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, 2015





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, 2015 , there were 387,045,609 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 Operations25Item 3.Quantitative and Qualitative Disclosures About Market Risk45Item 4.Controls and Procedures46Part II.Other Information47Item 1.Legal Proceedings47Item 1A.Risk Factors47Item 2.Unregistered Sales of Equity Securities and Use of Proceeds47Item 3.Defaults Upon Senior Securities48Item 4.Mine Safety Disclosures48Item 5.Other Information48Item 6.Exhibits48Signatures49Index to Exhibits50





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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 Ended June 30,Six Months EndedJune 30,2015201420152014RevenuesOil, Gas and NGL Sales$722$1,338$1,462$2,665Income from Equity Method Investees6452497Other2—4—Total7301,3831,4902,762Costs and ExpensesProduction Expense213244459474Exploration Expense4159106133Depreciation, Depletion and Amortization451413905837General and Administrative104127198266Asset Impairments153443131Other Operating (Income) Expense, Net67(23)73(12)Total8918541,7841,829Operating Income (Loss)(161)529(294)933Other (Income) Expense(Gain) Loss on Commodity Derivative Instruments87236(63)311Interest, Net of Amount Capitalized545211299Other Non-Operating (Income) Expense, Net(9)8(9)13Total13229640423Income (Loss) Before Income Taxes(293)233(334)510Income Tax (Benefit) Provision(184)41(203)118Net Income (Loss)$(109)$192$(131)$392Earnings (Loss) Per Share, Basic$(0.28)$0.53$(0.35)$1.09Earnings (Loss) Per Share, Diluted$(0.28)$0.52$(0.35)$1.07Weighted Average Number of Shares OutstandingBasic387361378361Diluted387366378365





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 Ended June 30,Six Months EndedJune 30,2015201420152014Net Income (Loss)$(109)$192$(131)$392Other Items of Comprehensive IncomeNet Change in Mutual Fund Investment——(11)—Less Tax Benefit——3—Net Change in Pension and Other2452510Less Tax Benefit(10)(1)(10)(4)Other Comprehensive Income14476Comprehensive Income (Loss)$(95)$196$(124)$398





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, 2015December 31, 2014ASSETSCurrent AssetsCash and Cash Equivalents$1,278$1,183Accounts Receivable, Net554857Commodity Derivative Assets, Current456710Other Current Assets244325Total Current Assets2,5323,075Property, Plant and EquipmentOil and Gas Properties (Successful Efforts Method of Accounting)27,13825,599Property, Plant and Equipment, Other681630Total Property, Plant and Equipment, Gross27,81926,229Accumulated Depreciation, Depletion and Amortization(8,996)(8,086)Total Property, Plant and Equipment, Net18,82318,143Goodwill616620Other Noncurrent Assets714715Total Assets$22,685$22,553LIABILITIES AND SHAREHOLDERS’ EQUITYCurrent LiabilitiesAccounts Payable - Trade$1,222$1,578Other Current Liabilities834944Total Current Liabilities2,0562,522Long-Term Debt6,1126,103Deferred Income Taxes, Noncurrent2,2782,516Other Noncurrent Liabilities1,0301,087Total Liabilities11,47612,228Commitments and ContingenciesShareholders’ EquityPreferred Stock - Par Value $1.00 per share; 4 Million Shares Authorized, None Issued——Common Stock - Par Value $0.01 per share; 1 Billion and 500 Million Shares Authorized, respectively; 428 Million and 402 Million Shares Issued, respectively44Additional Paid in Capital4,7783,624Accumulated Other Comprehensive Loss(83)(90)Treasury Stock, at Cost; 38 Million Shares(683)(671)Retained Earnings7,1937,458Total Shareholders’ Equity11,20910,325Total Liabilities and Shareholders’ Equity$22,685$22,553





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 30,20152014Cash Flows From Operating ActivitiesNet Income (Loss)$(131)$392Adjustments to Reconcile Net Income to Net Cash Provided by Operating ActivitiesDepreciation, Depletion and Amortization905837Asset Impairments43131Dry Hole Cost192Deferred Income Tax (Benefit) Expense(312)24Income (Loss) from Equity Method Investees, Net of Dividends4(3)(Gain) Loss on Commodity Derivative Instruments(63)311Net Cash Received (Paid) in Settlement of Commodity Derivative Instruments397(83)Gain on Divestitures(1)(42)Stock Based Compensation3845Non-cash Pension Expense21—Other Adjustments for Noncash Items Included in Income1238Changes in Operating Assets and LiabilitiesDecrease in Accounts Receivable30455(Decrease) Increase in Accounts Payable(167)126(Decrease) in Current Income Taxes Payable(63)(86)Other Current Assets and Liabilities, Net(45)25Other Operating Assets and Liabilities, Net5(15)Net Cash Provided by Operating Activities9661,757Cash Flows From Investing ActivitiesAdditions to Property, Plant and Equipment(1,898)(2,321)Additions to Equity Method Investments(65)(40)Proceeds from Divestitures151146Net Cash Used in Investing Activities(1,812)(2,215)Cash Flows From Financing ActivitiesExercise of Stock Options441Excess Tax Benefits from Stock-Based Awards—17Dividends Paid, Common Stock(134)(116)Purchase of Treasury Stock(12)(15)Proceeds from Issuance of Shares of Common Stock to Public, Net of Offering Costs1,112—Proceeds from Credit Facility, Net—600Repayment of Senior Notes—(200)Repayment of Capital Lease Obligation(29)(28)Net Cash Provided by Financing Activities941299Increase (Decrease) in Cash and Cash Equivalents95(159)Cash and Cash Equivalents at Beginning of Period1,1831,117Cash and Cash Equivalents at End of Period$1,278$958





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)





CommonStockAdditionalPaid inCapitalAccumulated OtherComprehensiveLossTreasuryStock atCostRetainedEarningsTotalShareholders'EquityDecember 31, 2014$4$3,624$(90)$(671)$7,458$10,325Net Loss————(131)(131)Stock-based Compensation—38———38Exercise of Stock Options—4———4Dividends (36 cents per share)————(134)(134)Changes in Treasury Stock, Net———(12)—(12)Issuance of Shares of Common Stock to Public, Net of Offering Costs—1,112———1,112Net Change in Pension and Other——7——7June 30, 2015$4$4,778$(83)$(683)$7,193$11,209December 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$9,554








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. We have recently acquired assets in the Eagle Ford Shale and Permian Basin. See Note 3. Rosetta Merger.





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, 2015 and December 31, 2014 and for the three and six months ended June 30, 2015 and 2014 contain all normally recurring adjustments considered necessary for a fair presentation of our financial position, results of operations, cash flows and shareholders’ equity for such periods. Certain prior-period amounts have been reclassified to conform to the current-period presentation. Operating results for the three and six months ended June 30, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, 2015 .


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, 2014 .


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.


Pension Plan We are in the process of terminating our noncontributory, tax-qualified defined benefit pension plan. During second quarter 2015, we liquidated a portion of the associated pension obligation through lump-sum payments to participants. We expect to liquidate the remaining pension obligation through the purchase of annuities during third quarter 2015. At that time, we will reclassify all unamortized prior service cost (PSC) and actuarial loss remaining in accumulated other comprehensive loss (AOCL), totaling approximately $61 million , to earnings.


Equity Offering On March 3, 2015, we closed an underwritten public offering of 21,000,000 shares of common stock, par value $0.01 per share, at a price to the public of $47.50 per share. In addition, on March 25, 2015, we completed the issuance of an additional 3,150,000 shares of common stock, par value $ 0.01 per share, in connection with the exercise of the option of the underwriters to purchase additional shares of common stock. The aggregate net proceeds of the offerings were approximately $1.1 billion (after deducting underwriting discounts and commissions and offering expenses). We used approximately $150 million of the net proceeds to repay outstanding indebtedness under our revolving credit facility and the remainder will be used for general corporate purposes, including the funding of our capital investment program.


Increase in Authorized Shares On April 28, 2015, our stockholders approved an amendment to our Certificate of Incorporation to increase the number of authorized shares of our common stock from 500 million to 1 billion .


Update on Core Area – Israel In March 2014, we and our partners reached an agreement with the Israel Antitrust Authority on various matters (Consent Decree). The Consent Decree, which was subject to final approval by the Antitrust Tribunal, granted the rights, to us and our partners, to jointly market natural gas from the Leviathan field. Also, as a result of the Consent Decree, we agreed to divest our Tanin and Karish natural gas discoveries.


However, on December 23, 2014, we and our partners in the Leviathan field were advised by the Israel Antitrust Commissioner of his decision to not submit the Consent Decree to the Antitrust Tribunal for final approval. This is a matter that we believed was resolved and we had received assurances from the Antitrust Authority that approval was forthcoming. An oral hearing with the Antitrust Authority took place on January 27, 2015.


During second quarter 2015, we continued to work to resolve regulatory matters with the Israeli government. In June 2015, the Israeli government approved a framework (Framework) to support development of offshore natural gas reserves including natural gas exports. Recently, the government conducted public hearings on the Framework and we understand the government is currently progressing toward final approval. Legal challenges may be brought against the Framework in the Israeli courts. Therefore, there can be no assurance as to when or if the Framework will be finalized or as to the terms thereof if finalized. If necessary, we are prepared to defend our legal rights to our Israel assets to the fullest extent in both domestic and international venues.





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 Noble Energy, Inc.
 Notes to Consolidated Financial Statements





We remain prepared to implement the Consent Decree if agreed with the Antitrust Authority but in any case, expect that divestiture of Tanin and Karish will be part of a final regulatory settlement.  We therefore continue to hold these assets for sale.


Recently Issued Accounting Standards In July 2015,  the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2015-11 (ASU 2015-11): Simplifying the Measurement of Inventory, effective for annual and interim periods beginning after December 15, 2016. ASU 2015-11 changes the inventory measurement principle for entities using the first-in, first out (FIFO) or average cost methods. For entities utilizing one of these methods, the inventory measurement principle will change from lower of cost or market to the lower of cost and net realizable value. We are currently evaluating the provisions of ASU 2015-11 and assessing the impact, if any, it may have on our financial position and results of operations.


In April 2015, the FASB issued Accounting Standards Update No. 2015-03 (ASU 2015-03): Simplifying the Presentation of Debt Issuance Costs, effective for annual and interim periods beginning after December 15, 2015. ASU 2015-03 requires that all costs incurred to issue debt be presented in the balance sheet as a direct deduction from the carrying value of the debt. It is effective retrospectively for all prior periods presented in the financial statements beginning in the first quarter 2016 and is only expected to impact the presentation of our consolidated balance sheet. As of June 30, 2015 and December 31, 2014, we had $47 million and $50 million of capitalized, unamortized debt issuance costs, respectively, included in other long-term assets in our consolidated balance sheet.


In February 2015, the FASB issued Accounting Standards Update No. 2015-02 (ASU 2015-02): Consolidation - Amendments to the Consolidation Analysis, effective for annual and interim periods beginning after December 15, 2015. ASU 2015-02 changes the guidance as to whether an entity is a variable interest entity (VIE) or a voting interest entity and how related parties are considered in the VIE model. We are currently evaluating the provisions of ASU 2015-02 and assessing the impact, if any, it may have on our financial position and results of operations.


In May 2014, the FASB issued Accounting Standards Update No. 2014-09 (ASU 2014-09), which creates Topic 606, Revenue from Contracts with Customers, 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. Initially, the amendments in ASU 2014-09 were effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, and early application was not permitted. On July 9, 2015, the FASB agreed to give companies an extra year to comply with the new standard. The standard will be effective for fiscal years that begin after December 15, 2017, for public companies. We are currently evaluating the provisions of ASU 2014-09 and awaiting implementation guidance to determine 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.


