 Noble Energy, Inc.
 Notes to Consolidated Financial Statements


For the six months ended June 30, 2014


Liabilities incurred were due to new wells and facilities and included $13 million for onshore US and $9 million for Eastern Mediterranean.


Liabilities settled primarily related to onshore US property abandonments and non-core, onshore US assets sold.


Revisions were primarily due to an increase of $67 million related to a non-operated North Sea field due to an increase in costs and a change in timing recorded during the first quarter of 2014.  See Note 4. Asset Impairments .  Additional revisions were due to changes in cost and timing estimates and primarily included $21 million for DJ Basin, $16 million for Equatorial Guinea, $9 million for Eastern Mediterranean, and $7 million for deepwater Gulf of Mexico.


For the six months ended June 30, 2013


Liabilities incurred were due to new wells and facilities for onshore development.  Liabilities settled in 2013 relate primarily to non-core onshore US properties that were sold. See Note 3. Divestitures .





Note 10.  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 EndedJune 30,Six Months EndedJune 30,(millions, except per share amounts)2014201320142013Income from Continuing Operations$192$358$392$590Weighted Average Number of Shares Outstanding, Basic361359361358Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust5444Weighted Average Number of Shares Outstanding, Diluted366363365362Earnings from Continuing Operations Per Share, Basic$0.53$1.00$1.09$1.64Earnings from Continuing Operations Per Share, Diluted0.520.991.071.63Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above3545





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 Noble Energy, Inc.
 Notes to Consolidated Financial Statements


Note 11.  Income Taxes


The income tax provision relating to continuing operations consists of the following:


Three Months EndedJune 30,Six Months EndedJune 30,(millions)2014201320142013Current$34$71$94$108Deferred75724106Total Income Tax Provision$41$128$118$214Effective Tax Rate17.6%26.4%23.1%26.6%





Our effective tax rate (ETR) for the three months and six months ended June 30, 2014 decreased as compared with the three and six months ended June 30, 2013 primarily due to our ability to benefit from previously unrecognized foreign tax credits, increased earnings in our foreign jurisdictions with rates that vary from the US statutory rate and a decrease in our Israeli oil profits tax.


In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US – 2010 , Equatorial Guinea – 2008 and Israel – 2009 .


See Note 3. Divestitures for income taxes associated with discontinued operations.


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 Noble Energy, Inc.
 Notes to Consolidated Financial Statements





Note 12.  Segment Information


We have operations throughout the world and manage our operations by country. The following information is grouped into four components that are all in the business of crude oil and natural gas exploration, development, production, and acquisition: the United States; West Africa (Equatorial Guinea, Cameroon, and Sierra Leone); Eastern Mediterranean (Israel and Cyprus); and Other International and Corporate. Other International includes China, the North Sea, Falkland Islands, Nicaragua and new ventures. The North Sea geographical segment is included in continuing operations in 2014 and discontinued operations in 2013. (millions)ConsolidatedUnitedStatesWestAfricaEasternMediterraneanOther Int'l &CorporateThree Months Ended June 30, 2014Revenues from Third Parties$1,338$842$339$113$44Income from Equity Method Investees45—45——Total Revenues1,38384238411344DD&A413311721515Gain on Divestitures(44)(8)——(36)Asset Impairments3418—142Income (Loss) from Continuing Operations Before Income Taxes23319920444(214)Three Months Ended June 30, 2013Revenues from Third Parties$1,112$683$290$101$38Income from Equity Method Investees37—37——Total Revenues1,14968332710138DD&A368258632720Loss on Divestitures4—4——Asset Impairments—————Income (Loss) from Continuing Operations Before Income Taxes48632026844(146)Six Months Ended June 30, 2014Revenues from Third Parties$2,665$1,684$662$225$94Income from Equity Method Investees97—97——Total Revenues2,7621,68475922594DD&A8376191482941Gain on Divestitures(42)(6)——(36)Asset Impairments13123—1494Income (Loss) from Continuing Operations Before Income Taxes510382465121(458)Six Months Ended June 30, 2013Revenues from Third Parties$2,196$1,399$563$152$82Income from Equity Method Investees96—96——Total Revenues2,2921,39965915282DD&A7345241175538Gain on Divestitures(12)(12)———Asset Impairments—————Income (Loss) from Continuing Operations Before Income Taxes80456349959(317)June 30, 2014Total Assets$20,575$14,175$3,152$2,762$486December 31, 2013Total Assets19,59813,0943,1992,753552








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 Noble Energy, Inc.
 Notes to Consolidated Financial Statements


Note 13.  Commitments and Contingencies


CONSOL Carried Cost Obligation In accordance with our Marcellus Shale joint venture arrangement with a subsidiary of CONSOL Energy Inc. (CONSOL), we agreed to fund one-third of CONSOL's 50% working interest share of future drilling and completion costs, capped at $400 million each year, up to approximately $2.1 billion (CONSOL Carried Cost Obligation).


The CONSOL Carried Cost Obligation is suspended if average Henry Hub natural gas prices fall and remain below $4.00 per MMBtu in any three consecutive month period and remain suspended until average Henry Hub natural gas prices are above $4.00 per MMBtu for three consecutive months. Due to low natural gas prices, the CONSOL Carried Cost Obligation was suspended from the end of 2011 until February 28, 2014. Due to recent increases in Henry Hub natural gas prices, we began funding a portion of CONSOL's working interest share of certain drilling and completion costs as of March 1, 2014. Based on the June 30, 2014 NYMEX Henry Hub natural gas price curve and current development plans, we forecast we will incur approximately $240 million under the CONSOL Carried Cost Obligation for the year ended December 31, 2014.


Marcellus Shale Firm Transportation Agreements In February 2014, we signed Precedent Agreements for Firm Transportation (the Agreements) to flow 150,000 MMBtu per day of our Marcellus Shale natural gas production to Gulf Coast markets. The Agreements, which are expected to be executed in the second half of 2014, are for transportation services on new pipeline extensions, to be constructed by, and connecting to, an existing third-party system. The pipeline extensions are expected to be complete and operational in June of 2017. Our financial commitment totals approximately $765 million , undiscounted, over a 15 -year period. The Agreements are subject to various conditions, including regulatory approval of the pipeline extension projects.


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.











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





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





|  |                    
|- | -------------------
|• | Executive Overview;

|  |                   
|- | ------------------
|• | Operating Outlook;

|  |                           
|- | --------------------------
|• | Results of Operations; and

|  |                                 
|- | --------------------------------
|• | Liquidity and Capital Resources.




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





EXECUTIVE OVERVIEW


We are a worldwide explorer and producer of crude oil, natural gas and natural gas liquids. We aim to achieve sustainable growth in value and cash flow through exploration success and the development of a high-quality, diversified, portfolio of assets with investment flexibility between: onshore unconventional developments and offshore organic exploration leading to major development projects; US and international development projects; and production mix among crude oil, natural gas, and NGLs. We currently focus our efforts in five core operating areas: the DJ Basin and Marcellus Shale (onshore US), deepwater Gulf of Mexico, offshore West Africa, and offshore Eastern Mediterranean, where we have strategic competitive advantage and which we believe generate superior returns. We also seek to enter potential new core areas, and we are currently conducting exploration activities in domestic and international locations such as Northeast Nevada, the Falkland Islands, Cameroon, and Cyprus.


Our financial results for second quarter 2014 included:


|  |                                                                           
|- | --------------------------------------------------------------------------
|• | net income of$192 millionas compared with$377 millionforsecondquarter2013;

|  |                                                                                                                                                                                                                                                    
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|• | losson commodity derivative instruments of$236 million(including$187 millionnon-cash portion ofloss) as compared with a gain on commodity derivative instruments of$161 million(including$159 millionnon-cash portion ofgain) forsecondquarter2013;

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|• | asset impairment charges of$34 million, as compared withzeroforsecondquarter 2013;

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|- | ------------------------------------------------------------------------------
|• | diluted earnings per share of$0.52, as compared with$1.04forsecondquarter2013;

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|- | ------------------------------------------------------------------------------------------------------------
|• | cash flow provided by operating activities of$828 million, as compared with$539 millionforsecondquarter2013;

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|- | ------------------------------------------------------------------------------------
|• | ending cash balance of$958 million, as compared with$1.1 billionatDecember 31, 2013;

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|- | --------------------------------------------------------------------------------------
|• | capital spending, on a cash basis, of$1.2 billionfor both thesecondquarter2013and2014;

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|- | ----------------------------------------
|• | gain of $35 million on China asset sale;

|  |                                                      
|- | -----------------------------------------------------
|• | repayment of $200 million senior notes in April 2014;

|  |                                                                                                    
|- | ---------------------------------------------------------------------------------------------------
|• | total liquidity of$4.4 billionatJune 30, 2014, as compared with$5.1 billionatDecember 31, 2013; and

|  |                                                                                              
|- | ---------------------------------------------------------------------------------------------
|• | ratio of debt-to-book capital of35%atJune 30, 2014, as compared with 35% atDecember 31, 2013.

