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 March 31, 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 March 31, 2015 , there were 387,004,520 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 Operations21Item 3.Quantitative and Qualitative Disclosures About Market Risk38Item 4.Controls and Procedures39Part II.Other Information40Item 1.Legal Proceedings40Item 1A.Risk Factors40Item 2.Unregistered Sales of Equity Securities and Use of Proceeds40Item 3.Defaults Upon Senior Securities41Item 4.Mine Safety Disclosures41Item 5.Other Information41Item 6.Exhibits41Signatures42Index to Exhibits43





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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 March 31,20152014RevenuesOil, Gas and NGL Sales$740$1,327Income from Equity Method Investees1852Other1—Total7591,379Costs and ExpensesProduction Expense245229Exploration Expense6574Depreciation, Depletion and Amortization454425General and Administrative94140Asset Impairments2797Other Operating Expense, Net810Total893975Operating Income (Loss)(134)404Other (Income) Expense(Gain) Loss on Commodity Derivative Instruments(150)75Interest, Net of Amount Capitalized5747Other Non-Operating (Income) Expense, Net15Total(92)127Income (Loss) Before Income Taxes(42)277Income Tax (Benefit) Provision(20)77Net Income (Loss)$(22)$200Earnings (Loss) Per Share, Basic$(0.06)$0.56Earnings (Loss) Per Share, Diluted$(0.06)$0.55Weighted Average Number of Shares OutstandingBasic370360Diluted370365





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 March 31,20152014Net Income (Loss)$(22)$200Other Items of Comprehensive IncomeNet Change in Mutual Fund Investment(11)1Less Tax Benefit3—Net Change in Pension and Other14Less Tax Benefit—(2)Other Comprehensive Income (Loss)(7)3Comprehensive Income (Loss)$(29)$203





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





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Noble Energy, Inc.


Consolidated Balance Sheets


(millions)


(unaudited)





March 31, 2015December 31, 2014ASSETSCurrent AssetsCash and Cash Equivalents$1,709$1,183Accounts Receivable, Net769857Commodity Derivative Assets, Current661710Other Current Assets259325Total Current Assets3,3983,075Property, Plant and EquipmentOil and Gas Properties (Successful Efforts Method of Accounting)26,33725,599Property, Plant and Equipment, Other684630Total Property, Plant and Equipment, Gross27,02126,229Accumulated Depreciation, Depletion and Amortization(8,559)(8,086)Total Property, Plant and Equipment, Net18,46218,143Goodwill617620Other Noncurrent Assets784715Total Assets$23,261$22,553LIABILITIES AND SHAREHOLDERS’ EQUITYCurrent LiabilitiesAccounts Payable - Trade$1,269$1,578Other Current Liabilities874944Total Current Liabilities2,1432,522Long-Term Debt6,1136,103Deferred Income Taxes, Noncurrent2,4912,516Other Noncurrent Liabilities1,1571,087Total Liabilities11,90412,228Commitments and ContingenciesShareholders’ EquityPreferred Stock - Par Value $1.00 per share; 4 Million Shares Authorized, None Issued——Common Stock - Par Value $0.01 per share; 500 Million Shares Authorized; 428 Million and 402 Million Shares Issued, respectively44Additional Paid in Capital4,7613,624Accumulated Other Comprehensive Loss(97)(90)Treasury Stock, at Cost; 38 Million Shares(683)(671)Retained Earnings7,3727,458Total Shareholders’ Equity11,35710,325Total Liabilities and Shareholders’ Equity$23,261$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)