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 Noble Energy, Inc.
 Notes to Consolidated Financial Statements


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


Three Months Ended June 30,Six Months EndedJune 30,(millions)2015201420152014Production ExpenseLease Operating Expense$129$150$286$292Production and Ad Valorem Taxes285361102Transportation and Gathering Expense564111280Total$213$244$459$474Other Operating (Income) Expense, NetMidstream Gathering and Processing Expense$6$4$10$7Corporate Restructuring Expense(1)18—18—Stacked Drilling Rig Expense(2)7—7—Pension Plan Termination Expense(3)21—21—Gain on Divestitures(1)(44)—(42)Other, Net16171723Total$67$(23)$73$(12)Other Non-Operating (Income) Expense, NetDeferred Compensation (Income) Expense(4)$(7)$8(5)$12Other (Income) Expense, Net(2)—(4)1Total$(9)$8$(9)$13





|    |                                                                                                                                                     
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | Amount represents severance costs and expenses associated with the relocation of our accounting department from Ardmore, Oklahoma to Houston, Texas.

|    |                                                                                                                                                        
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------
|(2) | Amount represents the day rate cost associated with drilling rigs under contract, but not currently being utilized in our US onshore drilling programs.

|    |                                                                                                                                                                                       
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(3) | Amount includes the reclassification of a portion of  the remaining actuarial loss from AOCL, related to our defined benefit pension plan which is in the process of being terminated.

|    |                                                                                                               
|--- | --------------------------------------------------------------------------------------------------------------
|(4) | Amounts represent increases (decreases) in the fair value of shares of our common stock held in a rabbi trust.

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 Notes to Consolidated Financial Statements


Balance Sheet Information Other balance sheet information is as follows:


(millions)June 30, 2015December 31, 2014Accounts Receivable, NetCommodity Sales$296$405Joint Interest Billings175297Other102171Allowance for Doubtful Accounts(19)(16)Total$554$857Other Current AssetsInventories, Materials and Supplies$79$81Inventories, Crude Oil2024Assets Held for Sale(1)77180Prepaid Expenses and Other Current Assets6840Total$244$325Other Noncurrent AssetsInvestments in Unconsolidated Subsidiaries$400$325Mutual Fund Investments112111Commodity Derivative Assets100180Other Assets10299Total$714$715Other Current LiabilitiesProduction and Ad Valorem Taxes$151$110Income Taxes Payable117180Deferred Income Taxes, Current91158Accrued Benefit Costs, Current111125Asset Retirement Obligations13581Interest Payable6970Current Portion of Capital Lease Obligations6168Other99152Total$834$944Other Noncurrent LiabilitiesDeferred Compensation Liabilities$218$218Asset Retirement Obligations717670Accrued Benefit Costs1924Other76175Total$1,030$1,087


(1) Assets held for sale include our Tanin and Karish natural gas discoveries, offshore Israel.  See Update on Core Area – Israel, above.





Note 3.  Rosetta Merger


On July 20, 2015, stockholders of Rosetta Resources Inc. (Rosetta) approved the merger of Rosetta into a subsidiary of Noble Energy (Rosetta Merger). This transaction adds two premier onshore US shale plays to our portfolio: the Eagle Ford Shale and Permian Basin. Rosetta's liquids-rich asset base includes approximately 50,000 net acres in the Eagle Ford Shale and 54,000 net acres in the Permian ( 45,000 acres in the Delaware Basin and 9,000 acres in the Midland Basin).


The merger was effected through the issuance of approximately 41 million shares of Noble common stock in exchange for all outstanding shares of Rosetta using a ratio of 0.542 of a share of Noble common stock for each share of Rosetta common stock. The closing price of our stock on the New York Stock Exchange was $36.97 on July 20, 2015.


In addition to proved and unproved properties, we acquired commodity derivative assets and assumed Rosetta's outstanding debt. The results of Rosetta’s operations will be included in our consolidated statements of operations beginning July 21, 2015.


The transaction will be accounted for as a business combination, using the acquisition method. Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, final reserve reports and operating information for the properties acquired, valuation of pre-acquisition contingencies, final tax returns that provide the underlying tax bases of Rosetta's assets and liabilities, and final appraisals of assets acquired and liabilities assumed. We expect


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 Noble Energy, Inc.
 Notes to Consolidated Financial Statements


to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the allocation, including any goodwill, will be revised if necessary.


Rosetta Commodity Derivative Instruments


In connection with the Rosetta Merger, our subsidiary, NBL Texas, LLC, assumed the rights and obligations of Rosetta's commodity derivative instruments. NBL Texas, LLC currently holds the following commodity derivative instruments:


Crude Oil Derivative Instruments SwapsCollarsSettlementPeriodType of ContractIndex(1)Bbls PerDayWeightedAverageFixedPriceWeightedAverageShort PutPriceWeightedAverageFloorPriceWeightedAverageCeilingPriceInstruments Entered Into as of July 20, 20152015Two-Way Collars–8,000$—$—$55.00$84.802015Swaps–12,00089.81———2016Swaps–6,00090.28———


(1) Includes a combination of NYMEX WTI and Argus LLS indices.


Natural Gas Derivative Instruments SwapsCollarsSettlementPeriodType of ContractIndex(1)MMBtu PerDayWeightedAverageFixedPriceWeightedAverageShort PutPriceWeightedAverageFloorPriceWeightedAverageCeilingPriceInstruments Entered Into as of July 20, 20152015Swaps–50,000$4.13$—$—$—2015Two-Way Collars–50,000——3.605.042016Swaps–30,0004.04———2016Two-Way Collars–30,000——3.505.60


(1) Includes a combination of HSC (Houston Ship Channel) and TENNZ0 (Tennessee Zone 0) indices.


NGL Derivative Instruments SwapsCollarsSettlementPeriodType of ContractIndexBbls PerDayWeightedAverageFixedPriceWeightedAverageShort PutPriceWeightedAverageFloorPriceWeightedAverageCeilingPriceInstruments Entered Into as of July 20, 20152015SwapsNGL-Ethane2,476$11.18$—$—$—2015SwapsNGL-Propane1,75043.35———2015SwapsNGL-Isobutane61753.05———2015SwapsNGL-Normal Butane57952.53———2015SwapsNGL-Pentanes Plus57977.72———


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 Notes to Consolidated Financial Statements


Rosetta Debt


In connection with the Rosetta Merger, we assumed the following outstanding debt: July 20, 2015(millions, except percentages)DebtInterest RateCredit Facility, due April 12, 2018$70—%5.625% Senior Notes, due May 1, 20217005.625%5.875% Senior Notes, due June 1, 20226005.875%5.875% Senior Notes, due June 1, 20245005.875%Total$1,870





On July 21, 2015, we repaid the $70 million of outstanding borrowings under the Rosetta revolving credit facility.





All outstanding senior notes assumed pay interest semi-annually. On June 29, 2015, we filed a prospectus offering to exchange any and all outstanding Rosetta senior notes for Noble senior notes with the same terms. The offer to exchange expired on July 27, 2015. Approximately 99.4% of the outstanding Rosetta senior notes were tendered for exchange. Approximately $11 million aggregate principal amount of the Rosetta senior notes remained outstanding across the three series. Due to the small outstanding principal amount remaining, we called the remaining outstanding Rosetta Notes for redemption in accordance with the terms of the respective indentures governing the Rosetta notes.





Note 4.  Divestitures


Onshore US Properties During the first six months of 2015, we sold certain onshore US crude oil and natural gas properties, generating net proceeds of $151 million . Proceeds were primarily applied to the DJ Basin depletable field, with no recognition of gain or loss, other than a de minimis gain in second quarter 2015.


During the first six months of 2014, we sold certain non-core onshore US crude oil and natural gas properties. Gains from asset sales during the second quarter of 2014 were de minimis. The information regarding the assets sold is as follows: Six Months EndedJune 30,(millions)2014Sales Proceeds$110LessNet Book Value of Assets Sold(118)Goodwill Allocated to Assets Sold(6)Asset Retirement Obligations Associated with Assets Sold20Gain on Divestitures$6


China Sale  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. 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) Includes $150 million cash received on July 2, 2014, which was recorded as accounts receivable at June 30, 2014.


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 Notes to Consolidated Financial Statements


Note 5.  Asset Impairments


Pre-tax (non-cash) asset impairment charges were as follows: Three Months Ended June 30,Six Months EndedJune 30,(millions)2015201420152014Deepwater Gulf of Mexico$8$18$11$23Eastern Mediterranean7143214North Sea—2—94Total$15$34$43$131


Impairments for 2015 were primarily related to revisions in expected field abandonment or other costs at South Raton (Deepwater Gulf of Mexico) and the Noa and Pinnacles fields (Eastern Mediterranean).


Impairments for 2014 were primarily related to an increase in expected field abandonment costs and a change in the timing of abandonment activities at the North Sea MacCulloch field.


See Note 2. Basis of Presentation , Note 8. Fair Value Measurements and Disclosures and Note  10. Asset Retirement Obligations .


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 Notes to Consolidated Financial Statements





Note 6.  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.


While these instruments mitigate the cash flow risk of future decreases in commodity prices, they may also curtail benefits from future increases in commodity prices. See Note 8. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of our derivative instruments.


Unsettled Commodity Derivative Instruments As of June 30, 2015 , we had entered into the following crude oil derivative instruments: SwapsCollarsSettlementPeriodType of ContractIndexBbls PerDayWeightedAverageFixedPriceWeightedAverageShort PutPriceWeightedAverageFloorPriceWeightedAverageCeilingPriceInstruments Entered Into as of June 30, 20152015SwapsNYMEX WTI27,000$88.80$—$—$—2015SwapsDated Brent8,000100.31———2015Two-Way CollarsNYMEX WTI5,000——50.0064.942015Three-Way CollarsNYMEX WTI20,000—70.5087.5594.412015Three-Way CollarsDated Brent13,000—76.9296.00108.492016SwapsNYMEX WTI9,00080.30———2016SwapsDated Brent9,00097.96———2016Two -Way CollarsNYMEX WTI1,000——60.0070.002016Three-Way CollarsNYMEX WTI6,000—61.0072.5086.372016Three-Way CollarsDated Brent8,000—72.5086.25101.79


As of June 30, 2015 , we had entered into the following natural gas derivative instruments: SwapsCollarsSettlementPeriodType of ContractIndexMMBtuPer DayWeightedAverageFixedPriceWeightedAverageShort PutPriceWeightedAverageFloorPriceWeightedAverageCeilingPriceInstruments Entered Into as of June 30, 20152015SwapsNYMEX HH140,000$4.30$—$—$—2015Three-Way CollarsNYMEX HH150,000—3.584.255.042016Swaps(1)NYMEX HH40,0003.60———2016Two-Way CollarsNYMEX HH30,000——3.003.502016Three-Way CollarsNYMEX HH90,000—2.833.423.90


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|(1) | We have entered into natural gas derivative contracts which give counterparties the option to extend for an additional 12-month period. Options covering a notional volume of30,000MMBtu/d are exercisable on December 22 and 23, 2016. If the counterparties exercise all such options, the notional volume of our existing natural gas derivative contracts will increase by30,000MMBtu/d at an average price of $3.50per MMBtu for each month during the period January 1, 2017 through December 31, 2017.