Our operating results for second quarter 2014 included:


|  |                                                                                                                                         
|- | ----------------------------------------------------------------------------------------------------------------------------------------
|• | delivered record horizontal production of 112 MBoe/d from the DJ Basin and Marcellus Shale, 56% higher than second quarter of last year;

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|- | -------------------------------------------------------------------------------------------
|• | increased wet gas type curves 10% for wells in the Majorsville area of the Marcellus Shale;

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|- | -------------------------------------------------------------------------------------------------------------------------------------
|• | announced plans to form a master limited partnership (MLP) with CONSOL for our jointly owned midstream assets in the Marcellus Shale;

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|- | ------------------------------------------------------------------------------------------
|• | exploration discovery made at the Katmai prospect located in the deepwater Gulf of Mexico;

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|• | acquired interest in 17 exploration lease blocks in the Atwater Valley area of the Gulf of Mexico and spud initial prospect, Bright;

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|- | ---------------------------------------------------------------------------------------------------------------------------
|• | increased Leviathan resource estimate as the result of additional information from the ongoing Leviathan appraisal program;

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|- | ---------------------------------------------------------------------------------------------
|• | signed two regional export Letters of Intent for natural gas sales to customers in Egypt; and

|  |                                                             
|- | ------------------------------------------------------------
|• | closed China asset sale, receiving $186 million in proceeds.

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Exploration Program Update


We have numerous exploration opportunities remaining in our core areas and are also engaged in new venture activity in both our US and international locations.


We were in the process of drilling and/or evaluating significant exploratory wells at June 30, 2014 ( See Item 1. Financial Statements – Note 8. Capitalized Exploratory Well Costs ), and expect to continue an active exploratory drilling program in the future.


A portion of our 2014 capital investment program is dedicated to exploration and associated appraisal activities, including leasehold acquisitions. However, we do not always encounter hydrocarbons through our drilling activities. In addition, we may find hydrocarbons but subsequently reach a decision, through additional analysis or appraisal drilling, that a development project is not economically or operationally viable.


In the event we conclude that one of our exploratory wells did not encounter hydrocarbons or that a discovery is not economically or operationally viable, the associated capitalized exploratory well costs would be charged to expense.  Additionally, we may not be able to conduct exploration activities prior to lease expirations. As a result, in a future period, dry hole cost and/or leasehold abandonment expense could be significant. See Operating Outlook – Potential for Future Asset Impairment, Dry Hole or Lease Abandonment Expense, below.


Updates on significant exploration activities are as follows:


Northeast Nevada We are currently analyzing results from our first exploratory vertical well and conducting a long term production test.  We plan to drill additional exploratory wells later in 2014.


Deepwater Gulf of Mexico During second quarter 2014, we acquired working interests in 17 deepwater exploration leases in the Gulf of Mexico. Each of the leases resides in the Atwater Valley protraction area. We acquired a 50% working interest in 13 leases and an average 26% working interest in four leases.


As part of the transaction, we are participating with a 50% non-operated working interest in the Bright prospect, which is currently being drilled on Atwater Valley Block 362 in a water depth of approximately 5,600 feet. The initial exploratory well, targeting multiple reservoirs, is anticipated to be drilled to a total depth of 13,500 feet. In addition to the Bright prospect, there are multiple follow-on exploration opportunities that have been identified on these newly acquired leases.


We are also currently drilling the Katmai exploratory well (Green Canyon Block 40, 50% operated working interest) in water depth of approximately 2,100 feet.  We recently announced a commercial crude oil discovery at Katmai, and expect to reach a total depth of 28,300 feet during the third quarter of 2014.


Offshore West Africa We are currently acquiring 3D seismic data across Blocks O and I, offshore Equatorial Guinea, and may potentially drill an exploratory well offshore Cameroon in the fourth quarter of 2014. Additionally, we are reprocessing 3D seismic data over our YoYo mining concession, offshore Cameroon.


Offshore Eastern Mediterranean We are processing and evaluating recently acquired 3D seismic data over offshore Israel and Cyprus and continue to study locations for potential exploratory wells, with opportunities offshore in both Israel and Cyprus.


Offshore Falkland Islands We continue to process and evaluate 3D seismic data over the northern and southern areas and prepare for our first operated exploratory well planned for 2015.


Major Development Project Updates


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


Sanctioned Ongoing Development Projects


A "sanctioned" development project is one for which a final investment decision has been made.


DJ Basin (Onshore US) We continue to operate at a high level of horizontal drilling activity with continued growth from strong well performance, new wells brought online, and expanded natural gas and crude oil infrastructure. We have accelerated our extended reach lateral well program to approximately 30% of our wells to be drilled in 2014. During the quarter, we spud 80 horizontal wells, of which 27 were extended reach lateral wells, and 85 wells initiated production. Our 2014 drilling program includes over 90 extended reach lateral wells. Currently, 10 drilling rigs are active across the basin.


Marcellus Shale (Onshore US) We continue to delineate the wet gas acreage, while our partner, CONSOL Energy, Inc. (CONSOL), continues to develop the dry gas acreage. During the quarter, we and our partner drilled 48 wells, and 35 wells initiated production. The joint venture is currently operating ten drilling rigs.


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Due to an increase in Henry Hub natural gas prices, our funding of certain drilling and completion costs under the CONSOL Carried Cost Obligation commenced as of March 1, 2014. See Liquidity and Capital Resources – Contractual Obligations below.


In June 2014, we and our joint venture partner, CONSOL, submitted a confidential draft Registration Statement on Form S-1 to the U.S. Securities and Exchange Commission relating to a proposed master limited partnership (MLP). The MLP will own, operate, and develop our jointly-owned natural gas midstream assets in the Marcellus Shale.


Gunflint (Deepwater Gulf of Mexico) In 2013, we sanctioned the development plan for the 2008 Gunflint crude oil discovery, utilizing a subsea tieback to an existing host facility, and are targeting first production in 2016.


Big Bend (Deepwater Gulf of Mexico) The 2012 Big Bend crude oil discovery is located in the Rio Grande area of the deepwater Gulf of Mexico. In October 2013, we sanctioned a development plan, utilizing a subsea tieback to a third party host facility. First production is targeted for late 2015.


Tamar Expansion (Offshore Israel) The Tamar compression project, which is expected to increase capacity by 200 MMcf/d at the Ashdod onshore terminal, is progressing, and we expect operational start-up in the second half of 2015.


We are continuing to work with the Israeli government to obtain regulatory approval of our development plan for the Tamar Southwest discovery, which is intended to utilize current Tamar infrastructure. Continuing delays in securing regulatory approvals have placed the project at risk of delay. We have petitioned the Israeli courts to expedite the needed approvals. Timely development of Tamar Southwest is important to provide future flow rate assurance for our overall Tamar project.


In May 2014, we announced that we had entered into a non-binding Letter of Intent (LOI) for the supply of natural gas from the Tamar field to existing natural gas liquefaction (LNG) facilities in Egypt.


Unsanctioned Development Projects (As of June 30, 2014)


Dantzler (Deepwater Gulf of Mexico) The 2013 Dantzler crude oil discovery is located in the Rio Grande area of the deepwater Gulf of Mexico and is a co-development opportunity with Big Bend.  During the second quarter, we spud the first Dantzler appraisal well (45% operated working interest) and expect drilling results during the third quarter of 2014.


Leviathan (Offshore Israel) In the first half of 2014, we made significant progress on the development of the Leviathan field, following approval of Israel's natural gas export policy, an agreement with Israel's Anti-trust Authority, and receipt of the Development and Production Leases for Leviathan.


In May 2014, we announced that the existing Leviathan partners terminated the non-binding memorandum of understanding regarding the sale of interest in the Leviathan licenses to Woodside Petroleum.