Three Months EndedMarch 31,20152014Cash Flows From Operating ActivitiesNet Income (Loss)$(22)$200Adjustments to Reconcile Net Income to Net Cash Provided by Operating ActivitiesDepreciation, Depletion and Amortization454425Asset Impairments2797Dry Hole Cost202Deferred Income Taxes(30)17Income from Equity Method Investees, Net of Dividends(18)(13)(Gain) Loss on Commodity Derivative Instruments(150)75Net Cash Received (Paid) in Settlement of Commodity Derivative Instruments210(33)Stock Based Compensation2123Other Adjustments for Noncash Items Included in Income1118Changes in Operating Assets and LiabilitiesDecrease in Accounts Receivable10728Increase (Decrease) in Accounts Payable(71)57Increase in Current Income Taxes Payable347Decrease in Other Current Assets and Liabilities, Net(51)(24)Other Operating Assets and Liabilities, Net3010Net Cash Provided by Operating Activities541929Cash Flows From Investing ActivitiesAdditions to Property, Plant and Equipment(1,111)(1,158)Additions to Equity Method Investments(44)(12)Proceeds from Divestitures11992Net Cash Used in Investing Activities(1,036)(1,078)Cash Flows From Financing ActivitiesExercise of Stock Options410Excess Tax Benefits from Stock-Based Awards—6Dividends Paid, Common Stock(64)(50)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—450Repayment of Capital Lease Obligation(19)(15)Net Cash Provided by Financing Activities1,021386Increase in Cash and Cash Equivalents526237Cash and Cash Equivalents at Beginning of Period1,1831,117Cash and Cash Equivalents at End of Period$1,709$1,354





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)————(22)(22)Stock-based Compensation—21———21Exercise of Stock Options—4———4Dividends (18 cents per share)————(64)(64)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)——(7)March 31, 2015$4$4,761$(97)$(683)$7,372$11,357December 31, 2013$4$3,463$(117)$(659)$6,493$9,184Net Income————200200Stock-based Compensation—23———23Exercise of Stock Options—10———10Tax Benefits Related to Exercise of Stock Options—6———6Dividends (14 cents per share)————(50)(50)Changes in Treasury Stock, Net———(15)—(15)Net Change in Pension and Other——3——3March 31, 2014$4$3,502$(114)$(674)$6,643$9,361








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


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 Noble Energy, Inc.
 Notes to Consolidated Financial Statements





Note 1.  Organization and Nature of Operations


Noble Energy, Inc. (Noble Energy, we or us) is a leading independent energy company engaged in worldwide crude oil and natural gas exploration and production. Our core operating areas are onshore US, primarily in the DJ Basin and Marcellus Shale, in the deepwater Gulf of Mexico, offshore Eastern Mediterranean, and offshore West Africa.





Note 2.  Basis of Presentation


Presentation The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the US (US GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and notes required by US GAAP for complete financial statements. The accompanying consolidated financial statements at March 31, 2015 and December 31, 2014 and for the three months ended March 31, 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 months ended March 31, 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.


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 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.


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 Authority of its decision to not submit the Consent Decree to the Antitrust Tribunal for final approval. This is a matter that we believed was resolved some time ago and we had received assurances from the Antitrust Authority that approval was forthcoming. We requested an oral hearing with the Antitrust Authority, which took place on January 27, 2015, and await final disposition.


In the meantime, negotiations are ongoing with the Antitrust Authority and with an inter-ministerial working group, established by the Prime Minister's office for the purpose of agreeing to a comprehensive regulatory framework for investment.  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 April 2015, the Financial Accounting Standards Board (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 first quarter 2016 and is only expected to impact the presentation of our consolidated balance sheet. As of March 31, 2015 and December 31, 2014, we had $48 million and $50 million of capitalized, unamortized debt issuance costs, respectively.


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


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 Noble Energy, Inc.
 Notes to Consolidated Financial Statements


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. The amendments in ASU 2014-09 are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, and early application is not permitted. In April 2015, the FASB proposed to delay the effective date for one year, for annual reporting periods beginning after December 15, 2017. The proposal will be subject to the FASB's due process requirement.  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.