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 Noble Energy, Inc.
 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, 2015December 31, 2014June 30, 2015December 31, 2014(millions)Balance Sheet LocationFairValueBalance Sheet LocationFairValueBalance Sheet LocationFairValueBalance Sheet LocationFairValueCommodity DerivativeInstrumentsCurrent Assets$456Current Assets$710Current Liabilities$—Current Liabilities$—Noncurrent Assets100Noncurrent Assets180Noncurrent Liabilities—Noncurrent Liabilities—Total$556$890$—$—





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


Three Months Ended June 30,Six Months EndedJune 30,(millions)2015201420152014Cash (Received) Paid in Settlement of Commodity Derivative InstrumentsCrude Oil$(157)$46$(342)$73Natural Gas(30)3(55)10Total Cash (Received) Paid in Settlement of Commodity Derivative Instruments(187)49(397)83Non-cash Portion of (Gain) Loss on Commodity Derivative InstrumentsCrude Oil242192297219Natural Gas32(5)379Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments274187334228(Gain) Loss on Commodity Derivative InstrumentsCrude Oil85238(45)292Natural Gas2(2)(18)19Total (Gain) Loss on Commodity Derivative Instruments$87$236$(63)$311





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 Noble Energy, Inc.
 Notes to Consolidated Financial Statements


Note 7.  Debt


Debt consists of the following: June 30, 2015December 31, 2014(millions, except percentages)DebtInterest RateDebtInterest RateCredit Facility, due October 3, 2018$——%$——%Capital Lease Obligations414—%413—%8.25% Senior Notes, due March 1, 20191,0008.25%1,0008.25%4.15% Senior Notes, due December 15, 20211,0004.15%1,0004.15%7.25% Senior Notes, due October 15, 20231007.25%1007.25%3.90% Senior Notes, due November 15, 20246503.90%6503.90%8.00% Senior Notes, due April 1, 20272508.00%2508.00%6.00% Senior Notes, due March 1, 20418506.00%8506.00%5.25% Senior Notes, due November 15, 20431,0005.25%1,0005.25%5.05% Senior Notes, due November 15, 20448505.05%8505.05%7.25% Senior Debentures, due August 1, 2097847.25%847.25%Total6,1986,197Unamortized Discount(25)(26)Total Debt, Net of Discount6,1736,171Less Amounts Due Within One YearCapital Lease Obligations(61)(68)Long-Term Debt Due After One Year$6,112$6,103


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





Note 8.  Fair Value Measurements and Disclosures


Assets and Liabilities Measured at Fair Value on a Recurring Basis


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


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


Mutual Fund Investments Our mutual fund investments, 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 6. Derivative Instruments and Hedging Activities .


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


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 Noble Energy, Inc.
 Notes to Consolidated Financial Statements


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


Fair Value Measurements 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, 2015Financial AssetsMutual Fund Investments$112$—$—$—$112Commodity Derivative Instruments—559—(3)556Financial LiabilitiesCommodity Derivative Instruments—(3)—3—Portion of Deferred Compensation Liability Measured at Fair Value(130)———(130)December 31, 2014Financial AssetsMutual Fund Investments$111$—$—$—$111Commodity Derivative Instruments—890—890Financial LiabilitiesCommodity Derivative Instruments—————Portion of Deferred Compensation Liability Measured at Fair Value(134)———(134)





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

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

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

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

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis


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


Asset Impairments Information about impaired assets is as follows: Fair Value Measurements UsingDescriptionQuoted Prices in Active Markets(Level 1)Significant OtherObservable Inputs(Level 2)SignificantUnobservableInputs   (Level 3)Net Book Value(1)Total Pre-tax (Non-cash) Impairment LossmillionsThree Months Ended June 30, 2015Impaired Oil and Gas Properties$—$—$—$15$15Three Months Ended June 30, 2014Impaired Oil and Gas Properties——84234Six Months Ended June 30, 2015Impaired Oil and Gas Properties$—$—$—$43$43Six Months Ended June 30, 2014Impaired Oil and Gas Properties——14145131


(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% .  Impairments for the first six months of 2015 were due primarily to increases in asset carrying values associated with increases in estimated field abandonment costs. See Note 5. 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.


Fair value information regarding our debt is as follows: June 30, 2015December 31, 2014(millions)Carrying AmountFair ValueCarrying AmountFair ValueTotal Debt, Net of Unamortized Discount(1)$5,759$6,103$5,758$6,179


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

Note 9.  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, 2015Capitalized Exploratory Well Costs, Beginning of Period$1,337Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves134Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves(12)Capitalized Exploratory Well Costs Charged to Expense(1)(17)Capitalized Exploratory Well Costs, End of Period$1,442





(1) Relates primarily to onshore US exploration activity.





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, 2015December 31, 2014Exploratory Well Costs Capitalized for a Period of One Year or Less$262$247Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling1,1801,090Balance at End of Period$1,442$1,337Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling1413





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 Noble Energy, Inc.
 Notes to Consolidated Financial Statements


The following table includes exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling as of June 30, 2015 : (millions)Total by ProjectProgressCountry/Project:Onshore USNortheast Nevada$31Analyzing results from our first four exploratory vertical wells and evaluating potential for production tests.Deepwater Gulf of MexicoKatmai43Anticipate drilling an appraisal well in 2016 to test the resource potential of this 2014 crude oil discovery.Troubadour48Evaluating development scenarios for this 2013 natural gas discovery including subsea tieback to existing infrastructure.Offshore Equatorial Guinea (Blocks O and I)Diega/Carmen229Evaluating regional development scenarios for this 2008 crude oil discovery. We drilled subsequent appraisal wells. During 2014, we conducted additional seismic activity over Blocks O and I and are engaged in processing the newly-acquired seismic data.Carla166Evaluating regional development scenarios for this 2011 crude oil discovery. We drilled subsequent appraisal wells. During 2014, we conducted additional seismic activity over Blocks O and I and are engaged in processing the newly-acquired seismic data.Felicita39Evaluating regional development plans for this 2008 condensate and natural gas discovery. A natural gas development team is working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options and finalize a data exchange agreement between the two countries.Yolanda20Evaluating regional development plans for this 2007 condensate and natural gas discovery. A natural gas development team is working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options and finalize a data exchange agreement between the two countries.Offshore CameroonYoYo48Working with the government to assess commercialization of this 2007 condensate and natural gas discovery. A natural gas development team is working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options and finalize a data exchange agreement between the two countries.Offshore Israel(1)Leviathan187During 2014, we received the Leviathan Development and Production Leases, submitted a development plan to the Israeli government, completed substantial engineering and procurement activities and engaged in natural gas marketing activities.


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 Noble Energy, Inc.
 Notes to Consolidated Financial Statements


Leviathan-1 Deep80Well did not reach the target interval; developing future drilling plans to test this deep oil concept, which is held by the Leviathan Development and Production Leases. We are working on potential well design and placement.Dalit28Submitted a development plan to the Israeli government to develop this 2009 natural gas discovery as a tie-in to existing infrastructure.Dolphin 125Reviewing regional development scenarios for this 2011 natural gas discovery, including a potential tieback to Leviathan. We have applied to the Israeli government for a commerciality ruling.Offshore CyprusCyprus208Submitted a Declaration of Commerciality and a Preliminary Development Plan for Block 12 with the government of Cyprus.OtherIndividual Projects Less than $20 million28Continuing to drill and evaluate wells.Total$1,180


(1) We are currently working to resolve antitrust and other regulatory matters with the Israeli government to enable Leviathan and other development to move forward. See Note 2. Basis of Presentation – Update on Core Area – Israel .





Note 10.  Asset Retirement Obligations


Asset retirement obligations (ARO) consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Changes in ARO are as follows: Six Months EndedJune 30,(millions)20152014Asset Retirement Obligations, Beginning Balance$751$586Liabilities Incurred1622Liabilities Settled(15)(43)Revision of Estimate79120Accretion Expense(1)2119Asset Retirement Obligations, Ending Balance$852$704


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


For the six months ended June 30, 2015


Liabilities incurred were due to new wells and facilities for onshore US and deepwater Gulf of Mexico. Liabilities settled relate primarily to non-core, onshore US properties sold.


Revisions in estimate related to changes in cost estimates and included $43 million for Eastern Mediterranean and $28 million for DJ Basin.


For the  six months ended June 30, 2014


Liabilities incurred were due to new wells and facilities for onshore US and Eastern Mediterranean. Liabilities settled primarily related to onshore US property abandonments and non-core, onshore US assets sold.


Revisions in estimate included $67 million for the North Sea McCulloch field due to an increase in costs and a change in timing. See Note 5. Asset Impairments . Additional revisions of $21 million for DJ Basin, $16 million for Equatorial Guinea, $9 million for Eastern Mediterranean, and $7 million for deepwater Gulf of Mexico were due to changes in cost and timing estimates.


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 Noble Energy, Inc.
 Notes to Consolidated Financial Statements


Note 11.  Earnings Per Share


Basic earnings per share of common stock is computed using the weighted average number of shares of common stock outstanding during each period. The diluted earnings per share of common stock include the effect of outstanding stock options, shares of restricted stock, or shares of our common stock held in a rabbi trust (when dilutive). The following table summarizes the calculation of basic and diluted earnings per share: Three Months Ended June 30,Six Months EndedJune 30,(millions, except per share amounts)2015201420152014Net Income (Loss)$(109)$192$(131)$392Weighted Average Number of Shares Outstanding, Basic(1)387361378361Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust(2)—5—4Weighted Average Number of Shares Outstanding, Diluted387366378365Earnings (Loss) Per Share, Basic$(0.28)$0.53$(0.35)$1.09Earnings (Loss) Per Share, Diluted(0.28)0.52(0.35)1.07Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above10394


|    |                                                                                                                                                                                                                                           
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | The weighted average number of shares outstanding includes the weighted average shares of common stock issued in connection with the underwritten public offering of24,150,000shares of common stock of the Company in first quarter 2015.

|    |                                                                                                                                                                                                                                                                                                                                         
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(2) | For the three and six months ended June 30, 2015, all outstanding options and non-vested restricted shares have been excluded from the calculation of diluted EPS as the Company incurred losses. Therefore, inclusion of outstanding options and non-vested restricted shares in the calculation of diluted EPS would be anti-dilutive.







Note 12.  Income Taxes


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


Three Months Ended June 30,Six Months EndedJune 30,(millions)2015201420152014Current$99$34$109$94Deferred(283)7(312)24Total Income Tax (Benefit) Provision$(184)$41$(203)$118Effective Tax Rate62.8%17.6%60.8%23.1%





Our effective tax rate (ETR) for the six months ended June 30, 2015 increased as compared with the six months ended June 30, 2014 primarily as a result of a tax benefit divided by a pre-tax loss. In the case of a pre-tax loss, our favorable permanent differences, such as income from equity method investees and increased earnings in our foreign jurisdictions with rates that vary from the US statutory rate, have the effect of increasing the tax benefit which, in turn, increases the ETR.


In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US – 2011 , Equatorial Guinea – 2010 and Israel – 2010 .


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 Noble Energy, Inc.
 Notes to Consolidated Financial Statements


Note 13.  Segment Information


We have operations throughout the world and manage our operations by country. The following information is grouped into four components that are all in the business of crude oil and natural gas exploration, development, production, and acquisition: the United States; West Africa (Equatorial Guinea, Cameroon, Gabon, and Sierra Leone); Eastern Mediterranean (Israel and Cyprus); and Other International and Corporate. Other International includes the North Sea, China (through June 30, 2014), Falkland Islands, Nicaragua (which we have exited) and new ventures. (millions)ConsolidatedUnitedStatesWestAfricaEasternMediterraneanOther Int'l &CorporateThree Months Ended June 30, 2015Revenues from Third Parties$722$441$174$106$1Income (Loss) from Equity Method Investees68(2)——Other22———Total Revenues7304511721061DD&A451344791513Gain on Divestitures(1)(1)———Asset Impairments158—7—Loss on Commodity Derivative Instruments876225——Income (Loss) Before Income Taxes(293)(163)2369(222)Three 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—142Loss on Commodity Derivative Instruments23617066——Income (Loss) Before Income Taxes23319920444(214)Six Months Ended June 30, 2015Revenues from Third Parties$1,462$919$312$226$5Income from Equity Method Investees24195——Other44———Total Revenues1,4909423172265DD&A9057011563018Gain on Divestitures—————Asset Impairments4311—32—Gain on Commodity Derivative Instruments(63)(43)(20)——Income (Loss) Before Income Taxes(334)(164)97120(387)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—1494Loss on Commodity Derivative Instruments31124665——Income (Loss) Before Income Taxes510382465121(458)June 30, 2015Total Assets$22,685$16,755$2,628$2,802$500December 31, 2014Total Assets22,55316,4002,7632,806584








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 Noble Energy, Inc.
 Notes to Consolidated Financial Statements


Note 14.  Commitments and Contingencies


CONSOL Carried Cost Obligation In accordance with our Marcellus Shale joint venture arrangement with a subsidiary of CONSOL Energy Inc. (CONSOL), we agreed to fund one-third of CONSOL's 50% working interest share of future drilling and completion costs, capped at $400 million each year (CONSOL Carried Cost Obligation). The remaining obligation totaled approximately $1.6 billion at June 30, 2015 .