The initial phase of the Leviathan project is designed to provide significant quantities of natural gas to Israel and regional markets. In June 2014, we announced that we had entered into a non-binding LOI for the supply of natural gas from the Leviathan field to existing LNG facilities in Egypt.


We are currently considering various project finance options for Leviathan. Sanctioning of the initial phase of development at Leviathan is targeted by the end of 2014 or early 2015, with first production from the field currently planned for the end of 2017 or early 2018.


See also Update on Israel's Natural Gas Economy, below.


Cyprus Project (Offshore Cyprus) We are planning additional appraisal activities, including interpretation of seismic data and spudding another well to further determine the ultimate recoverable resources on Block 12 and optimize field development planning. In addition, our application for renewal of the production sharing contract for two additional years was approved in May 2014.


Diega and Carla (Offshore Equatorial Guinea) We are currently evaluating regional development scenarios for Diega and Carla and targeting to sanction a Diega development project in 2015.


See Item 1. Financial Statements – Note 8. Capitalized Exploratory Well Costs for additional information on costs incurred related to these projects.


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Non-Core Divestiture Program


We have continued our non-core asset divestiture program with the sale of our China assets on June 30, 2014.  Sales of certain smaller onshore US property packages were completed during the first six months of 2014 or are expected to be completed this year. Divestitures of non-core properties allow us to allocate capital and human resources to high-value and high-growth areas. See Item 1. Financial Statements – Note 3. Divestitures  and Operating Outlook - Potential for Future Asset Impairment, Dry Hole or Lease Abandonment Expense, below.


We are currently winding up local business activities in countries of former operations.  At this time, we do not believe that any of the activities associated with these areas will have a material effect on our financial position, results of operations or cash flows.


Update on Israel's Natural Gas Economy


Israel Antitrust Authority During 2014, we and our partners reached an agreement with the Israeli government on various antitrust matters. As a result of the agreement, we will divest two natural gas discoveries. We have initiated an active program to locate a buyer and other actions required to complete the plan to sell the assets. The assets are reported within assets held for sale in our consolidated balance sheet at June 30, 2014.


The agreement also granted the rights, to us and our partners, to jointly market natural gas from the Leviathan field. As a result, we plan to further our domestic natural gas marketing activities. The agreement is subject to final approval by the Israeli government.


On March 26, 2014, the Israel Ministry of Finance (Ministry) issued a memorandum indicating its intent to amend the Petroleum Profits Law in light of the Israeli government's 2013 decision to permit the export of natural gas from Israel.  The purpose of the proposed amendments is mainly to regulate the method of taxing petroleum export transactions, and, in particular, exports of natural gas.  As a part of the Ministry's draft recommendation, several methodologies could be used to establish the transfer price for natural gas sales, depending on various circumstances.  We are currently evaluating the recommendation and proposed amendments.


The recent Israel-Gaza conflict has resulted in loss of life and destruction of property. See our Annual Report on Form 10-K for the year ended December 31, 2013 - Item 1A. Risk Factors - Our operations may be adversely affected by violent acts such as from civil disturbances, terrorist acts, regime changes, cross-border violence, war, piracy, or other conflicts that may occur in regions that encompass our operations.


Update on Hydraulic Fracturing


Potential Rulemaking Although hydraulic fracturing is regulated primarily at the state level, governments and agencies at all levels from federal to municipal are conducting studies and considering regulations, and some have proposed rules.


A measure to ban hydraulic fracturing was on the ballot in the City of Loveland in northern Colorado in June of 2014. Industry worked with the community to defeat that initiative.  Also during 2014, we have been actively campaigning against statewide ballot initiatives that would unreasonably restrict or limit crude oil and natural gas development in Colorado.  There are currently two remaining initiatives that have survived titling and Supreme Court review and are in a position to collect sufficient signatures to be placed on the November 2014 ballot.  These are:


|  |                                                                                                
|- | -----------------------------------------------------------------------------------------------
|• | an initiative to amend the state constitution to establish an environmental bill of rights; and

|  |                                                                                                                                                                         
|- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | an initiative to amend the state constitution to impose a 2000-foot statewide drilling setback from occupied structures, unless a waiver is obtained from the landowner.

Petitioners have until August 4, 2014 to gather 86,105 verified signatures and we will work with the State of Colorado to ensure any signatures submitted on these initiatives are properly verified. The ultimate passage and implementation of one or both of these initiatives could have a negative impact on our business.  In particular, a statewide drilling setback will likely delay or otherwise limit our drilling and development activities in certain parts of the DJ Basin. This could result in a reduction in our proved reserves and negatively impact our results of operations, cash flows, and stock price.


In Nevada, state regulators are in the process of promulgating rules to govern hydraulic fracturing and new crude oil and natural gas development.  We have actively participated in that process and do not believe it will have a material impact on our activities.  We will continue to monitor new and proposed legislation and regulations to assess the potential impact on our operations.


Concurrently, we are engaged in extensive public education and outreach efforts with the goal of engaging and educating the general public about the energy, economic and environmental benefits of safe and responsible crude oil and natural gas development.


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Regulations


On February 23, 2014, the Colorado Air Quality Control Commission (Commission) adopted a number of revisions to its oil and gas industry regulations.  The revisions include the full adoption of US Environmental Protection Agency's Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution (also known as NSPS Quad O) with corresponding complementary control measures.  The control measures set forth requirements for identifying and repairing leaks, undertaking record keeping, and submitting reports.  The revisions also include the first ever regulation of methane emissions from the industry.  In collaboration with the Environmental Defense Fund and other oil and gas operators, we provided testimony and evidence to the Commission in support of the adopted revisions. The adopted revised regulations were published in the Colorado Register on March 25, 2014, Volume 37, No. 6, and are effective as of April 14, 2014. Copies of these regulations are available at http://www.sos.state.co.us/CCR.  We do not currently believe costs incurred to implement these regulations will be material to our earnings or cash flows.


Sales Volumes


The execution of our strategy has delivered a diversified production growth most recently due to our Tamar natural gas field and Alen condensate project coming online in 2013 along with accelerated activity in onshore US unconventional developments. On a BOE basis, total sales volumes were 11%  higher for the second quarter of 2014 as compared with the second quarter of 2013 , and our mix of sales volumes was 46% global liquids, 27% international natural gas, and 27% US natural gas. See Results of Operations – Revenues, below.


Commodity Price Changes


Average realized natural gas prices increased 5% in the US and 13% in Israel for second quarter of 2014 as compared with the second quarter of 2013 . Average realized crude oil prices increased 5% in the US and 7% in Equatorial Guinea for the second quarter of 2014 as compared with the second quarter of 2013 .


Recently Issued Accounting Standards


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


OPERATING OUTLOOK


2014 Production Our expected crude oil, natural gas and NGL production for 2014 may be impacted by several factors including:


|  |                                                                   
|- | ------------------------------------------------------------------
|• | changes to drilling plans in the DJ Basin and the Marcellus Shale;

|  |                                                                                                                                                                               
|- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | Israeli demand for electricity, which affects demand for natural gas as fuel for power generation and industrial market growth, and which is impacted by unseasonable weather;

|  |                                                                                                                                                                       
|- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | potential downtime at key assets including: Galapagos and Swordfish, deepwater Gulf of Mexico; Tamar, offshore Israel; and Aseng and Alen, offshore Equatorial Guinea;

|  |                                                                                                                    
|- | -------------------------------------------------------------------------------------------------------------------
|• | natural field decline in the deepwater Gulf of Mexico and the Alba and Aseng fields offshore Equatorial Guinea; and

|  |                                                                                                                                        
|- | ---------------------------------------------------------------------------------------------------------------------------------------
|• | potential weather-related volume curtailments due to hurricanes in the deepwater Gulf of Mexico which can shut-in or reduce production.

2014 Capital Investment Program Total capital expenditures are estimated at $4.8 to $5.0 billion for 2014. We expect to invest approximately 70% of the program in onshore US development and approximately 30% of the program in global deepwater activities.


The 2014 capital investment program is estimated to exceed operating cash flows and is expected to be funded from cash flows from operations, cash on hand, and borrowings under our unsecured revolving credit facility (Credit Facility) and/or other financing. Funding may also be provided by proceeds from divestment of non-core assets or farm-out of working interests in exploration prospects. See Liquidity and Capital Resources – Financing Activities.