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


Three Months Ended March 31,(millions)20152014Production ExpenseLease Operating Expense$157$142Production and Ad Valorem Taxes3249Transportation and Gathering Expense5638Total$245$229Other Operating (Income) Expense, NetMidstream Gathering and Processing Expense$4$3Other, Net47Total$8$10Other Non-Operating (Income) Expense, NetDeferred Compensation Expense(1)$2$4Other (Income) Expense, Net(1)1Total$1$5





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




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 Noble Energy, Inc.
 Notes to Consolidated Financial Statements


Balance Sheet Information Other balance sheet information is as follows:


(millions)March 31, 2015December 31, 2014Accounts Receivable, NetCommodity Sales$303$405Joint Interest Billings343297Other140171Allowance for Doubtful Accounts(17)(16)Total$769$857Other Current AssetsInventories, Materials and Supplies$89$81Inventories, Crude Oil2824Assets Held for Sale(1)106180Prepaid Expenses and Other Current Assets3640Total$259$325Other Noncurrent AssetsEquity Method Investments$384$325Mutual Fund Investments112111Commodity Derivative Assets169180Other Assets11999Total$784$715Other Current LiabilitiesProduction and Ad Valorem Taxes$119$110Income Taxes Payable182180Deferred Income Taxes, Current151158Accrued Benefit Costs, Current109125Asset Retirement Obligations8181Interest Payable8370Current Portion of Capital Lease Obligations6568Other84152Total$874$944Other Noncurrent LiabilitiesDeferred Compensation Liabilities$224$218Asset Retirement Obligations706670Accrued Benefit Costs2324Other204175Total$1,157$1,087


(1) Assets held for sale includes $76 million related to our Tanin and Karish natural gas discoveries, offshore Israel.  See Update on Core Area – Israel, above.





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 Noble Energy, Inc.
 Notes to Consolidated Financial Statements


Note 3.  Divestitures


Onshore US Properties During the first three months of 2015, we sold certain onshore US crude oil and natural gas leases. Properties sold generated net proceeds of $119 million , which were applied to the DJ Basin depletable field, with no recognition of gain or loss.


Information regarding assets sold during the first three months of 2014 is as follows: Three Months Ended March 31,(millions)2014Sales Proceeds$92LessNet Book Value of Assets Sold(106)Goodwill Allocated to Assets Sold(6)Asset Retirement Obligations Associated with Assets Sold20Other Closing Adjustments(1)Gain on Divestitures$(1)


Note 4.  Asset Impairments


Pre-tax (non-cash) asset impairment charges were as follows: Three Months Ended March 31,(millions)20152014Deepwater Gulf of Mexico3—Eastern Mediterranean24—North Sea—92Non-Core US Property—5Total$27$97


Impairments for 2015 were related to facility costs at South Raton (Deepwater Gulf of Mexico) and increases in expected field abandonment costs for 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 MacCulloch North Sea field.


See Note 2. Basis of Presentation , Note 7. Fair Value Measurements and Disclosures and Note  9. Asset Retirement Obligations .


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 Noble Energy, Inc.
 Notes to Consolidated Financial Statements





Note 5.  Derivative Instruments and Hedging Activities


Objective and Strategies for Using Derivative Instruments We are exposed to fluctuations in crude oil and natural gas prices on the majority of our production. In order to mitigate the effect of commodity price volatility and enhance the predictability of cash flows relating to the marketing of our global crude oil and domestic natural gas, we enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production.


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


Unsettled Commodity Derivative Instruments As of March 31, 2015 , we had entered into the following crude oil derivative instruments: SwapsCollarsSettlementPeriodType of ContractIndexBbls PerDayWeightedAverageFixedPriceWeightedAverageShort PutPriceWeightedAverageFloorPriceWeightedAverageCeilingPriceInstruments Entered Into as of March 31, 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 WTI6,00087.95———2016SwapsDated Brent9,00097.96———2016Three-Way CollarsNYMEX WTI6,000—61.0072.5086.372016Three-Way CollarsDated Brent8,000—72.5086.25101.79


As of March 31, 2015 , we had entered into the following natural gas derivative instruments: SwapsCollarsSettlementPeriodType of ContractIndexMMBtuPer DayWeightedAverageFixedPriceWeightedAverageShort PutPriceWeightedAverageFloorPriceWeightedAverageCeilingPriceInstruments Entered Into as of March 31, 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 HH60,000—2.883.504.03