The CONSOL Carried Cost Obligation is suspended if average Henry Hub natural gas prices fall and remain below $4.00 per MMBtu in any three consecutive month period and remain suspended until average Henry Hub natural gas prices equal or exceed $4.00 per MMBtu for three consecutive months. The CONSOL Carried Cost Obligation is currently suspended due to low natural gas prices. Based on the June 30, 2015 NYMEX Henry Hub natural gas price curve, we expect that the CONSOL Carried Cost Obligation will be suspended for the next 12 months.


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. Our legacy core operating areas include 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 attractive returns. We also seek to enter potential new core areas, and recently completed a merger with Rosetta Resources Inc. (Rosetta), an onshore US company with operating assets in the Eagle Ford Shale and Permian Basin. We are also conducting exploration activities in domestic and international locations such as Northeast Nevada, the Falkland Islands, Cameroon, and Gabon.


Second Quarter 2015 Significant Operating Highlights Included:


|  |                                                                                                                              
|- | -----------------------------------------------------------------------------------------------------------------------------
|• | announced the Rosetta Merger, resulting in our entry into the Eagle Ford Shale and Permian Basin (see Rosetta Merger, below);

|  |                                                                                                                
|- | ---------------------------------------------------------------------------------------------------------------
|• | continued cost reduction efforts and actively managed our capital spending (see Cost Reduction Efforts, below);

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|- | --------------------------------------------------------------------------------------------------------------
|• | achieved substantial progress on the regulatory framework in Israel (see Update on Core Area – Israel, below);

|  |                                                                                                                                                              
|- | -------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | prepared to spud the Cheetah prospect (drilling commenced in early July 2015) which represents our first Cretaceous crude oil prospect offshore Cameroon; and

|  |                                                                                                                        
|- | -----------------------------------------------------------------------------------------------------------------------
|• | submitted a Declaration of Commerciality and a Preliminary Development Plan for Block 12 with the government of Cyprus.

Second Quarter 2015 Financial Results Included:


|  |                                                                                         
|- | ----------------------------------------------------------------------------------------
|• | net loss of$109 million, as compared with net income of$192 millionforsecondquarter2014;

|  |                                                                                                                                                                                                                                        
|- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | net loss on commodity derivative instruments of$87 million(including$274 millionnon-cash loss) as compared with a net loss on commodity derivative instruments of$236 million(including$187 millionnon-cash loss) forsecondquarter2014;

|  |                                                                                                         
|- | --------------------------------------------------------------------------------------------------------
|• | diluted loss per share of$0.28, as compared with diluted earnings per share of$0.52forsecondquarter2014;

|  |                                                                                                                    
|- | -------------------------------------------------------------------------------------------------------------------
|• | cash flow provided by operating activities of $425 million, as compared with $828 million forsecondquarter2014; and

|  |                                                                                         
|- | ----------------------------------------------------------------------------------------
|• | capital expenditures of$799 million, as compared with $1.3 billion forsecondquarter2014.

Quarter-End Key Financial Metrics Included:


|  |                                                                                     
|- | ------------------------------------------------------------------------------------
|• | ending cash balance of$1.3 billion, as compared with$1.2 billionatDecember 31, 2014;

|  |                                                                                                    
|- | ---------------------------------------------------------------------------------------------------
|• | total liquidity of$5.3 billionatJune 30, 2015, as compared with$5.2 billionatDecember 31, 2014; and

|  |                                                                                              
|- | ---------------------------------------------------------------------------------------------
|• | ratio of debt-to-book capital of36%atJune 30, 2015, as compared with 38% atDecember 31, 2014.

Rosetta Merger


On July 20, 2015, Rosetta stockholders approved the merger of Rosetta into a subsidiary of Noble Energy. This transaction adds two premier onshore US shale plays: the Eagle Ford Shale and Permian Basin. Rosetta's liquids-rich asset base includes approximately 50,000 net acres in the Eagle Ford and 54,000 net acres in the Permian (45,000 acres in the Delaware Basin and 9,000 acres in the Midland Basin), and we have identified more than 1,800 gross horizontal drilling locations for development. Rosetta's assets produced 63 MBoe/d in second quarter 2015, and year-end 2014 proved reserves were 282 MMBoe. More than


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60% percent of Rosetta's current production and proved reserves are liquids. See Item 1. Financial Statements - Note 3 Rosetta Merger .


Cost Reduction Efforts


During the first six months of 2015, we have focused on enhancing overall performance, maximizing operating efficiencies, and maintaining our strong safety culture. Engagement in cost reduction initiatives, including both operational enhancements and new pricing arrangements with service partners, has resulted in reduced unit costs, including lease operating and general and administrative expense. In addition, we have actively managed our capital spending by, among other things, reducing activity in our core onshore US areas, and we are moving toward a cash flow neutral position that provides flexibility in this commodity price cycle downturn. The relocation of our accounting department from Ardmore, Oklahoma to Houston, Texas and other corporate restructuring activities resulted in corporate restructuring expense of $18 million and stacked rig expense of $7 million during second quarter 2015. See also Operating Outlook – 2015 Capital Investment Program below.


Sales Volumes


On a BOE basis, total sales volumes were 3%  higher for second quarter 2015 as compared with second quarter 2014 , and our mix of sales volumes was 43% global liquids, 23% international natural gas, and 34% US natural gas. See Results of Operations – Revenues, below.


Commodity Price Changes


The upstream oil and gas business is cyclical. During 2014, natural gas prices declined steadily, and, during fourth quarter 2014, a significant decline in crude oil prices occurred. During the first six months of 2015, commodity prices have continued to trade in a low range, or decline further. In addition, location differentials have increased in some regions, such as the Marcellus Shale, resulting in further declines in natural gas prices. For second quarter 2015 , our consolidated average realized prices decreased  46% for crude oil, 34% for natural gas and 72% for NGLs as compared with second quarter 2014 .


We are unable to predict the extent to which commodity prices may recover during the remainder of 2015. Prices are likely to remain volatile and could decline further. In addition, we could be entering a period of sustained lower prices.


We plan for these cyclical downturns in our business and feel we are well positioned to withstand current and future commodity price volatility:


|  |                                                                                              
|- | ---------------------------------------------------------------------------------------------
|• | we have a high-quality, diversified portfolio of assets which provide investment flexibility;

|  |                                                                                                                                 
|- | --------------------------------------------------------------------------------------------------------------------------------
|• | we have achieved cost reductions impacting both operating expenses and capital items, positively impacting operating cash flows;

|  |                                                                                                                                     
|- | ------------------------------------------------------------------------------------------------------------------------------------
|• | we have designed a substantially-reduced capital investment program which will allow us to respond to conditions that occur in 2015;

|  |                                                                                           
|- | ------------------------------------------------------------------------------------------
|• | we are well hedged for the remainder of 2015, with additional quantities hedged into 2016;

|  |                                                                                              
|- | ---------------------------------------------------------------------------------------------
|• | we have a strong balance sheet with a ratio of debt-to-book capital of36%atJune 30, 2015; and

|  |                                                                             
|- | ----------------------------------------------------------------------------
|• | we have robust liquidity with total liquidity of$5.3 billionatJune 30, 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 currently have a position in excess of 400,000 net acres, the majority of which are included within our integrated development plan (IDP) areas. During the quarter, we operated four drilling rigs, drilled 44 horizontal wells and commenced production on 46 wells.  Also during the quarter, our 100% owned Keota natural gas processing plant in the East Pony IDP area commenced operation. Third party infrastructure also continued to expand, including the start-up of the third-party Lucerne-2 natural gas processing plant. The Lucerne capacity, along with recently-completed compression projects in the region, should result in lower line pressures and increase future production flow.


Marcellus Shale (Onshore US) During the quarter, we and our joint venture partner each averaged two horizontal drilling rigs. We drilled 20 operated wells and commenced production on 19 operated wells. Our joint venture partner drilled 15 wells and commenced production on 11 wells. In response to the lower natural gas and NGL pricing environment, we and our partner expect to reduce drilling and completion activity during the second half of 2015.


Gunflint (Deepwater Gulf of Mexico) Development is on track for the Gunflint (31% operated working interest) crude oil discovery, utilizing a two-well subsea tieback to the Gulfstar 1 spar. During second quarter 2015, we successfully drilled a development well and commenced drilling a second development well.  First production is targeted for mid-2016.


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Big Bend and Dantzler (Deepwater Gulf of Mexico) A co-development project is underway for the Big Bend (54% operated working interest) and Dantzler (45% operated working interest) crude oil discoveries, located in the Rio Grande area of the deepwater Gulf of Mexico, which will tie back to the Thunder Hawk semi-submersible production facility. Big Bend pipeline installation is nearly complete and first production is targeted for fourth quarter 2015. First production for Dantzler is targeted near the end of 2015.


Alba Field (Offshore Equatorial Guinea) During second quarter 2015, the field operator successfully drilled the C-21 development well, which will commence production in third quarter 2015. Additionally, the multi-year compression project continues as planned with start-up in mid-2016.


Ashdod Onshore Terminal Compression Project (Onshore Israel) The compression project, increasing peak natural gas deliverability at Tamar to 1.2 Bcf/d, gross, has been completed.


Tamar Southwest We continue 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 suspended the project. We have petitioned the Israeli courts to expedite the needed approvals. Timely development of Tamar Southwest is important to maintain well capacity and reliability for our overall Tamar project. See Update on Core Area – Israel, below.


North Sea During second quarter 2015, the operator of the MacCulloch field commenced decommissioning activities.


Unsanctioned Development Projects


Tamar Expansion Project (Offshore Israel) We have engaged in the planning phase for an expansion project which would expand Tamar field deliverability to approximately 2.0 Bcf/d. Timing of project sanction depends on satisfactory resolution of antitrust and other regulatory matters. See Update on Core Area – Israel, below.


Leviathan Project (Offshore Israel) In 2014, we submitted the Plan of Development to the Ministry of National Infrastructures, Energy and Water Resources. The development plan is expected to serve both domestic demand and export. Timing of project sanction depends on satisfactory resolution of antitrust and other regulatory matters, including adoption of a framework intended to address and clarify many of the outstanding regulatory issues we and our partners face in developing our offshore assets, as well as execution of natural gas sales and purchase agreements, which will be subject to, among other conditions, the receipt of regulatory approvals. Project financing will also be required. We are engaged with the governments of the US, Israel, Jordan and Egypt on this project. See Update on Core Area – Israel, below.


Cyprus Project (Offshore Cyprus) During second quarter 2015, we submitted a Declaration of Commerciality and a Preliminary Development Plan for Block 12 (Aphrodite, 70% operated working interest) with the government of Cyprus.  We and our partners are performing pre-FEED work for a potential development that envisions a regional natural gas export project to potential natural gas customers in Cyprus and Egypt.  There is also potential for a farm-out arrangement of our working interest.


See Item 1. Financial Statements – Note 9. Capitalized Exploratory Well Costs .


Exploration Program Update


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


We were in the process of drilling and/or evaluating significant exploratory wells at June 30, 2015 , and expect to conduct additional exploratory activities.


A portion of our 2015 capital investment program is dedicated to exploration and associated appraisal activities. 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 recorded as dry hole expense.


Additionally, we may not be able to conduct exploration activities prior to lease expirations. As a result, in a future period, dry hole cost and/or leasehold abandonment expense could be significant. See Item 1. Financial Statements – Note 9. Capitalized Exploratory Well Costs and Operating Outlook – Potential for Future Impairment, Dry Hole or Lease Abandonment Expense, below.


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Updates on significant exploration activities are as follows:


Northeast Nevada We have drilled four exploratory wells to date. To assess commercial viability, further testing is underway, including a production test of the third exploration well drilled. Additional exploration and appraisal plans are being developed.