We will continue to evaluate the level of capital spending and remain flexible throughout the year.  For further discussion, see Executive Overview – Update on Hydraulic Fracturing, above, regarding potential legislative or regulatory changes in the use of hydraulic fracturing, and Liquidity and Capital Resources – Contractual Obligations , below, regarding the CONSOL Carried Cost Obligation.


Potential for Future Asset Impairment, Dry Hole or Lease Abandonment Expense


Exploration Activities We have an active exploratory drilling program. In the event we conclude that an exploratory well did not encounter hydrocarbons or that a discovery is not economically or operationally viable, the associated capitalized exploratory well costs would be charged to expense. For example, in the Falkland Islands we are processing recently acquired seismic data.  We will conduct seismic interpretation and basin modeling during the remainder of 2014 in order to determine our future drilling program. Integration of seismic information with the results of the Scotia exploratory well will allow us to assess the economic viability of this prospect.  If we were to determine, based on the results of seismic interpretation and/or


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additional drilling activities, that the Scotia prospect is not economically viable, the costs we have incurred (approximately $73 million to date) would be written off to dry hole expense.


Additionally, we may not conduct exploration activities prior to lease expirations. For example, in the deepwater Gulf of Mexico, while we continue to mature our prospect portfolio, regulations have become more stringent due to the Deepwater Horizon incident in 2010. In some instances, specifically engineered blowout preventers, rigs, and completion equipment may be required for high pressure environments. Regulatory requirements or lack of readily available equipment could prevent us from engaging in future exploration activities during our current lease terms.


One particular deepwater Gulf of Mexico lease, which we acquired under regulations in effect prior to the Deepwater Gulf of Mexico Moratorium, is set to expire on July 31, 2014. We  have been working to mature this prospect by conducting various activities, including the licensing and processing of 3-D seismic data and interpretation of geophysical information, which have resulted in the identification of a potential hydrocarbon-bearing formation below 25,000 feet. We reviewed the criteria for a lease suspension of operations (SOO), which may be granted by regulatory authorities, and believe we satisfy each of the required conditions. We submitted an application for the SOO, evidencing satisfaction of the required conditions, on July 7, 2014.  If an SOO is granted, we intend to continue processing of subsalt imaging and developing an exploration plan, targeting a 2017 exploratory well spud date.  Although we believe we have satisfied the required conditions for the SOO, there is no certainty an extension will be obtained prior to the lease expiration. The lease had a net book value of approximately $41 million at June 30, 2014. If we are unable to obtain an extension, we must relinquish the lease, abandon our exploration plans, and write off the book value to exploration expense.


Producing Properties Commodity prices remain volatile. A decline in future crude oil or natural gas prices could result in impairment charges. 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 along with operating and development costs, market outlook on forward commodity prices, and interest rates. All inputs to the cash flow model must be evaluated at each date of estimate. However, a decrease in forward crude oil or natural gas prices alone could result in an impairment.


Occasionally, well mechanical problems arise, which can reduce production and potentially result in reductions in proved reserves estimates. For example, our South Raton development in the deepwater Gulf of Mexico has been shut-in due to mechanical issues.  We have conducted remediation work; however, return to production has been delayed due to work being performed at the non-operated host facility. We expect to begin producing later in third quarter 2014.  No impairment is currently indicated; however, we will monitor production and reserves when South Raton is brought back online and continue to assess the field for possible impairment. South Raton had a net book value of approximately $123 million at June 30, 2014 .


In addition, well decommissioning programs, especially in deepwater or remote locations, are often complex and expensive. It may be difficult to estimate timing of actual abandonment activities, which are subject to regulatory approval and the availability of rigs and services. It may be difficult to estimate costs as rigs and services become more expensive in periods of higher demand. Therefore, our ARO estimates may change, sometimes significantly, and could result in asset impairment.


Divestments We are currently marketing certain non-core onshore US properties, including our assets in the Piceance Basin of western Colorado. If properties are reclassified as assets held for sale in the future, they will be valued at the lower of net book value or anticipated sales proceeds less costs to sell. Impairment expense would be recorded for any excess of net book value over anticipated sales proceeds less costs to sell. In addition, we would allocate a portion of goodwill to any non-core onshore US property held for sale that constitutes a business, which could potentially decrease any gain or increase any loss recorded on the sale.


In addition, certain assets offshore Israel were classified as held for sale at June 30, 2014. No impairments are indicated at this time. However, failure to achieve acceptable sale terms or delays in closing sales of these properties could result in impairment and/or loss on sale.


Potential Change in Pennsylvania Tax Structure  The State of Pennsylvania has been addressing a potential budget deficit. As a result, Pennsylvania lawmakers have been considering various alternatives for generating additional revenues, including additional taxes on crude oil and natural gas production. Additional taxes could be in the form of a severance tax, which would be assessed on the value of the natural gas produced. A severance tax, if imposed, may or may not replace the current local impact fee, which is assessed on a per well basis at a rate determined primarily by the age of the well, under a law signed in 2012.


We are currently unable to predict whether a severance tax will be imposed by the State of Pennsylvania. However, additional taxes on our crude oil, condensate or natural gas production could have a negative impact on our results of operations and cash flows.





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RESULTS OF OPERATIONS


In the discussion below, the North Sea geographical segment is reflected as discontinued operations for the first six months of 2013. During first quarter 2014, the remaining unsold North Sea assets were reclassified to held and used, and their operations are included in continuing operations for 2014. See also Discontinued Operations, below.


Revenues


Revenues were as follows: Increase/(Decrease)from Prior Year(millions)20142013Three Months Ended June 30,Oil, Gas and NGL Sales$1,338$1,11220%Income from Equity Method Investees453722%Total$1,383$1,14920%Six Months Ended June 30,Oil, Gas and NGL Sales$2,665$2,19621%Income from Equity Method Investees97961%Total$2,762$2,29221%


Changes in revenues are discussed below.


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Oil, Gas and NGL Sales  Average daily sales volumes and average realized sales prices were as follows: Sales VolumesAverage Realized Sales PricesCrude Oil & Condensate(MBbl/d)NaturalGas(MMcf/d)NGLs(MBbl/d)Total(MBoe/d)(1)Crude Oil & Condensate(Per Bbl)NaturalGas(Per Mcf)NGLs(Per Bbl)Three Months Ended June 30, 2014United States6546922166$99.39$4.24$34.66Equatorial Guinea(2)34248—75108.080.27—Israel—218—37—5.57—Other International(3)5——5104.70——Total Consolidated Operations10493522283102.533.5034.66Equity Investees(4)2—67108.31—64.86Total Continuing Operations10693528290$102.62$3.50$40.70Three Months Ended June 30, 2013United States5840415140$94.29$4.04$30.05Equatorial Guinea(2)31252—73101.440.27—Israel—220—37—4.92—Other International(3)4——497.92——Total Consolidated Operations938761525496.843.1830.05Equity Investees(4)1—5699.48—62.93Total Continuing Operations9487620260$96.87$3.18$38.48Six Months Ended June 30, 2014United States6547620165$98.22$4.52$39.10Equatorial Guinea(2)34245—74106.920.27—Israel—218—37—5.59—Other International(3)5——5104.48——Total Consolidated Operations10493920281101.393.6639.10Equity Investees(4)2—67106.50—69.70Total Continuing Operations10693926288$101.47$3.66$45.71Six Months Ended June 30, 2013United States6040615143$95.02$3.68$34.63Equatorial Guinea(2)29249—70106.200.27—Israel—166—28—5.00—Other International(3)4——4103.66——Total Consolidated Operations938211524598.872.9134.63Equity Investees(4)2—68105.38—69.03Total Continuing Operations9582121253$98.98$2.91$44.02


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

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|    |                                                                                                                                                                                                                                                                                           
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(2) | Natural gas from the Alba field in Equatorial Guinea is under contract for $0.25 per MMBtu to a methanol plant, an LPG plant, an LNG plant and a power generation plant. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method of accounting.

|    |                                              
|--- | ---------------------------------------------
|(3) | Other International includes primarily China.

|    |                                                                                                                                      
|--- | -------------------------------------------------------------------------------------------------------------------------------------
|(4) | Volumes represent sales of condensate and LPG from the Alba plant in Equatorial Guinea. SeeIncome from Equity Method Investees,below.