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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 InstrumentsMarch 31, 2015December 31, 2014March 31, 2015December 31, 2014(millions)Balance Sheet LocationFairValueBalance Sheet LocationFairValueBalance Sheet LocationFairValueBalance Sheet LocationFairValueCommodity DerivativeInstrumentsCurrent Assets$661Current Assets$710Current Liabilities$—Current Liabilities$—Noncurrent Assets169Noncurrent Assets180Noncurrent Liabilities—Noncurrent Liabilities—Total$830$890$—$—





The effect of commodity derivative instruments on our consolidated statements of operations was as follows: Three Months Ended March 31,(millions)20152014Cash (Received) Paid in Settlement of Commodity Derivative InstrumentsCrude Oil$(185)$27Natural Gas(25)6Total Cash (Received) Paid in Settlement of Commodity Derivative Instruments(210)33Non-cash Portion of (Gain) Loss on Commodity Derivative InstrumentsCrude Oil5528Natural Gas514Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments6042(Gain) Loss on Commodity Derivative InstrumentsCrude Oil(130)55Natural Gas(20)20Total (Gain) Loss on Commodity Derivative Instruments$(150)$75


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 Notes to Consolidated Financial Statements


Note 6.  Debt


Debt consists of the following: March 31, 2015December 31, 2014(millions, except percentages)DebtInterest RateDebtInterest RateCredit Facility, due October 3, 2018$——%$——%Capital Lease and Other Obligations419—%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%Total6,2036,197Unamortized Discount(25)(26)Total Debt, Net of Discount6,1786,171Less Amounts Due Within One YearCapital Lease Obligations(65)(68)Long-Term Debt Due After One Year$6,113$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 7. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of debt.





Note 7.  Fair Value Measurements and Disclosures


Assets and Liabilities Measured at Fair Value on a Recurring Basis


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


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


Mutual Fund Investments Our mutual fund investments, which primarily include assets held in a rabbi trust, consist of various publicly-traded mutual funds that include investments ranging from equities to money market instruments. The fair values are based on quoted market prices for identical assets.


Commodity Derivative Instruments Our commodity derivative instruments may include: variable to fixed price commodity swaps, two-way collars, and/or three-way collars. We estimate the fair values of these instruments based on published forward commodity price curves as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. In addition, for collars, we estimate the option values of the put options sold and the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract terms.  See Note 5. Derivative Instruments and Hedging Activities .


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


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 Notes to Consolidated Financial Statements


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


Fair Value Measurements UsingQuoted Prices inActive Markets(Level 1)(1)Significant OtherObservable Inputs(Level 2)(2)SignificantUnobservableInputs   (Level 3)(3)Adjustment(4)Fair Value Measurement(millions)March 31, 2015Financial AssetsMutual Fund Investments$112$—$—$—$112Commodity Derivative Instruments—832—(2)830Financial LiabilitiesCommodity Derivative Instruments—(2)—2—Portion of Deferred Compensation Liability Measured at Fair Value(137)———(137)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)





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

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

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

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|(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 March 31, 2015Impaired Oil and Gas Properties$—$—$—$27$27Three Months Ended March 31, 2014Impaired Oil and Gas Properties——610397


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


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 Notes to Consolidated Financial Statements


The fair value of impaired oil and gas properties was determined as of the date of the assessment using a discounted cash flow model based on management’s expectations of future crude oil and natural gas production prior to abandonment date, commodity prices based on NYMEX WTI, NYMEX Henry Hub, and Brent future price curves as of the date of the estimate, estimated operating and abandonment costs, and a risk-adjusted discount rate of 10% .  First quarter 2015 impairments were due primarily to increases in asset carrying values associated with increases in estimated abandonment costs. See Note 4. Asset Impairments .


Additional Fair Value Disclosures


Debt The fair value of public, fixed-rate debt is estimated based on the published market prices for the same or similar issues. As such, we consider the fair value of our public, fixed-rate debt to be a Level 1 measurement on the fair value hierarchy.