Deepwater Gulf of Mexico We currently have an inventory of identified prospects, which are a combination of both high impact subsalt prospects and smaller, high value tie-back opportunities. These prospects are subject to an ongoing technical maturation process and may or may not emerge as drillable options. We are actively assessing exploration and appraisal drilling activity necessary to test the resource potential of our Katmai discovery from third quarter 2014 (Green Canyon Block 40, 50% operated working interest). We anticipate drilling a Katmai appraisal well in 2016.


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


In July 2015, we spud the Cheetah exploration prospect on the Tilapia license (46.67% working interest) and expect to complete drilling activities in third quarter 2015. We are also reprocessing 3D seismic data over our YoYo mining concession.


Also, during second quarter 2015, we exited our acreage position offshore Sierra Leone.


Offshore Eastern Mediterranean See Update on Core Area – Israel, below.


Offshore Falkland Islands Drilling operations began at the Humpback prospect (35% operated working interest), located in the South Falkland Basin, in June 2015 and we expect to complete drilling activities in third quarter 2015. In addition, we recently acquired a 75% interest and operatorship of the PL001 License in the North Falkland Basin. The PL001 License covers an area of approximately 280,000 gross acres. We have identified the Rhea prospect as the initial target on the PL001 License and expect to commence drilling in third quarter 2015.


An Argentine court has initiated a criminal investigation against Noble and other oil and gas companies regarding their exploration activities offshore Falkland Islands.  The court has also issued a preservation order against the relevant companies to preserve assets in the event of any judgment. The investigation is premised on Argentina’s claim that the Falkland Islands are a part of its territory. Argentina does not recognize the United Kingdom’s sovereignty over the Falkland Islands or the Falkland Islanders rights to exploit their natural resources. The Falkland Islands are part of the United Kingdom’s overseas territories and are afforded full self-governance. Our concessions are with the Falkland Islands Government and we do not believe that Argentina has any authority over our operations in the Falkland Islands.


Update on Core Area – Israel


Noble Energy and its partners have remained committed to providing natural gas to Israeli citizens for over a decade. We have delivered approximately 1.3 Tcf, gross, of natural gas to Israeli customers, including the Israel Electric Corporation (IEC), the largest supplier of electricity in the country.


Since obtaining our first exploration license in 1998, Noble Energy has been the first, and only, oil and natural gas company to successfully explore for significant amounts of hydrocarbons in Israel. We are also the first company to construct, operate and produce from a major development project offshore Israel. We have invested significant amounts of capital in exploration and development activities since 1998. Throughout this time, we have focused on partnering with our customers and the Israeli government to provide a reliable fuel source at reasonable prices to support affordable energy for the State of Israel’s citizens.


Since our initial discovery at Mari-B in 2000, we and our partners have continued to reinvest for long-term growth, leasing additional acreage and conducting exploration activities offshore Israel, in pursuit of additional resources to meet increasing demand from Israeli consumers and global markets. Our exploration efforts resulted in numerous natural gas discoveries over the past several years. The Tamar and Leviathan discoveries, in particular, are large scale, high quality reservoirs, of global significance, providing substantial additional resources for the government and citizens of Israel. We developed the Tamar field, with a discovery to production cycle time of approximately four years, which is exceptionally fast by historical industry standards for an offshore natural gas project of this magnitude and complexity.


The quantity of discovered natural gas resources at Tamar and Leviathan have positioned Israel to meet domestic needs for decades to come and eventually become a significant natural gas exporter. Multiple regional markets are emerging and Israel’s domestic demand is predicted to continue to grow over the next decade. Eastern Mediterranean export projects would be well positioned to supply growing regional and global natural gas demand, which would provide benefits beyond satisfying domestic consumption of natural gas. In fact, we have been working with potential customers to supply natural gas through a regional pipeline system and/or LNG facilities. Government export royalties and tax revenues related to regional export sales would provide material financial benefit for Israel’s citizens.


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In addition to our natural gas discoveries, the Levant Basin also has potential for large scale crude oil discoveries, which may exist at greater depths. We have conducted preliminary exploration activities and have been planning to complete our test of two deeper intervals.


We have been working with the Israeli government on plans to develop the Leviathan field and expand the currently-producing Tamar field. However, the regulatory environment in Israel has become increasingly challenging and uncertain. Laws, regulations and guidelines have been modified, sometimes with retroactive impacts, resulting in an unpredictable investment climate. Timing of approval for development plans has been delayed, and consequently our ability to make significant, long-term investment decisions has been stymied.


Since 2011, following the discovery of Leviathan, we have been engaged with the Israeli government, including the Antitrust Commissioner, to reach agreement on various antitrust matters resulting from our significant resource ownership status. During 2014, we and our partners reached an agreement with the Israeli government on the antitrust matters (Consent Decree), which included an agreement to divest two of our natural gas discoveries, Tanin and Karish.


Acting in good faith upon the Consent Decree, we engaged in discussions with potential purchasers of the Tanin and Karish discoveries. We believed that the Consent Decree matter had been resolved and had received assurances from the Antitrust Authority that approval was forthcoming.


However, on December 23, 2014, the Israeli Antitrust Commissioner (Commissioner) reversed a decision to submit the agreed Consent Decree to the Israeli Antitrust Tribunal for approval. An oral hearing with the Antitrust Authority took place on January 27, 2015.


Because stable fiscal and regulatory regimes are imperative to support ongoing investment and sanction of major development projects, we determined that the resolution of the following items, and greater certainty with respect to Israeli fiscal and regulatory matters, would be required prior to sanction of a Leviathan development project, the Tamar expansion or other future development projects:


|  |                                                                                                       
|- | ------------------------------------------------------------------------------------------------------
|• | Approval of final gas sale and purchase agreements with off-takers, to support financing arrangements;

|  |                                                                      
|- | ---------------------------------------------------------------------
|• | Clear, economically viable tax rulings, including export tax rulings;

|  |                                                    
|- | ---------------------------------------------------
|• | Export approval with reasonable export allocations;

|  |                                   
|- | ----------------------------------
|• | Approvals of Plans of Development;

|  |                                                                                                   
|- | --------------------------------------------------------------------------------------------------
|• | Acceptable resolution of Leviathan and other pending matters with the Israeli Antitrust Authority;

|  |                   
|- | ------------------
|• | Timely permitting;

|  |                                                           
|- | ----------------------------------------------------------
|• | Prompt decisions regarding pipeline onshore landing sites;

|  |                                                                                                           
|- | ----------------------------------------------------------------------------------------------------------
|• | Other relevant regulatory terms critical to offshore crude oil and natural gas exploration and production;

|  |                                                                                                                                                                           
|- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | Stable fiscal and contract terms that allow for financial returns that are appropriate to support long-term investment by a global exploration and production company; and

|  |                                                                       
|- | ----------------------------------------------------------------------
|• | Stability clauses and protection from changes in laws and regulations.

In response to this situation, in late 2014, the Prime Minister's office established an inter-ministerial working group, led by the head of the National Economic Council, for the purpose of addressing outstanding regulatory matters and developing a comprehensive regulatory framework to support further investment in natural gas development. We have been engaged with the Israeli government inter-ministerial working group in an attempt to resolve these matters through the development of that framework.


During second quarter 2015, we continued to work to resolve regulatory matters with the Israeli government. On June 25, 2015, the Israeli Security Cabinet unanimously adopted a decision that empowers the government of Israel to exempt certain arrangements from the provisions of the Israeli Restrictive Trade Practices Law 1988 (the IRTPL). The Israeli government has published for public hearing a framework (Framework) to support development of offshore natural gas reserves including natural gas exports and is intended to address and clarify many of the outstanding regulatory issues we and our partners face in developing our offshore assets. Recently, the government conducted public hearings on the Framework and we understand the government is currently progressing toward final approval. Legal challenges may be brought against the Framework in the Israeli courts. Therefore, there can be no assurance as to when or if the Framework will be finalized or as to the terms thereof if finalized. If necessary, we are prepared to defend our legal rights to our Israel assets to the fullest extent in both domestic and international venues.


Although our development plans have been delayed as a result of recent government actions, described above, we believe that, given the quality of the natural gas resources and significant associated economic benefit to the citizens of Israel, which could total in the billions of dollars over the life of the fields, it is in the best interest of the Israeli government to ultimately support development, and we continue to expect that our discoveries will be developed, upon satisfactory resolution of the above matters. Therefore, we believe the risk of loss of our investment is remote as the value of these assets could be realized through ultimate development and/or sale to third parties. In addition, we would pursue any and all remedies for any damages incurred.


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As of June 30, 2015, our $2.1 billion investment in Israel includes: approximately $1.3 billion related to the currently-producing Tamar field; approximately $400 million related to the Leviathan natural gas discovery and suspended deep oil test; approximately $300 million related to the Tamar expansion project and previous discoveries which are awaiting sanction of development plans; and $77 million related to the Karish and Tanin discoveries, which are included in assets held for sale. We expect further capital expenditure to be minimized, pending resolution of regulatory matters.


Non-Core Divestiture Program


We periodically divest non-core, non-strategic assets. During the first six months of 2015, we continued our non-core asset divestiture program with the sale of certain smaller onshore US property packages resulting in net proceeds of $151 million. Divestitures of non-core properties allow us to allocate capital and other resources to high-value and high-growth areas. See Item 1. Financial Statements – Note 4. Divestitures  and Operating Outlook - Potential for Future Impairment, Dry Hole or Lease Abandonment Expense , below.


Colorado Air Matter


In August 2013, we received an information request from the EPA under Section 114 of the Clean Air Act regarding several tank batteries used in our DJ Basin operations. The information request relates to our compliance with certain regulatory requirements at those locations, including air emissions of volatile organic compounds in a marginal ozone non-attainment area. We responded to the EPA’s information requests between November 2013 and April 2014 and, in April 2015, reached a settlement with the EPA and the State of Colorado regarding potential noncompliance with the Clean Air Act, Colorado's State Implementation Plan, Colorado's Air Pollution Prevention and Control Act and its implementation regulations. See Part II. Other Information – Item 1. Legal Proceedings .


Update on Regulations


Hydraulic Fracturing  Rules


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.


On March 26, 2015, the US Interior Department's Bureau of Land Management (BLM) published a final rule regulating hydraulic fracturing on public and Indian lands. The new rules include requirements related to well-bore integrity, wastewater disposal and public disclosure of chemicals. Key components of the rule, which took effect on June 24, 2015, include:


• provisions for ensuring the protection of groundwater supplies by requiring a validation of well integrity and strong cement barriers between the wellbore and water zones through which the wellbore passes;


• increased transparency by requiring companies to publicly disclose chemicals used in hydraulic fracturing to the Bureau of Land Management through the website FracFocus, within 30 days of completing fracturing operations;


• higher standards for interim storage of recovered waste fluids from hydraulic fracturing to mitigate risks to air, water and wildlife; and


• measures to lower the risk of cross-well contamination with chemicals and fluids used in the fracturing operation, by requiring companies to submit more detailed information on the geology, depth, and location of preexisting wells to afford the BLM an opportunity to better evaluate and manage unique site characteristics.


We are currently reviewing the final rules to determine the impacts, including additional costs and reporting burdens and increased cycle time for permit approval, they may have on our operations on federal land, including our federal units in Nevada.


Nevada Regulations


In September 2014, Nevada state regulators finalized regulations for the use of hydraulic fracturing in crude oil and natural gas development. The regulatory program includes requirements for groundwater baseline sampling and monitoring, water resource and wastewater disposal requirements, chemical disclosure requirements and mandates for extra casing for unconventional wells. We actively participated in the program's development and do not believe it will have a material impact on our activities.


Proposed Offshore Drilling Regulations


On April 13, 2015, the US Department of the Interior announced proposed regulations which include more stringent design requirements and operational procedures for critical well control equipment used in offshore oil and gas operations.