An analysis of revenues from sales of crude oil, natural gas and NGLs is as follows: Sales Revenues(millions)Crude Oil & CondensateNaturalGasNGLsTotalThree Months Ended June 30, 2013$817$253$42$1,112Changes due toIncrease in Sales Volumes1001719136Increase in Sales Prices5427990Three Months Ended June 30, 2014$971$297$70$1,338Six Months Ended June 30, 2013$1,667$432$97$2,196Changes due toIncrease in Sales Volumes1866230278Increase in Sales Prices4612817191Six Months Ended June 30, 2014$1,899$622$144$2,665


Crude Oil and Condensate Sales – Revenues from crude oil and condensate sales increased during second quarter and first six months of 2014 as compared with 2013 due to the following:


|  |                                                                                      
|- | -------------------------------------------------------------------------------------
|• | higher sales volumes in the DJ Basin attributable to our horizontal drilling program;

|  |                                                                                                                                                                                                     
|- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | additional sales volumes from the Alen condensate project, offshore Equatorial Guinea, which began producing in late second quarter 2013 and averaged 11 MBoe/d during the first six months of 2014;

|  |                                                                                                                                           
|- | ------------------------------------------------------------------------------------------------------------------------------------------
|• | higher sales volumes from the deepwater Gulf of Mexico of approximately 2 MBoe/d for the second quarter of 2014 as compared with 2013; and

|  |                                                                                                      
|- | -----------------------------------------------------------------------------------------------------
|• | higher realized prices for crude and condensate, both in the DJ Basin and offshore Equatorial Guinea;

partially offset by:


|  |                                                                                                        
|- | -------------------------------------------------------------------------------------------------------
|• | negative volume impact of severe winter weather and downtime for facility upgrades in the DJ Basin; and

|  |                                                                                                            
|- | -----------------------------------------------------------------------------------------------------------
|• | lower sales volumes from the Aseng project, offshore Equatorial Guinea, due to natural production declines.

Natural Gas Sales – Revenues from natural gas sales increased during the second quarter and first six months of 2014 as compared with 2013 due to the following:


|  |                                                                                                                                                                                 
|- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | increases in total consolidated average realized prices of10%primarily due to increased demand from cooler weather and higher-than-expected inventory withdrawals in the US; and

|  |                                                                                                                                                                                                                                                                                                   
|- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | higher sales volumes in the Marcellus Shale of 231 MMcf/d for second quarter 2014 and 218 MMcf/d for the first six months of 2014, as compared with 108 MMcf/d and 104 MMcf/d, respectively for 2013, primarily attributable to our horizontal drilling program and continued ramp-up of activity;

partially offset by:


|  |                                                                                                                 
|- | ----------------------------------------------------------------------------------------------------------------
|• | lower sales volumes due to non-core onshore US properties divested during 2013 and first six months of 2014; and

|  |                                                                                                             
|- | ------------------------------------------------------------------------------------------------------------
|• | lower sales volumes due to natural field decline from the Mari-B, Noa and Pinnacles fields, offshore Israel.

NGL Sales – The majority of our US NGL production is currently from the DJ Basin. Additional NGL production from the Marcellus Shale added 2 MBbl/d during second quarter and first six months of 2014 as compared with 2013 , primarily due to increased production from the wet gas acreage. NGL sales in the DJ Basin increased by 5 MBbl/d during the second quarter of 2014 as compared with 2013, and recent sales of our non-core onshore US properties have slightly reduced sales volumes as compared with second quarter 2013. Additionally, sales prices have increased 13% for the first six months of 2014, compared to the first six months of 2013.


Income from Equity Method Investees  We 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.


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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.





Operating Costs and Expenses


Operating costs and expenses were as follows:


Increasefrom Prior Year(millions)20142013Three Months Ended June 30,Production Expense$248$21018%Exploration Expense5990(34)%Depreciation, Depletion and Amortization41336812%General and Administrative12710422%Gain on Divestitures(44)4N/MAsset Impairments34——%Other Operating (Income) Expense, Net171242%Total$854$7888%Six Months Ended June 30,Production Expense$481$39821%Exploration Expense133151(12)%Depreciation, Depletion and Amortization83773414%General and Administrative26621623%Gain on Divestitures(42)(12)N/MAsset Impairments131——%Other Operating (Income) Expense, Net2320N/MTotal$1,829$1,50721%


N/M – Amount is not meaningful.


Changes in operating costs and expenses are discussed below.


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Production Expense Components of production expense were as follows: (millions, except unit rate)Total per BOE(1)TotalUnitedStatesEquatorial GuineaIsraelOther Int'l,Corporate(2)Three Months Ended June 30, 2014Lease Operating Expense(3)$5.99$154$88$36$14$16Production and Ad Valorem Taxes2.065345——8Transportation and Gathering Expense1.604140——1Total Production Expense$9.65$248$173$36$14$25Three Months Ended June 30, 2013Lease Operating Expense(3)$6.04$140$90$27$19$4Production and Ad Valorem Taxes1.874335——8Transportation and Gathering Expense1.172727———Total Production Expense$9.08$210$152$27$19$12Six Months Ended June 30, 2014Lease Operating Expense(3)$5.89$299$176$67$26$30Production and Ad Valorem Taxes2.0110285——17Transportation and Gathering Expense1.578078——2Total Production Expense$9.47$481$339$67$26$49Six Months Ended June 30, 2013Lease Operating Expense(3)$5.78$257$179$47$20$11Production and Ad Valorem Taxes1.948669——17Transportation and Gathering Expense1.245554——1Total Production Expense$8.96$398$302$47$20$29


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

|    |                                              
|--- | ---------------------------------------------
|(2) | Other International includes primarily China.

|    |                                                                                                                                                                            
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(3) | 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 second quarter and first six months of 2014 , total production expense increased as compared with 2013 due to the following:


|  |                                                                                                                                   
|- | ----------------------------------------------------------------------------------------------------------------------------------
|• | increased lease operating expense in the DJ Basin and Marcellus Shale due to increased development activity and higher production;

|  |                                                                                                                                         
|- | ----------------------------------------------------------------------------------------------------------------------------------------
|• | increased lease operating expense offshore Equatorial Guinea primarily due to the start up of the Alen field in the second half of 2013;

|  |                                                                                                                                                            
|- | -----------------------------------------------------------------------------------------------------------------------------------------------------------
|• | increased lease operating expense offshore Israel primarily due to the start up of the Tamar field, which began producing at the end of first quarter 2013;

|  |                                                                                                                                              
|- | ---------------------------------------------------------------------------------------------------------------------------------------------
|• | increased production and ad valorem taxes in the DJ Basin and Marcellus Shale due to higher production volumes and higher average prices; and

|  |                                                                                                                                                         
|- | --------------------------------------------------------------------------------------------------------------------------------------------------------
|• | increased transportation and gathering expense in the DJ Basin and Marcellus Shale due to higher production volumes from ongoing development activities;

partially offset by:


|  |                                                                                            
|- | -------------------------------------------------------------------------------------------
|• | decreased lease operating expense from sales of non-core onshore US properties in 2013; and

|  |                                                                                                     
|- | ----------------------------------------------------------------------------------------------------
|• | decreased lease operating expense from natural field decline from the Mari-B field, offshore Israel.

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Exploration Expense Components of exploration expense were as follows: (millions)TotalUnitedStatesWestAfrica(1)EasternMediter-ranean(2)Other Int'l,Corporate(3)Three Months Ended June 30, 2014Dry Hole Cost$—$—$—$—$—Seismic98—1—Staff Expense33102318Other1717———Total Exploration Expense$59$35$2$4$18Three Months Ended June 30, 2013Dry Hole Cost$23$15$8$—$—Seismic2572610Staff Expense3053—22Other1212———Total Exploration Expense$90$39$13$6$32Six Months Ended June 30, 2014Dry Hole Cost$2$2$—$—$—Seismic3215—215Staff Expense68184541Other3131———Total Exploration Expense$133$66$4$7$56Six Months Ended June 30, 2013Dry Hole Cost$23$15$8$—$—Seismic50132629Staff Expense58124240Other2021——(1)Total Exploration Expense$151$61$14$8$68


|    |                                                                    
|--- | -------------------------------------------------------------------
|(1) | West Africa includes Equatorial Guinea, Cameroon, and Sierra Leone.

|    |                                                  
|--- | -------------------------------------------------
|(2) | Eastern Mediterranean includes Israel and Cyprus.

|    |                                                                 
|--- | ----------------------------------------------------------------
|(3) | Other International includes the Falkland Islands and Nicaragua.