As such, we consider the fair values of our Credit Facility to be a Level 2 measurement on the fair value hierarchy. See Note 6. Debt .


Fair value information regarding our debt is as follows: March 31, 2015December 31, 2014(millions)Carrying AmountFair ValueCarrying AmountFair ValueTotal Debt, Net of Unamortized Discount(1)$5,759$6,385$5,758$6,179


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

Note 8.  Capitalized Exploratory Well Costs


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


Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the same period: (millions)Three Months Ended March 31, 2015Capitalized Exploratory Well Costs, Beginning of Period$1,337Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves59Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves(6)Capitalized Exploratory Well Costs Charged to Expense(1)(17)Capitalized Exploratory Well Costs, End of Period$1,373





(1) Relates 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)March 31, 2015December 31, 2014Exploratory Well Costs Capitalized for a Period of One Year or Less$272$247Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling1,1011,090Balance at End of Period$1,373$1,337Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling1313





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 Noble Energy, Inc.
 Notes to Consolidated Financial Statements


The following table includes exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling as of March 31, 2015 : (millions)Total by ProjectProgressCountry/Project:Onshore USNortheast Nevada$26Analyzing results from our first four exploratory vertical wells and evaluating potential for production tests.Deepwater Gulf of MexicoTroubadour47Evaluating development scenarios for this 2013 natural gas discovery including subsea tieback to existing infrastructure.Offshore Equatorial Guinea (Blocks O and I)Diega/Carmen221Evaluating 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.Carla154Evaluating 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)Leviathan185During 2014, we received the Leviathan Development and Production Leases, submitted a development plan to the government, completed substantial engineering and procurement activities and engaged in natural gas marketing activities.Leviathan-1 Deep79Well 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.


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 Noble Energy, Inc.
 Notes to Consolidated Financial Statements


Dalit28Submitted a development plan to the 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 CyprusCyprus203Discussing monetization options with the Cyprus government for this 2011 natural gas discovery. In May 2014, our application for renewal of the PSC for two additional years was approved. We plan to submit a plan of development to the government in 2015.OtherIndividual Projects Less than $20 million26Continuing to drill and evaluate wells.Total$1,101


(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 9.  Asset Retirement Obligations


Asset retirement obligations (ARO) consists primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Changes in ARO are as follows: Three Months EndedMarch 31,(millions)20152014Asset Retirement Obligations, Beginning Balance$751$586Liabilities Incurred101Liabilities Settled(8)(14)Revision of Estimate2472Accretion Expense(1)1010Asset Retirement Obligations, Ending Balance$787$655


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


For the three months ended March 31, 2015


Liabilities incurred were due to new wells and facilities and included $4 million for onshore US and $6 million for deepwater Gulf of Mexico. Liabilities settled in 2015 relate primarily to non-core US properties classified as held for sale.


Revisions in estimate for 2015 relate to changes in cost estimates for Eastern Mediterranean.


For the  three months ended March 31, 2014


Liabilities settled in 2014 include $24 million for onshore US and deepwater Gulf of Mexico abandonments and $17 million related to properties classified as held for sale, offset by $27 million as a result of reclassifying remaining North Sea assets from held for sale to held and used.


Revision in estimate for 2014 included an increase of $ 67 million related to the non-operated MacCulloch North Sea field due to an increase in costs and a change in timing. See Note 3. Divestitures .


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 Noble Energy, Inc.
 Notes to Consolidated Financial Statements


Note 10.  Earnings Per Share


Basic earnings per share of common stock is computed using the weighted average number of shares of common stock outstanding during each period. The diluted earnings per share of common stock include the effect of outstanding stock options, shares of restricted stock, or shares of our common stock held in a rabbi trust (when dilutive). The following table summarizes the calculation of basic and diluted earnings per share: Three Months Ended March 31,(millions, except per share amounts)20152014Net Income (Loss)$(22)$200Weighted Average Number of Shares Outstanding, Basic(1)370360Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust(2)—5Weighted Average Number of Shares Outstanding, Diluted370365Earnings (Loss) Per Share, Basic$(0.06)$0.56Earnings (Loss) Per Share, Diluted(0.06)0.55Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above96


|    |                                                                                                                                                                                                                                           
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(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 months ended March 31, 2015, all outstanding options and non-vested restricted shares have been excluded from the calculation of diluted EPS as the Company incurred a loss for the quarter. Therefore, inclusion of outstanding options and non-vested restricted shares in the calculation of diluted EPS would be anti-dilutive.