The proposed rule, which will be open for public comment, addresses the range of systems and equipment related to well control operations. The measures are designed to improve equipment reliability, building upon enhanced industry standards for blowout preventers and blowout prevention technologies. The rule also includes reforms in well design, well control, casing, cementing, real-time well monitoring and subsea containment. We will continue to monitor the development of these new


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regulations to determine the impacts, including additional costs and reporting burdens, on our deepwater Gulf of Mexico operations.


Endangered Species Act


The US Fish and Wildlife Service (FWS), under the Endangered Species Act (ESA), has regulatory authority over our exploration for, and production and sale of, crude oil, natural gas and NGLs and activities that may result in the take of any endangered or threatened species or its habitat. The FWS recently listed the northern long-eared bat as threatened under the ESA, which could have an impact on the timing of certain of our operations in the Marcellus Shale.


Clean Water Rule


In May 2015, the US Environmental Protection Agency and the US Army Corps of Engineers jointly released a final rule that is meant to define more precisely which water bodies are and are not subject to the Clean Water Act (the Clean Water Rule). Among other things, the Clean Water Rule defines the intermittent, ephemeral, and man-altered streams to be protected and specifies when federal jurisdiction may be extended from a covered water to nearby waters. While the agencies have claimed that the new requirements are narrower than existing regulation, the Clean Water Rule has generated substantial controversy. Several court challenges have been filed, and legislation has been introduced in Congress to require changes. To the extent that the Clean Water Rule requires more detailed studies of site conditions, or results in an expansion of federal jurisdiction over streams and wetlands, our costs may increase, especially with respect to spill prevention, storm water management, and wetlands permitting. We are currently evaluating the impact of the new rule on our operations.


Colorado Task Force


In 2014, by executive order, Colorado Governor Hickenlooper created the Task Force on State and Local Regulation of Oil and Gas Operations (Task Force) for the purpose of recommending policies and legislation. The 21-member Task Force, which included a Noble Energy representative, concluded its activities on February 27, 2015. The Task Force sent nine recommendations to the governor. The recommendations seek to balance land use issues among communities and oil and gas operators and allow reasonable access to private mineral rights. Three recommendations have been approved by the legislature and state regulators will soon begin public outreach meetings in five communities around the state to solicit comments to help shape a draft rulemaking targeted for fourth quarter 2015.


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


Recently Issued Accounting Standards


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


OPERATING OUTLOOK


2015 Production Our expected crude oil, natural gas and NGL production for 2015 may be impacted by several factors including:


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

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

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|• | the level of horizontal drilling activity in our onshore US shale areas;

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|• | decline in our DJ Basin legacy vertical well production and capacity constraints of midstream facilities serving those wells;

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|• | timing of start-up of a low pressure line-loop system, performance of gathering and processing infrastructure, and occurrence of other events which impact capacity constraints of midstream facilities serving our DJ Basin wells;

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|• | integration and timing of new wells in the Eagle Ford and Permian as a result of the Rosetta Merger;

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|• | timing of start-up of the Big Bend and Dantzler projects (deepwater Gulf of Mexico);

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|• | 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;

|  |                                                                                                                                                                                                                                                
|- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | variations in West Africa crude oil and condensate sales volumes due to potential Aseng FPSO downtime and timing of liftings, and variations in natural gas sales volumes related to potential downtime at the methanol, LPG and/or LNG plants;

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

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

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

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|• | pending Alba and Alen field unitizations in West Africa;

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

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

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|• | potential purchases of producing properties or divestments of non-core operating assets.

2015 Capital Investment Program Given the current commodity price environment with low prices and an industry cost structure that has yet to fully reset to lower revenue levels, we have designed a substantially-reduced capital investment program that is appropriate for the current price environment and will be responsive to conditions that develop during 2015. Our 2015 capital program accommodates an investment level of approximately $2.9 billion for our existing assets, which represents an approximate 40% reduction from 2014. The program initially allocated more than 60% of total investment to core onshore US assets and 35% for global offshore development activities including the deepwater Gulf of Mexico, and approximately 5% for global offshore exploration.


On July 20, 2015, we completed the Rosetta Merger. We currently plan to allocate an incremental $165 million capital to the Eagle Ford and Permian assets.


The 2015 capital investment program may be funded from cash flows from operations, cash on hand, proceeds from divestments of non-core assets, borrowings under our Credit Facility and/or other financings. We are targeting a cash neutral position, whereby the capital investment program is at, or below, operating cash flows, for the second half of 2015. See Liquidity and Capital Resources – Financing Activities .


Potential for Future Impairments, 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, during the first six months of 2015, we recorded dry hole expense of $12 million related to onshore US exploratory wells. See Item 1. Financial Statements - Note  9. Capitalized Exploratory Well Costs .


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


We currently have capitalized undeveloped leasehold cost  in excess of $300 million related to deepwater Gulf of Mexico prospects that have not yet been drilled. These leases will expire over the years 2015 - 2024. In particular, one of these leases was acquired under regulations in effect prior to the Deepwater Gulf of Mexico Moratorium. We have been working to mature the prospect and identified a potential subsalt hydrocarbon-bearing formation below 25,000 feet. The lease passed its expiration date of July 31, 2014; however, BSEE has approved an application for a suspension of operations (SOO). According to SOO terms, we must commit, by October 31, 2015, to drilling an exploratory well and commence drilling of the well by October 31, 2016. If we are unable to comply with approved SOO terms, the lease will expire and associated costs will be written off to exploration expense. The lease had a net book value of $42 million at June 30, 2015.


Producing Properties Commodity prices remain volatile. A decline in future crude oil, natural gas or NGL prices could result in impairment charges, decrease in proved reserves and/or shut-in of currently producing wells. The cash flow model that we use to assess proved properties for impairment includes numerous assumptions, such as management’s estimates of future crude oil and natural gas production along with operating and development costs, market outlook on forward commodity prices, and interest rates. All inputs to the cash flow model must be evaluated at each date of estimate. However, a decrease in forward crude oil or natural gas prices alone could result in an impairment.


In addition, well decommissioning programs, especially in deepwater or remote locations, are often complex and expensive. It may be difficult to estimate timing of actual abandonment activities, which are subject to regulatory approval and the availability of rigs and services. It may 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. 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


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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, 2015 . 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 .


Goodwill Our US reporting unit included $616 million of goodwill as of June 30, 2015. We assess goodwill for impairment at least annually at the reporting unit level. Relevant events and circumstances which could have a negative impact on goodwill include macroeconomic conditions; industry and market conditions, such as commodity prices; operating cost factors; overall financial performance; the impact of dispositions and acquisitions; and other entity-specific events. Further declines in commodity prices or sustained lower valuation for our common stock could indicate a reduction in our estimate of reporting unit fair value which, in turn, could lead to an impairment of reporting unit goodwill. We will continue to monitor events and circumstances which could have a negative impact on our estimates of reporting unit fair value.


RESULTS OF OPERATIONS


Revenues


Revenues were as follows: (Decrease)from Prior Year(millions)20152014Three Months Ended June 30,Oil, Gas and NGL Sales$722$1,338(46)%Income from Equity Method Investees645(87)%Other2—N/MTotal$730$1,383(47)%Six Months Ended June 30,Oil, Gas and NGL Sales$1,462$2,665(45)%Income from Equity Method Investees2497(75)%Other4—N/MTotal$1,490$2,762(46)%


N/M amount is not meaningful.


Changes in revenues are discussed below.


Oil, Gas and NGL Sales


We generally sell crude oil, natural gas, and NGLs under two types of agreements common in our industry.  Both types of agreements may include transportation charges.  One type of agreement is a netback agreement, under which we sell crude oil and natural gas at the wellhead and receive a price, net of transportation expense incurred by the purchaser.  In this case, we record crude oil and natural gas revenue at the net price we received from the purchaser.  In the case of NGLs, we may receive a price from the purchaser, which is net of processing costs. In this case, we record NGL revenue at the net price we receive from the purchaser. The second type of agreement is one whereby we pay transportation expense directly. In that case, transportation expense is included within production expense in our consolidated statements of operations.


In addition, commodity prices we receive may be reduced by location basis differentials, which can be significant.  As a result of both netback agreements and location basis differentials, our reported sales prices may differ significantly from published commodity price benchmarks for the same period.


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Average daily sales volumes and average realized sales prices were as follows: Sales 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, 2015United States6561327194$52.44$1.90$9.64Equatorial Guinea(2)31202—6560.020.27—Israel—215—36—5.34—Other International(3)———————Total Consolidated Operations961,0302729554.912.309.64Equity Investees(4)1—3460.34—33.34Total971,03030299$54.95$2.30$12.05Three 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—64.86Total10693528290$102.62$3.50$40.70Six Months Ended June 30, 2015United States6961626198$48.20$2.31$12.00Equatorial Guinea(2)30216—6654.970.27—Israel—229—38—5.40—Other International(3)1——155.52——Total Consolidated Operations1001,0612630350.292.5612.00Equity Investees(4)1—4651.86—31.27Total1011,06130309$50.31$2.56$14.83Six 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—69.70Total10693926288$101.47$3.66$45.71


|    |                                                                                                                                                                                                                                                                                                                                                                           
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(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 both natural gas  and NGL are significantly less than the price for a barrel of crude oil.

|    |                                                                                                                                                                                                                                                                                           
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(2) | Natural gas from the Alba field in Equatorial Guinea is under contract for $0.25 per MMBtu to a methanol plant, an LPG plant, 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 (through June 30, 2014). North Sea sales volumes for 2014 and 2015 were de minimis, with last production in May 2015.

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

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An analysis of revenues from sales of crude oil, natural gas and NGLs is as follows: Sales Revenues(millions)Crude Oil & CondensateNaturalGasNGLsTotalThree Months Ended June 30, 2014$971$297$70$1,338Changes due toIncrease (Decrease) in Sales Volumes(70)2915(26)Decrease in Sales Prices(418)(111)(61)(590)Three Months Ended June 30, 2015$483$215$24$722Six Months Ended June 30, 2014$1,899$622$144$2,665Changes due toIncrease (Decrease) in Sales Volumes(58)813861Decrease in Sales Prices(927)(211)(126)(1,264)Six Months Ended June 30, 2015$914$492$56$1,462


Crude Oil and Condensate Sales – Revenues from crude oil and condensate sales decreased during second quarter and first six months of 2015 as compared with 2014 due to the following:


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

|  |                                                                                                                                                                                         
|- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | decreases in sales volumes due to planned downtime and maintenance as well as natural field decline in the deepwater Gulf of Mexico and the Aseng field, offshore Equatorial Guinea; and

|  |                                                                                           
|- | ------------------------------------------------------------------------------------------
|• | lower sales volumes due to the sale of our China assets at the end of second quarter 2014;

partially offset by:


|  |                                                                   
|- | ------------------------------------------------------------------
|• | higher sales volumes due to continued development in the DJ Basin.

Natural Gas Sales – Revenues from natural gas sales decreased during second quarter and the first six months of 2015 as compared with 2014 due to the following:


|  |                                                                                                                                          
|- | -----------------------------------------------------------------------------------------------------------------------------------------
|• | decreases in US average realized prices between June and December 2014 with prices declining further in the first six months of 2015; and

|  |                                                                                                                     
|- | --------------------------------------------------------------------------------------------------------------------
|• | a widening of location basis differentials in the Marcellus Shale due to an oversupply of natural gas in the region;

partially offset by:


|  |                                                                                       
|- | --------------------------------------------------------------------------------------
|• | higher sales volumes due to continued development in the DJ Basin and Marcellus Shale.

NGL Sales – Revenues from NGL sales decreased during second quarter and first six months of 2015 as compared with 2014 due to decreases in average realized prices primarily driven by oversupply, particularly in the Marcellus Shale.


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


Income from equity method investees decreased $73 million during the first six months of 2015 as compared with 2014. Income from AMPCO, our methanol investee, decreased $45 million due to lower sales volumes and additional expenses related to a 45-day plant turnaround during 2015. In addition, average realized methanol prices have declined. Income from Alba Plant, our LPG investee, decreased $46 million due to lower sales volumes and lower realized prices. In addition, feed gas supply to both Alba Plant and AMPCO was interrupted during the drilling of the Alba field C-21 development well during second quarter 2015. We recorded income of $18 million during the first six months of 2015 from our investments in CONE Gathering LLC and CONE Midstream Partners LP, which completed an initial public offering of limited partner units in September 2014.