Exploration expense for the second quarter and first six months of 2014 included:


|  |                                                                                        
|- | ---------------------------------------------------------------------------------------
|• | seismic expense related to 3D seismic testing in the DJ Basin and Falkland Islands; and

|  |                                                                       
|- | ----------------------------------------------------------------------
|• | staff expense associated with new ventures and corporate expenditures.

Exploration expense for the second quarter and first six months of 2013 included the following:


|  |                                                                                                                                                                                                                             
|- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | dry hole cost related primarily to the deeper exploration objective of the second Gunflint appraisal well, deepwater Gulf of Mexico, and the side track portion of the Carla I-7 appraisal well, offshore Equatorial Guinea;

|  |                                                                                               
|- | ----------------------------------------------------------------------------------------------
|• | other international seismic expense related to 3D seismic testing in the Falkland Islands; and

|  |                                                                       
|- | ----------------------------------------------------------------------
|• | staff expense associated with new ventures and corporate expenditures.

Depreciation, Depletion and Amortization DD&A expense was as follows: Three Months EndedJune 30,Six Months EndedJune 30,2014201320142013DD&A Expense (millions)(1)$413$368$837$734Unit Rate per BOE(2)$16.07$15.93$16.49$16.53


|    |                                                                                                      
|--- | -----------------------------------------------------------------------------------------------------
|(1) | For DD&A expense by geographical area, seeItem 1. Financial Statements – Note12. Segment Information.

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

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Total DD&A expense for the second quarter and first six months of 2014 increased as compared with 2013 due to the following:


|  |                                                                                                                             
|- | ----------------------------------------------------------------------------------------------------------------------------
|• | increase in the DJ Basin and the Marcellus Shale due to higher sales volumes associated with increased development activity;

|  |                                                                                                                                           
|- | ------------------------------------------------------------------------------------------------------------------------------------------
|• | increase in the deepwater Gulf of Mexico due to a new well producing at Ticonderoga and the addition of the Neptune spar at Swordfish; and

|  |                                                                                                                
|- | ---------------------------------------------------------------------------------------------------------------
|• | increase offshore Equatorial Guinea primarily due to the start up of the Alen field in the second half of 2013;

partially offset by:


|  |                                                                     
|- | --------------------------------------------------------------------
|• | decrease due to sales of non-core onshore US properties in 2013; and

|  |                                                                                                                                  
|- | ---------------------------------------------------------------------------------------------------------------------------------
|• | decrease offshore Israel related to the start up of the Tamar field at the end of first quarter 2013 which has a lower DD&A rate.

The increase in the unit rate per BOE for the second quarter of 2014 as compared with 2013 was due primarily to the change in mix of production. Higher-cost production volumes in the deepwater Gulf of Mexico were offset by lower cost volumes produced at Tamar, offshore Israel, which replaced higher cost volumes produced from the Mari-B, Noa and Pinnacles fields.  The unit rate per BOE remained flat for the first six months of 2014 as compared with 2013 .


General and Administrative Expense General and administrative expense (G&A) was as follows: Three Months EndedJune 30,Six Months EndedJune 30,2014201320142013G&A Expense (millions)$127$104$266$216Unit Rate per BOE(1)$4.93$4.48$5.24$4.86


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

G&A expense for the second quarter and first six months of 2014 increased as compared with 2013 primarily due to additional expenses relating to personnel and office space in support of our major development projects and increased exploration activities. For example, our total number of employees increased from 2,190 at December 31, 2012, to 2,527 at December 31, 2013 and to just over 2,600 at June 30, 2014.  An increase in the number of participants in our 401(k) savings plan, as a result of the planned termination of the defined benefit pension plan, resulted in an increase in payroll burden.


Asset Impairment Expense Asset impairment expense was as follows: Three Months EndedJune 30,Six Months EndedJune 30,(millions)2014201320142013Asset Impairments$34$—$131$—


See Item 1. Financial Statements – Note 2. Basis of Presentation ,  Note  4. Asset Impairments and Note 7. Fair Value Measurements and Disclosures .


Other (Income) Expense


Other (income) expense was as follows: Three Months EndedJune 30,Six Months EndedJune 30,(millions)2014201320142013(Gain) Loss on Commodity Derivative Instruments$236$(161)$311$(89)Interest, Net of Amount Capitalized52339958Other Non-Operating Expense, Net831312Total$296$(125)$423$(19)


(Gain) Loss on Commodity Derivative Instruments (Gain) Loss on commodity derivative instruments is a result of mark-to-market accounting. Many factors impact a gain or loss on commodity derivative instruments including: increases and decreases in the commodity forward price curves compared to our executed hedging arrangements; increases in hedged future volumes; and the mix of hedge arrangements between NYMEX WTI, Dated Brent and NYMEX Henry Hub commodities. See Item 1. Financial Statements – Note 5. Derivative Instruments and Hedging Activities and  Note 7. Fair Value Measurements and Disclosures .


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Interest Expense and Capitalized Interest Interest expense and capitalized interest were as follows: Three Months EndedJune 30,Six Months EndedJune 30,2014201320142013(millions, except unit rate)Interest Expense, Gross$78$68$159$135Capitalized Interest(26)(35)(60)(77)Interest Expense, Net$52$33$99$58Unit Rate per BOE(1)$2.01$1.44$1.95$1.31


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


The increase in interest expense, gross, is due to the issuance of new senior debt in November 2013 and recent borrowings under our Credit Facility.


The decrease in capitalized interest is primarily due to the completion of longer cycle time major projects, such as Alen, offshore West Africa, and Tamar, offshore Israel, and the current concentration of development activity onshore US, which has more rapid well construction time, partially offset by higher work in progress amounts related to major long-term projects in the deepwater Gulf of Mexico, offshore West Africa, and offshore Israel.


Income Tax Provision


See Item 1. Financial Statements – Note 11. Income Taxes for a discussion of the change in our effective tax rate for the second quarter and first six months of 2014 as compared with 2013 .


Discontinued Operations


The North Sea geographical segment is reflected as discontinued operations for the first six months of 2013. During first quarter 2014, the remaining unsold North Sea assets were reclassified to held and used, and their operations are included in continuing operations for 2014.


Summarized results of discontinued operations were as follows: Three Months EndedJune 30,Six Months EndedJune 30,20132013(millions)Oil and Gas Sales$12$21Expenses717Income Before Income Taxes54Income Tax Expense310Operating (Income) Loss, Net of Tax2(6)Gain on Sale, Net of Tax1755Income From Discontinued Operations$19$49Key Statistics:Daily ProductionCrude Oil & Condensate (MBbl/d)11Natural Gas (MMcf/d)33Average Realized PriceCrude Oil & Condensate (Per Bbl)$103.21$107.63Natural Gas (Per Mcf)11.4010.63


Our long-term debt is recorded at the consolidated level and is not reflected by each component. Thus, we have not allocated interest expense to discontinued operations. See Item 1. Financial Statements – Note 3. Divestitures .





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LIQUIDITY AND CAPITAL RESOURCES


Capital Structure/Financing Strategy


In seeking to effectively fund and monetize our discovered hydrocarbons, we employ a capital structure and financing strategy designed to provide sufficient liquidity throughout the volatile commodity price cycle.  Specifically, we strive to retain the ability to fund long cycle, multi-year, capital intensive development projects throughout a range of scenarios, while also funding a robust exploration program and maintaining capacity to capitalize on financially attractive periodic mergers and acquisitions activity.


We endeavor to maintain an investment grade debt rating in service of these objectives, while delivering competitive returns and a growing dividend.  We utilize a commodity price hedging program to reduce the impacts of commodity price volatility and enhance the predictability of cash flows along with a risk and insurance program to protect against disruption to our cash flows and the funding of our business.


We strive to maintain a minimum liquidity level to address volatility and risk. Traditional sources of our liquidity are cash flows from operations, cash on hand, available borrowing capacity under our Credit Facility, and proceeds from sales of non-core properties.  We may also access the capital markets to ensure adequate liquidity exists in the form of unutilized capacity under our Credit Facility or to refinance scheduled debt maturities.  On April 15, 2014, we repaid $200 million of scheduled current maturities. See Item 1. Financial Statements – Note 6. Debt  and Credit Facility, below.