Note 11.  Income Taxes


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


Three Months EndedMarch 31,(millions)20152014Current$10$60Deferred(30)17Total Income Tax (Benefit) Provision$(20)$77Effective Tax Rate47.6%27.6%





Our effective tax rate (ETR) for the three months ended March 31, 2015 increased as compared with the three months ended March 31, 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 – 2009 and Israel – 2010 .


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 Noble Energy, Inc.
 Notes to Consolidated Financial Statements


Note 12.  Segment Information


We have operations throughout the world and manage our operations by country. The following information is grouped into four components that are all in the business of crude oil and natural gas exploration, development, production, and acquisition: the United States; West Africa (Equatorial Guinea, Cameroon, Sierra Leone, and Gabon); Eastern Mediterranean (Israel and Cyprus); and Other International and Corporate. Other International includes the North Sea, China (through June 30, 2014), Falkland Islands, Nicaragua and new ventures. Income (loss) from continuing operations before income taxes for the United States and West Africa includes gains and losses on commodity derivative instruments. (millions)ConsolidatedUnitedStatesWestAfricaEasternMediterraneanOther Int'l &CorporateThree Months Ended March 31, 2015Revenues from Third Parties$740$478$138$120$4Income from Equity Method Investees18117——Gathering, Marketing and Processing11———Total Revenues7594901451204DD&A45435777155Asset Impairments273—24—Gain on Commodity Derivative Instruments(150)(105)(45)——Income (Loss) Before Income Taxes(42)(1)7451(166)Three Months Ended March 31, 2014Revenues from Third Parties$1,327$842$323$112$50Income from Equity Method Investees52—52——Total Revenues1,37984237511250DD&A425308761427Asset Impairments975——92Loss on Commodity Derivative Instruments7576(1)——Income (Loss) from Before Income Taxes27718326177(244)March 31, 2015Total Assets$23,261$16,998$2,732$2,840$691December 31, 2014Total Assets22,55316,4002,7632,806584








Note 13.  Commitments and Contingencies


CONSOL Carried Cost Obligation In accordance with our Marcellus Shale joint venture arrangement with a subsidiary of CONSOL Energy Inc. (CONSOL), we agreed to fund one-third of CONSOL's 50% working interest share of future drilling and completion costs, capped at $400 million each year (CONSOL Carried Cost Obligation). The remaining obligation totaled approximately $1.6 billion at March 31, 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 March 31, 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. We currently focus our efforts in five core operating areas: the DJ Basin and Marcellus Shale (onshore US), deepwater Gulf of Mexico, offshore West Africa, and offshore Eastern Mediterranean, where we have strategic competitive advantage and which we believe generate attractive returns. We also seek to enter potential new core areas, and we are currently conducting exploration activities in domestic and international locations such as Northeast Nevada, the Falkland Islands, Cameroon, and Gabon.


Significant Operating Highlights Included:


|  |                                                                                   
|- | ----------------------------------------------------------------------------------
|• | record total sales volumes of 318 MBoe/d, an 11% increase over first quarter 2014;

|  |                                                             
|- | ------------------------------------------------------------
|• | record quarterly US onshore horizontal volumes of 96 MBoe/d;

|  |                                                                          
|- | -------------------------------------------------------------------------
|• | deepwater Gulf of Mexico major projects remain on schedule and on budget;

|  |                                                                                                          
|- | ---------------------------------------------------------------------------------------------------------
|• | first gas sales and purchase agreement for regional export of Eastern Mediterranean natural gas approved;

|  |                                                                                                
|- | -----------------------------------------------------------------------------------------------
|• | planning for upcoming exploration opportunities offshore the Falkland Islands and Cameroon; and

|  |                                                                                        
|- | ---------------------------------------------------------------------------------------
|• | a decision to exit our position in Nicaragua following detailed future prospect review.