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Operating Costs and Expenses


Operating costs and expenses were as follows:


Increase / (Decrease)from Prior Year(millions)20152014Three Months Ended June 30,Production Expense$213$244(13)%Exploration Expense4159(31)%Depreciation, Depletion and Amortization4514139%General and Administrative104127(18)%Asset Impairments1534(56)%Other Operating (Income) Expense, Net67(23)N/MTotal$891$85410%Six Months Ended June 30,Production Expense$459$474(3)%Exploration Expense106133(20)%Depreciation, Depletion and Amortization9058378%General and Administrative198266(26)%Asset Impairments43131(67)%Other Operating (Income) Expense, Net73(12)N/MTotal$1,784$1,829(2)%


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, 2015Lease Operating Expense(3)$4.80$129$80$36$12$1Production and Ad Valorem Taxes1.052828———Transportation and Gathering Expense(4)2.085656———Total Production Expense$7.93$213$164$36$12$1Total Production Expense per BOE$7.93$9.27$6.15$3.65N/MThree Months Ended June 30, 2014Lease Operating Expense(3)$5.99$150$84$36$14$16Production and Ad Valorem Taxes2.065345——8Transportation and Gathering Expense(4)1.604140——1Total Production Expense$9.65$244$169$36$14$25Total Production Expense per BOE$9.65$11.20$5.27$4.21N/MSix Months Ended June 30, 2015Lease Operating Expense(3)$5.21$286$182$70$25$9Production and Ad Valorem Taxes1.116161———Transportation and Gathering Expense(4)2.04112112———Total Production Expense$8.36$459$355$70$25$9Total Production Expense per BOE$8.36$9.92$5.83$3.59N/MSix Months Ended June 30, 2014Lease Operating Expense(3)$5.89$292$169$67$26$30Production and Ad Valorem Taxes2.0110285——17Transportation and Gathering Expense(4)1.578078——2Total Production Expense$9.47$474$332$67$26$49Total Production Expense per BOE$9.47$11.15$4.97$3.93N/M


N/M  amount is not meaningful.


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

|    |                                                                                                 
|--- | ------------------------------------------------------------------------------------------------
|(2) | Other International includes primarily China (through June 30, 2014) and corporate expenditures.

|    |                                                                                                                                                                            
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(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 second quarter and the first six months of 2015, total production expense decreased as compared with 2014 due to the following:


|  |                                                                                                                 
|- | ----------------------------------------------------------------------------------------------------------------
|• | decreased lease operating expense due to the sale of our China assets at the end of the second quarter 2014; and

|  |                                                                                                                                                                                              
|- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | decreased production and ad valorem taxes due to lower revenues resulting from lower realized prices in the US as well as the sale of our China assets at the end of the second quarter 2014;

partially offset by:


|  |                                                                           
|- | --------------------------------------------------------------------------
|• | increased lease operating expense due to higher onshore US production; and

|  |                                                                                             
|- | --------------------------------------------------------------------------------------------
|• | an increase in transportation and gathering expense due to higher onshore US production; and

|  |                                                                                                                                            
|- | -------------------------------------------------------------------------------------------------------------------------------------------
|• | an increase in transportation and gathering expense rates due to new service contracts with CONE Gathering LLC, our equity method investee.

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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, 2015Dry Hole Cost$—$—$—$—$—Seismic—————Staff Expense2625217Other1515———Total Exploration Expense$41$17$5$2$17Three Months Ended June 30, 2014Dry Hole Cost$—$—$—$—$—Seismic98—1—Staff Expense33102318Other1717———Total Exploration Expense$59$35$2$4$18Six Months Ended June 30, 2015Dry Hole Cost$19$18$1$—$—Seismic22———Staff Expense5952943Other2626———Total Exploration Expense$106$51$3$9$43Six Months Ended June 30, 2014Dry Hole Cost$2$2$—$—$—Seismic3215—215Staff Expense68184541Other3131———Total Exploration Expense$133$66$4$7$56


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

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

|    |                                                                          
|--- | -------------------------------------------------------------------------
|(3) | Other International includes the Falkland Islands and other new ventures.

Exploration expense for second quarter and the first six months of 2015 included:


|  |                                                                     
|- | --------------------------------------------------------------------
|• | dry hole cost related primarily to onshore US exploratory wells; and

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

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


|  |                                             
|- | --------------------------------------------
|• | seismic expense in the Falkland Islands; and

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

Depreciation, Depletion and Amortization DD&A expense was as follows: Three Months Ended June 30,Six Months EndedJune 30,2015201420152014DD&A Expense (millions)(1)$451$413$905$837Unit Rate per BOE(2)$16.77$16.07$16.50$16.49


|    |                                                                                                      
|--- | -----------------------------------------------------------------------------------------------------
|(1) | For DD&A expense by geographical area, seeItem 1. Financial Statements – Note13. 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 second quarter and the first six months of 2015  increased as compared with 2014 due to the following:


|  |                                                                          
|- | -------------------------------------------------------------------------
|• | increase in the DJ Basin and Marcellus Shale due to higher sales volumes;

partially offset by:


|  |                                                          
|- | ---------------------------------------------------------
|• | decrease due to the sale of our China assets during 2014.

The increase in the unit rate per BOE for the second quarter and the first six months of 2015 as compared with 2014 was due primarily to the change in mix of production. Higher-cost production volumes in the DJ Basin were offset by an increase in lower cost volumes produced at Tamar, offshore Israel.


There were no significant changes in our proved reserves estimates as of June 30, 2015 as compared with December 31, 2014. However, a decline in proved reserves estimates, caused by decreases in the 12-month average commodity prices, could result in an increase in DD&A expense in future periods.


General and Administrative Expense General and administrative expense (G&A) was as follows: Three Months Ended June 30,Six Months EndedJune 30,2015201420152014G&A Expense (millions)$104$127$198$266Unit Rate per BOE(1)$3.87$4.93$3.61$5.24


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

G&A expense for the first six months of 2015 decreased as compared with 2014 primarily due to cost savings initiatives and decreases in compensation, including the following:


|  |                                                                                                  
|- | -------------------------------------------------------------------------------------------------
|• | $37 million decrease due to reduced short term incentive compensation and related payroll burden;

|  |                                                            
|- | -----------------------------------------------------------
|• | $11 million decrease in contractor and consulting services;

|  |                                                     
|- | ----------------------------------------------------
|• | $8 million decrease due to reductions in travel; and

|  |                                                                           
|- | --------------------------------------------------------------------------
|• | $12 million decrease in special projects and other discretionary expenses.

Asset Impairment Expense Asset impairment expense was as follows: Three Months Ended June 30,Six Months EndedJune 30,(millions)2015201420152014Asset Impairments$15$34$43$131


See Item 1. Financial Statements – Note 2. Basis of Presentation ,  Note 5. Asset Impairments and Note 8. Fair Value Measurements and Disclosures .


Other Operating (Income) Expense  Other operating (income) expense was as follows: Three Months Ended June 30,Six Months EndedJune 30,(millions)2015201420152014Midstream Gathering and Processing Expense$6$4$10$7Corporate Restructuring Expense18—18—Stacked Drilling Rig Expense7—7—Pension Plan Termination Expense21—21—Gain on Divestitures(1)(44)—(42)Other, Net16171723Total$67$(23)$73$(12)


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


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Other (Income) Expense


Other (income) expense was as follows: Three Months Ended June 30,Six Months EndedJune 30,(millions)2015201420152014(Gain) Loss on Commodity Derivative Instruments$87$236$(63)$311Interest, Net of Amount Capitalized545211299Other Non-Operating (Income) Expense, Net(9)8(9)13Total$132$296$40$423


(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 the terms of our executed commodity instruments; increases in notional volumes; and the mix of instruments between NYMEX WTI, Dated Brent and NYMEX Henry Hub commodities. See Item 1. Financial Statements – Note 6. Derivative Instruments and Hedging Activities and  Note 8. Fair Value Measurements and Disclosures .


Interest Expense and Capitalized Interest Interest expense and capitalized interest were as follows: Three Months Ended June 30,Six Months EndedJune 30,2015201420152014(millions, except unit rate)Interest Expense, Gross$92$78$185$159Capitalized Interest(38)(26)(73)(60)Interest Expense, Net$54$52$112$99Unit Rate per BOE(1)$2.01$2.01$2.04$1.95


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


The increase in interest expense, gross, for second quarter and the first six months of 2015 as compared with 2014 is due to the issuance of new senior debt in November 2014.  During the first six months of 2015, we drew down and repaid amounts under our Credit Facility.


Income Tax Provision


See Item 1. Financial Statements – Note 12. Income Taxes for a discussion of the change in our effective tax rate for second quarter and the first six months of 2015 as compared with 2014 .





LIQUIDITY AND CAPITAL RESOURCES


Capital Structure/Financing Strategy


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


We endeavor to maintain 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.


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We occasionally 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 March 3, 2015, we closed an underwritten public offering of 21,000,000 shares of common stock, par value $0.01 per share, at a price to the public of $47.50 per share. In addition, on March 25, 2015, we completed the issuance of an additional 3,150,000 shares of common stock, par value $0.01 per share, in connection with the exercise of the option of the underwriters to purchase additional shares of common stock. The aggregate net proceeds of the offerings were approximately $1.1 billion (after deducting underwriting discounts and commissions and estimated offering expenses). We used approximately $150 million of the net proceeds to repay outstanding indebtedness under our revolving credit facility and the remainder will be used for general corporate purposes, including the funding of our capital investment program.


We also consider repatriations of 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 incremental US tax. During second quarter 2015, we repatriated $313 million from our foreign operations. We do not expect to incur material incremental US tax on these repatriations due to foreign tax credit usage.


We also evaluate potential strategic farm-out arrangements of our working interests for reimbursement of our capital spending and may consider other sources of funding.


Cash on hand at June 30, 2015 totaled $1.3 billion , which includes both domestic and foreign cash, and there were no amounts outstanding under our Credit Facility. See Item 1. Financial Statements – Note 7. Debt  and Credit Facility, below.


Development in the DJ Basin and Marcellus Shale, investment in major deepwater development projects, and  planned exploration and appraisal drilling activities, as well as lower commodity prices, resulted in capital expenditures exceeding cash flows from operating activities for the first six months of 2015. The extent to which capital investment will exceed operating cash flows depends on the pace of future shale development activities, timing of future development project sanction, results of exploration activities, and new business opportunities, as well as external factors such as commodity prices, among others. In particular, the sustained commodity price decline has a significant negative impact on our cash flows. However, our financial capacity, coupled with our diversified portfolio, provides us with flexibility in our investment decisions including execution of our major development projects and 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 the Big Bend and Dantzler development projects and increased peak deliverability resulting from the Tamar compression project, will result in an increase in cash flows which will be available to meet a portion of future capital commitments in 2016 and subsequent years. See  Results of Operations above.


We are currently evaluating potential development and/or financing scenarios for our significant natural gas discoveries offshore Eastern Mediterranean. The magnitude of these discoveries presents technical and financial challenges for us due to the large-scale development requirements. Each of these development options, including the development of Leviathan Phase 1, would require a multi-billion dollar investment and require a number of years to complete. We are currently working to resolve antitrust and other regulatory matters with the Israeli government to enable Leviathan and other development to move forward. See Executive Overview – Update on Core Area – Israel , above.


Pension Plan Termination We are in the process of terminating our defined benefit pension plan. During second quarter 2015, we liquidated approximately $201 million of the associated pension obligation through lump-sum payments to participants. We expect to liquidate the remaining obligation through the purchase of annuities during third quarter 2015, which will require additional contributions to the plan of approximately $51 million.