Expanded development in the DJ Basin and Marcellus Shale, investment in our recently sanctioned major development projects, and our planned exploration and appraisal drilling activities are estimated to result in near term capital expenditures exceeding cash flows from operating activities. The extent to which capital investment will exceed operating cash flows depends on our success in sanctioning future development projects, the results of our exploration activities, and new business opportunities as well as external factors such as commodity prices, among others. Our financial capacity, coupled with our diversified portfolio, provides us with flexibility in our investment decisions including execution of our major development projects and increased exploration activity.


To support our investment program, we expect that higher production resulting from our core onshore US development programs combined with new production from Tamar, which began producing in late first quarter 2013, and Alen, which began producing in late second quarter 2013, will result in an increase in cash flows which will be available to meet a substantial portion of future capital commitments.


Cash on hand at June 30, 2014 totaled $958 million , and includes both domestic and foreign cash. We consider repatriating  foreign cash to increase our financial flexibility and fund our capital investment program to the extent such cash is not required to fund foreign investment projects and would not incur material US tax. During the first six months of 2014, we repatriated $519 million from our UK operations. We will not incur material US tax on these repatriations.


We also evaluate potential strategic farm-out arrangements of our working interests in Israel, Cyprus, Cameroon, Nicaragua and the deepwater Gulf of Mexico for reimbursement of our capital spending in these areas. In addition, our current liquidity level and balance sheet, along with our ability to access the capital markets, provide flexibility. We believe that we are well-positioned to fund our long-term growth plans.


We are currently evaluating potential development scenarios for our significant natural gas discoveries offshore Eastern Mediterranean, including Leviathan and Cyprus Block 12. The magnitude of these discoveries presents technical and financial challenges for us due to the large-scale development requirements. Potential development scenarios may include the construction of subsea pipeline, floating LNG, LNG terminals, FPSO or other options. Each of these development options would require a multi-billion dollar investment and require a number of years to complete. We are currently considering various  project finance alternatives for Leviathan.


Marcellus Shale Joint Venture Our joint venture arrangement with a subsidiary of CONSOL Energy, Inc. is structured in a manner to address partner alignment and financial affordability. Under the arrangement, we agreed to fund one-third of CONSOL's 50% working interest share of future drilling and completion costs up to a fixed amount.  See Contractual Obligations , below.


Pension Plan Termination We are in the process of terminating our defined benefit pension plan (pension plan). We expect to liquidate the associated pension obligation through lump-sum payments to participants or the purchase of annuities on their behalf. As of December 31, 2013, the latest actuarial measurement date for the pension plan, the accumulated benefit obligation totaled $315 million, and the fair value of plan assets was $265 million.


At March 31, 2014, we reclassified the long-term portion of the net pension plan liability to current, as we expect final plan termination to occur by the end of first quarter 2015. We expect to make additional contributions to the plan during the period leading up to final termination and distribution to the extent necessary to fund these obligations. In addition, upon termination


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of the pension plan, all unamortized prior service cost and net actuarial loss remaining in AOCL will be charged to expense. This amount totaled approximately $98 million as of June 30, 2014 .


In coordination with the termination of the pension plan, we also amended our restoration plan to freeze the accrual of benefits effective December 31, 2013. Payments under the restoration plan will continue to be made in ordinary course without acceleration. Restoration plan participants who remain employed by us upon final liquidation and distribution of assets of the pension plan may elect to have the lump sum present value of their restoration plan benefits converted into an account balance under our nonqualified deferred compensation plan.


Available Liquidity Information regarding cash and debt balances is as follows: June 30,December 31,20142013(millions, except percentages)Cash and Cash Equivalents$958$1,117Amount Available to be Borrowed Under Credit Facility(1)3,4004,000Total Liquidity$4,358$5,117Total Debt(2)$5,237$4,843Total Shareholders' Equity9,5549,184Ratio of Debt-to-Book Capital(3)35%35%


|    |                          
|--- | -------------------------
|(1) | SeeCredit Facility,below.

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|--- | -----------------------------------------------------------------------------------------------
|(2) | Total debt includes capital lease and other obligations and excludes unamortized debt discount.

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|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(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 $958 million in cash and cash equivalents at June 30, 2014 , primarily denominated in US dollars and invested in money market funds and short-term deposits with major financial institutions. Approximately $859 million of this cash is attributable to our foreign subsidiaries and a portion would be subject to US income taxes if repatriated.


Credit Facility Our Credit Facility matures on October 3, 2018. The commitment is $4.0 billion through the maturity date of the Credit Facility. As of June 30, 2014 , we had drawn $600 million under the Credit Facility to fund increased development activities. The weighted average interest rate on the borrowings was 1.41% . Borrowings under our Credit Facility subject us to interest rate risk. See Item 1. Financial Statements –Note 6. Debt and  Item 3. Quantitative and Qualitative Disclosures .


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


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


Commodity derivative instruments are recorded at fair value in our consolidated balance sheets, and changes in fair value are recorded in earnings in the period in which the change occurs.  As of June 30, 2014 , the fair value of our commodity derivative assets was $2 million and the fair value of our commodity derivative liabilities was $288 million (after consideration of netting provisions within our master agreements).  See Item 1. Financial Statements –Note 7. Fair Value Measurements and Disclosures for a description of the methods we use to estimate the fair values of commodity derivative instruments and Credit Risk, below.


Credit Risk We monitor the creditworthiness of our trade creditors, joint venture partners, hedging counterparties, and financial institutions on an ongoing basis. Some of these entities are not as creditworthy as we are and may experience credit downgrades or liquidity problems. Counterparty credit downgrades or liquidity problems could result in a delay in our receiving proceeds from commodity sales, reimbursement of joint venture costs, and potential delays in our major development projects. We are unable to predict sudden changes in a party's creditworthiness or ability to perform. Even if we do accurately predict such sudden changes, our ability to negate these risks may be limited and we could incur significant financial losses.


In addition, nonoperating partners often must obtain financing for their share of capital cost for development projects. A partner's inability to obtain financing could result in a delay of our joint development projects. For example, our Eastern Mediterranean partners must obtain financing for their share of significant development expenditures at Leviathan, offshore Israel, which potentially includes an LNG project and/or major underwater pipeline.


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Credit enhancements have been obtained from some parties in the form of parental guarantees, letters of credit or credit insurance; however, not all of our counterparty credit is protected through guarantees or credit support. Nonperformance by a trade creditor, joint venture partner, hedging counterparty or financial institution could result in significant financial losses.


Contractual Obligations


CONSOL Carried Cost Obligation The 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 a multi-year period and is capped at $400 million in each calendar year. The obligation is suspended if average Henry Hub natural gas prices fall and remain below $4.00 per MMBtu in any three consecutive month period and remain suspended until average Henry Hub natural gas prices are above $4.00 per MMBtu for three consecutive months. The carry terms ensure economic alignment with our partner in periods of low natural gas prices.


Due to past low natural gas prices, the CONSOL Carried Cost Obligation was suspended from the end of 2011 to February 28, 2014. Due to recent increases in Henry Hub natural gas prices, we began funding a portion of CONSOL's working interest share of certain drilling and completion costs as of March 1, 2014.


Based on the June 30, 2014, NYMEX Henry Hub natural gas price curve and current development plans, we forecast we will incur approximately $240 million under the CONSOL Carried Cost Obligation for 2014. The carry will be suspended again if average Henry Hub natural gas prices fall and remain below $4.00 per MMBtu in any future three consecutive month period.


Marcellus Shale Firm Transportation Agreements In February 2014, we signed Precedent Agreements for Firm Transportation to move 150,000 MMBtu per day of our Marcellus Shale natural gas production to Gulf Coast markets. Our financial commitment is approximately $765 million, undiscounted, over a 15-year period, beginning in 2017.


Cash Flows


Cash flow information is as follows: Six Months EndedJune 30,20142013(millions)Total Cash Provided By (Used in)Operating Activities$1,757$1,244Investing Activities(2,215)(1,835)Financing Activities299(90)Decrease in Cash and Cash Equivalents$(159)$(681)


Operating Activities Net cash provided by operating activities for the first six months of 2014 increased as compared with 2013 .  Higher crude oil and natural gas sales prices and an increase in crude oil and natural gas sales volumes were offset by increases in production expenses and general and administrative expense. Working capital changes contributed $105 million of positive operating cash flow in the first six months of 2014 as compared with a negative impact of $168 million in the first six months of 2013 .


Investing Activities Our investing activities include capital spending on a cash basis for oil and gas properties and investments in unconsolidated subsidiaries accounted for by the equity method. These investing activities may be offset by proceeds from property sales or dispositions, including farm-in arrangements, which may result in reimbursement for capital spending that had occurred in prior periods. Capital spending for property, plant and equipment increased by $392 million during the first six months of 2014 as compared with 2013 , primarily due to increased major project development activity in our core areas. We also invested $40 million in CONE Gathering LLC (CONE), discussed below, during the first six months of 2014 . We received $146 million in proceeds from non-core asset divestitures during the first six months of 2014 , as compared with $114 million during the same period in 2013.


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 six months of 2014 , funds were provided by cash proceeds from, and tax benefits related to, the exercise of stock options ( $58 million ) and net cash proceeds from our Credit Facility ( $600 million ). We used cash to pay dividends on our common stock ( $116 million ), to repay Senior Notes that were due April 15, 2014 ( $200 million ), make principal payments related to capital lease obligations ( $28 million ) and repurchase shares of our common stock ( $15 million ).


In comparison, during the first six months of 2013 , funds were provided by cash proceeds from, and tax benefits related to, the exercise of stock options ( $43 million ).  We also used cash to pay dividends on our common stock ( $96 million ), make


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principal payments related to the Aseng FPSO capital lease obligation ( $23 million ) and repurchase shares of our common stock ( $14 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 EndedJune 30,Six Months EndedJune 30,2014201320142013(millions)Acquisition, Capital and Exploration ExpendituresUnproved Property Acquisition(1)$74$97$129$134Exploration138197228385Development(2)9897491,7361,374Corporate and Other438990124Total$1,244$1,132$2,183$2,017OtherInvestment in Equity Method Investee(3)$28$3$40$23Increase in Capital Lease Obligations16312136


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|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | Unproved property acquisition cost for 2014 includes $37 million in the DJ Basin, $75 million in the Marcellus Shale, and $16 million in the deepwater Gulf of Mexico.  Unproved property acquisition cost for 2013 includes $73 million in the DJ Basin, $47 million in the Marcellus Shale, and $12 million in the deepwater Gulf of Mexico.

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|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(2) | Development expenditures for 2014 include drilling rig mobilization charges of $55 million, a portion of which will be billed to partners in future periods as the rig is utilized.

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|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(3) | Investment in equity method investees represents funding of our investment in CONE which owns and operates the natural gas gathering infrastructure associated with our Marcellus Shale joint venture.




Total expenditures increased in 2014 as compared with 2013 due to accelerated activity in the DJ Basin and Marcellus Shale.


Financing Activities


Long-Term Debt Our principal source of liquidity is our Credit Facility that matures October 3, 2018. At June 30, 2014 , $600 million was outstanding under the Credit Facility, leaving $3.4 billion available for use. We expect to use the Credit Facility to fund our capital investment program, and may periodically borrow amounts for working capital purposes. See Item 1 Financial Statements – Note 6. Debt .


Our outstanding fixed-rate debt (excluding capital lease and other obligations) totaled approximately $4.3 billion at June 30, 2014 . The weighted average interest rate on fixed-rate debt was 6.09% , with maturities ranging from March 2019 to August 2097. On April 15, 2014, we repaid $200 million of matured fixed rate debt.


Dividends We paid total cash dividends of 32 cents per share of our common stock during the first six months of 2014 and 27 cents per share during the first six months of 2013 (as adjusted for the 2-for-1 stock split during the second quarter of 2013).


On July 22, 2014, the Board of Directors declared a quarterly cash dividend of 18 cents per common share, which will be paid August 18, 2014 to shareholders of record on August 4, 2014. 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 $41 million during the first six months of 2014 and $31 million during the first six months of 2013 .


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 250,013 shares with a value of $15 million during the first six months of 2014 and 247,985 shares with a value of $14 million during the first six months of 2013 .


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Item 3.    Quantitative and Qualitative Disclosures About Market Risk


Commodity Price Risk


Derivative Instruments Held for Non-Trading Purposes We are  exposed to market risk in the normal course of business operations, and the volatility of crude oil and natural gas prices continues to impact the oil and gas industry. 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 June 30, 2014 , we had entered into variable to fixed price commodity swaps and three-way collars 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 liability position with a fair value of $286 million . Based on the June 30, 2014 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 liability by approximately $41 million . A hypothetical price increase of $0.10 per MMBtu for natural gas would increase the fair value of our net commodity derivative liability by approximately $10 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 Credit Facility and the amount of interest we earn on our short-term investments.


At June 30, 2014 , we had approximately $4.9 billion (excluding capital lease and other obligations) of long-term debt outstanding. Of this amount, $4.3 billion was fixed-rate debt with a weighted average interest rate of 6.09% . 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.


The remainder of our long-term debt, $600 million at June 30, 2014 , was variable-rate debt. Variable-rate debt exposes us to the risk of earnings or cash flow loss due to increases in market interest rates. We estimate that a hypothetical 25 basis point change in the floating interest rates applicable to the June 30, 2014 balance of our variable-rate debt would result in a change in annual interest expense of approximately $2 million .


We are also exposed to interest rate risk related to our interest-bearing cash and cash equivalents balances. As of June 30, 2014 , our cash and cash equivalents totaled approximately $958 million , approximately 40% 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 June 30, 2014 would result in a change in annual interest income of approximately $1 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 taxes payable in foreign tax jurisdictions, are settled in the foreign local currency. A reduction in the value of the US dollar against currencies of other countries in which we have material operations could result in the use of additional cash to settle operating, administrative, and tax liabilities.


Net transaction gains and losses were de minimis for the second quarter and the first six months of both 2014 and 2013.


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


Disclosure Regarding Forward-Looking Statements


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


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|• | our growth strategies;

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

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|• | anticipated trends in our business;

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|  |                                  
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|• | our future results of operations;

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

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|• | market conditions in the oil and gas industry;

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|• | our ability to make and integrate acquisitions;

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

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|- | --------------------
|• | access to resources.

Forward-looking statements are typically identified by use of terms such as “may,” “will,” “expect,” “believe,” “anticipate,” “estimate,” “intend,” and similar words, although some forward-looking statements may be expressed differently. These forward-looking statements are made based upon our current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements. You should consider carefully the statements under Item 1A. Risk Factors included in our Annual Report on Form 10-K for the year ended December 31, 2013 , 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, 2013 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.


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Part II. Other Information


Item 1.    Legal Proceedings


West Virginia Matter In March 2013, we received seven Notices of Violation (NOV) and two Administrative Orders (Orders) from the West Virginia Department of Environmental Protection Office of Oil and Gas (OOG) regarding the unintentional discharge of a mixture of freshwater and produced water that occurred on or about the evening of February 22, 2013 from one of our permitted water storage facilities in Marshall County, West Virginia. At this time, the OOG has not established a proposed penalty for these NOVs or Orders. Given the 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.





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, 2013 .





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


The following table sets forth, for the periods indicated, our share repurchase activity:


PeriodTotal Number ofSharesPurchased(1)AveragePrice PaidPer ShareTotal Number ofShares Purchasedas Part of PubliclyAnnounced Plans orProgramsApproximate DollarValue of Shares thatMay Yet BePurchased Under thePlans or Programs(in thousands)4/1/2014 - 4/30/20141,345$73.46——5/1/2014 - 5/31/201483370.95——6/1/2014 - 6/30/201450776.08——Total2,685$73.17——





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




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Item 3.    Defaults Upon Senior Securities


None.





Item 4.    Mine Safety Disclosures


Not applicable.





Item 5.    Other Information


None.





Item 6.    Exhibits


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


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Signatures





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





NOBLE ENERGY, INC.(Registrant)DateJuly 24, 2014/s/ Kenneth M. FisherKenneth M. FisherExecutive Vice President, Chief Financial Officer





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Index to Exhibits


Exhibit NumberExhibit3.1Certificate of Incorporation of the Registrant (as amended through April 23, 2013), filed as Exhibit 3.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2013 and incorporated herein by reference.3.2By-Laws of Noble Energy, Inc. (as amended through April 23, 2013), filed as Exhibit 3.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2013 and incorporated herein by reference.12.1Calculation of ratio of earnings to fixed charges, filed herewith.31.1Certification 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.31.2Certification 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.32.1Certification 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.32.2Certification 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.INSXBRL Instance Document101.SCHXBRL Schema Document101.CALXBRL Calculation Linkbase Document101.LABXBRL Label Linkbase Document101.PREXBRL Presentation Linkbase Document101.DEFXBRL Definition Linkbase Document








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