As of June 30, 2015, we reclassified approximately $19 million of unamortized net actuarial loss remaining in AOCL to earnings. Approximately $61 million of unamortized prior service cost and net actuarial loss remained in AOCL. This amount will be charged to expense upon final settlement of the remaining pension obligation and termination of the plan.


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Available Liquidity Information regarding cash and debt balances is as follows: June 30,December 31,20152014(millions, except percentages)Cash and Cash Equivalents$1,278$1,183Amount Available to be Borrowed Under Credit Facility(1)4,0004,000Total Liquidity$5,278$5,183Total Debt(2)$6,198$6,197Total Shareholders' Equity11,20910,325Ratio of Debt-to-Book Capital(3)36%38%


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

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

|    |                                                                                                                                                                                                                                                       
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(3) | We define our ratio of debt-to-book capital as total debt (which includes long-term debt excluding unamortized discount, the current portion of long-term debt, and short-term borrowings) divided by the sum of total debt plus shareholders’ equity.

Cash and Cash Equivalents We had approximately $1.3 billion in cash and cash equivalents at June 30, 2015 , primarily denominated in US dollars and invested in money market funds and short-term deposits with major financial institutions. Approximately $634 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, 2015 , no amounts were outstanding under the Credit Facility. Borrowings under our Credit Facility subject us to interest rate risk. See Item 1. Financial Statements –Note 7. Debt and  Item 3. Quantitative and Qualitative Disclosures About Market Risk.


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


Current period settlements on commodity derivative instruments impact our liquidity, since we are either paying cash to, or receiving cash from, our counterparties.


A significant portion of the hedged volumes are attributable to three-way collars. When commodities trade below the strike price of the sold put option contract of the three-way collar, the cash settlements received by us are limited. However, we still receive the cash market price plus the delta between the purchased put option floor price of the two-way collar contract and the sold put option strike price.


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, 2015 , the fair value of our commodity derivative assets was $556 million and we had no derivative liabilities (after consideration of netting provisions within our master agreements). In connection with the Rosetta Merger on July 20, 2015, we acquired commodity derivative assets. See Item 1. Financial Statements –Note  3 Rosetta Merger and Note 8. 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.


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.


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Contractual Obligations


CONSOL Carried Cost Obligation See Item 1. Financial Statements - Note 14. Commitments and Contingencies .


Exploration Commitments The terms of some of our production sharing contracts, licenses or concession agreements require us to conduct certain exploration activities, including drilling one or more exploratory wells or acquiring seismic data, within specific time periods. At June 30, 2015 , we have the following commitments:


|  |                                           
|- | ------------------------------------------
|• | remaining three-well obligation in Nevada;

|  |                                                                                                                                 
|- | --------------------------------------------------------------------------------------------------------------------------------
|• | one-well obligation offshore Cameroon, and consisting of the Cheetah well which was spud in June 2015 and is currently drilling;

|  |                                     
|- | ------------------------------------
|• | one-well obligation offshore Cyprus;

|  |                                                                                                                                      
|- | -------------------------------------------------------------------------------------------------------------------------------------
|• | two-well obligation offshore Falkland Islands, including the Humpback well which was spud in July 2015 and is currently drilling; and

|  |                                      
|- | -------------------------------------
|• | 3D seismic obligation offshore Gabon.

These obligations extend over a period ranging from one to four years. Failure to conduct exploration activities within the prescribed periods could lead to loss of leases or exploration rights.


Ratings Triggers We do not have triggers on any of our corporate debt that would cause an event of default in the case of a downgrade of our credit rating. In addition, there are no existing ratings triggers in any of our commodity hedging agreements that would require the posting of collateral. However, a series of downgrades or other negative rating actions could significantly alter our requirements to post collateral as financial assurance of performance under certain other contractual arrangements such as pipeline transportation contracts, crude oil and natural gas sales contracts, work commitments and certain abandonment obligations. A requirement to post collateral could have a negative impact on our liquidity.


Cash Flows


Cash flow information is as follows: Six Months EndedJune 30,20152014(millions)Total Cash Provided By (Used in)Operating Activities$966$1,757Investing Activities(1,812)(2,215)Financing Activities941299Increase (Decrease) in Cash and Cash Equivalents$95$(159)


Operating Activities Net cash provided by operating activities for the first six months of 2015 decreased significantly as compared with 2014 . Significant decreases in average realized commodity prices were partially offset by increases in sales volumes, decreases in production expenses, and a decrease in general and administrative expense. Working capital changes contributed $34 million of positive operating cash flow in the first six months of 2015 as compared with a positive impact of $105 million in the first six months of 2014 .


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 decreased by $423 million during the first six months of 2015 as compared with 2014 , primarily due to a reduced capital spending program. Investing activities included $65 million in CONE Gathering LLC during the first six months of 2015 as compared with $40 million in the first six months of 2014. We received $151 million in proceeds from asset divestitures during the first six months of 2015 , as compared with $146 million during the same period in 2014.


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 2015 , funds were provided by cash proceeds from the issuance of shares of Company common stock to the public ( $1.1 billion ) and the exercise of stock options ( $4 million ). We used cash to pay dividends on our common stock ( $134 million ), make principal payments related to capital lease obligations ( $29 million ) and repurchase shares of our common stock ( $12 million ).


In comparison, 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 also used cash to pay dividends on our common stock ( $116 million ), repay senior notes ($200 million), make principal payments related to capital lease obligations ( $28 million ) and repurchase shares of our common stock ( $15 million ).


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


Investing Activities


Acquisition, Capital and Exploration Expenditures  Information for investing activities (on an accrual basis) is as follows: Three Months Ended June 30,Six Months EndedJune 30,2015201420152014(millions)Acquisition, Capital and Exploration ExpendituresUnproved Property Acquisition(1)$39$74$65$129Exploration71138140228Development5939381,2371,641Midstream39519795Corporate and Other36435990Total$778$1,244$1,598$2,183OtherInvestment in Equity Method Investee(2)$21$28$65$40Increase in Capital Lease Obligations8163121


|    |                                                                                                                                                                                                                                                                                                 
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | Unproved property acquisition cost for 2015 includes $26 million in the DJ Basin and $40 million in the Marcellus Shale.  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.

|    |                                                                                                                                                                                                        
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(2) | Investment in equity method investee represents contributions to CONE Gathering LLC which owns and operates the natural gas gathering infrastructure associated with our Marcellus Shale joint venture.




Total expenditures decreased during the first six months of 2015 as compared with 2014 due to our reduced capital spending program. See Operating Outlook – 2015 Capital Investment Program , above.


On July 20, 2015, we closed the Rosetta Merger.  See Item 1 Financial Statements – Note 3 Rosetta Merger .


Financing Activities


Long-Term Debt Our principal source of liquidity is our Credit Facility that matures October 3, 2018. At June 30, 2015 , there were no borrowings outstanding under the Credit Facility, leaving $4.0 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. In connection with the Rosetta Merger, we assumed additional debt, including senior notes and amounts outstanding under Rosetta's revolving credit facility. On July 21, 2015, we repaid the $70 million of outstanding borrowings under Rosetta's revolving credit facility. See Item 1 Financial Statements – Note 3 Rosetta Merger .


Our outstanding fixed-rate debt (excluding capital lease obligations) totaled approximately $5.8 billion at June 30, 2015 . The weighted average interest rate on fixed-rate debt was 5.69% , with maturities ranging from March 2019 to August 2097.


Dividends We paid total cash dividends of 36 cents per share of our common stock during the first six months of 2015 and 32 cents per share during the first six months of 2014 .


On July 21, 2015, the Board of Directors declared a quarterly cash dividend of 18 cents per common share, which will be paid on August 17, 2015 to shareholders of record on August 3, 2015. 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 $4 million during the first six months of 2015 and $41 million during the first six months of 2014 .


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 253,597 shares with a value of $12 million during the first six months of 2015 and 247,985 shares with a value of $15 million during the first six months of 2014 .


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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, 2015 , we had entered into various commodity derivative instruments 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 asset position with a fair value of $556 million . Based on the June 30, 2015 published commodity futures price curves for the underlying commodities, a hypothetical price increase of $10.00 per Bbl for crude oil would decrease the fair value of our net commodity derivative asset by approximately $177 million . A hypothetical price increase of $0.50 per MMBtu for natural gas would decrease the fair value of our net commodity derivative asset by approximately $38 million .  Our derivative instruments are executed under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net cash settled at the time of election. See Item 1. Financial Statements – Note 6. Derivative Instruments and Hedging Activities .


Interest Rate Risk


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


At June 30, 2015 , we had approximately $5.8 billion (excluding capital lease obligations) of long-term debt outstanding. Of this amount, $5.8 billion was fixed-rate debt with a weighted average interest rate of 5.69% . Although near term changes in interest rates may affect the fair value of our fixed-rate debt, they do not expose us to the risk of earnings or cash flow loss.


There was no variable-rate debt outstanding at June 30, 2015 . Variable-rate debt exposes us to the risk of earnings or cash flow loss due to increases in market interest rates. We are also exposed to interest rate risk related to our interest-bearing cash and cash equivalents balances. As of June 30, 2015 , our cash and cash equivalents totaled approximately $1.3 billion , approximately 69% of which was invested in money market funds and short-term investments with major financial institutions. A change in the interest rate applicable to our variable-rate debt or our short term investments would have a de minimis impact. We currently have no interest rate derivative instruments outstanding. However, we may enter into interest rate derivative instruments in the future if we determine that it is necessary to invest in such instruments in order to mitigate our interest rate risk.


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 second quarter of each of 2015 and 2014.


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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|• | 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, 2014 , 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, 2014 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


Colorado Air Matter In April 2015, we entered into a joint consent decree (Consent Decree) with the US Environmental Protection Agency, US Department of Justice, and State of Colorado to improve emission control systems at a number of our condensate storage tanks that are part of our upstream oil and natural gas operations within the Non-Attainment Area of the DJ Basin. The Consent Decree was entered by the Court on June 2, 2015.


The Consent Decree, which alleges violations of the Colorado Air Pollution Prevention and Control Act and Colorado’s federal approved State Implementation Plan, specifically Colorado Air Quality Control Commission Regulation Number 7, will require the performance of certain injunctive relief activities, completion of mitigation projects and supplemental environmental projects (SEP), and payment of a civil penalty. The value of the settlement consists of $4.95 million in civil penalties, $4.5 million in mitigation projects, and $4 million in SEPs. The value associated with the injunctive relief is not yet quantifiable as it will be determined in accordance with the outcome of evaluations on the adequate design, operation, and maintenance of certain aspects of tank systems to handle potential peak instantaneous vapor flow rates between now and mid-2017.


Compliance with the Consent Decree could result in the temporary shut in or permanent plugging and abandonment of certain wells and associated tank batteries. The Consent Decree sets forth a detailed compliance schedule with deadlines for achievement of milestones through early 2019. The Consent Decree further contains requirements for ongoing inspection and monitoring, in addition to existing Colorado regulatory requirements.  Inspection and monitoring findings may influence decisions to temporarily shut in or permanently plug and abandon wells and associated tank batteries.


We have concluded that the penalties, injunctive relief, and mitigation expenditures that resulted from this settlement did not have 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, 2014 .








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)4/1/2015 - 4/30/20152,579$51.43——5/1/2015 - 5/31/20151,30748.61——6/1/2015 - 6/30/201558945.72——Total4,475$49.85——





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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)DateAugust 3, 2015/s/ Kenneth M. FisherKenneth M. FisherExecutive Vice President, Chief Financial Officer





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Index to Exhibits


Exhibit NumberExhibit2.1Agreement and Plan of Merger, dated as of May 10, 2015, by and among Noble Energy, Inc., Bluebonnet Merger Sub Inc. and Rosetta Resources Inc., filed as Exhibit 2.1 to the Registrant's Current Report on Form 8-K (Date of Event: May 10, 2015) filed on May 11, 2015 and incorporated herein by reference.3.1Certificate of Incorporation of the Registrant (as amended through April 29, 2015), filed as Exhibit 3.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2015 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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