First Quarter 2015 Financial Results Included:


|  |                                                                                       
|- | --------------------------------------------------------------------------------------
|• | net loss of$22 million, as compared with net income of$200 millionforfirstquarter2014;

|  |                                                                                                                                                                                                                  
|- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | engagement in cost reduction initiatives, including both operational enhancements and new pricing arrangements with service partners, which we expect will decrease capital and operating costs through the year;

|  |                                                                                                                                                                                                                                     
|- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | net gain on commodity derivative instruments of$150 million(including$60 millionnon-cash loss) as compared with a net loss on commodity derivative instruments of$75 million(including$42 millionnon-cash loss) forfirstquarter2014;

|  |                                                                                        
|- | ---------------------------------------------------------------------------------------
|• | asset impairment charges of$27 million, as compared with$97 millionforfirstquarter2014;

|  |                                                                                                        
|- | -------------------------------------------------------------------------------------------------------
|• | diluted loss per share of$0.06, as compared with diluted earnings per share of$0.55forfirstquarter2014;

|  |                                                                                                                   
|- | ------------------------------------------------------------------------------------------------------------------
|• | cash flow provided by operating activities of $541 million, as compared with $929 million forfirstquarter2014; and

|  |                                                                                                         
|- | --------------------------------------------------------------------------------------------------------
|• | capital expenditures (accrual based) of $919 million, as compared with $951 million forfirstquarter2014.

Significant Events Impacting Liquidity Included:


|  |                                                                                           
|- | ------------------------------------------------------------------------------------------
|• | net cash proceeds of $1.1 billion received from public offering of shares of common stock.

Quarter-End Key Financial Metrics Included:


|  |                                                                                     
|- | ------------------------------------------------------------------------------------
|• | ending cash balance of$1.7 billion, as compared with$1.2 billionatDecember 31, 2014;

|  |                                                                                                     
|- | ----------------------------------------------------------------------------------------------------
|• | total liquidity of$5.7 billionatMarch 31, 2015, as compared with$5.2 billionatDecember 31, 2014; and

|  |                                                                                               
|- | ----------------------------------------------------------------------------------------------
|• | ratio of debt-to-book capital of35%atMarch 31, 2015, as compared with 38% atDecember 31, 2014.

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 first quarter 2015, crude oil and average realized natural gas prices continued to decline.  As a result, our consolidated average realized crude oil price


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decreased 54% and our consolidated average realized natural gas price decreased 27% for first quarter 2015 as compared with first quarter 2014 .


We are unable to predict the extent to which commodity prices may recover during 2015. Prices are likely to remain volatile and could decline further. In addition, we could be entering a period of sustained, lower worldwide crude oil 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 positive operating cash flow (revenues less cash operating expenses), prior to capital expenditures, in each of our core areas;

|  |                                                                                                                                     
|- | ------------------------------------------------------------------------------------------------------------------------------------
|• | 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, with approximately 60% of global crude oil and 50% of domestic natural gas production hedged for 2015, with additional quantities hedged into 2016;

|  |                                                                                               
|- | ----------------------------------------------------------------------------------------------
|• | we have a strong balance sheet with a ratio of debt-to-book capital of35%atMarch 31, 2015; and

|  |                                                                              
|- | -----------------------------------------------------------------------------
|• | we have robust liquidity with total liquidity of$5.7 billionatMarch 31, 2015.

See Operating Outlook – 2015 Capital Investment Program below.


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) During the quarter, we drilled 57 horizontal wells and commenced production on 48 wells, including 17 extended reach lateral wells. Third-party compression, natural gas processing and transportation capacity continue to expand.


Marcellus Shale (Onshore US) During the quarter, we drilled 15 operated wells, and commenced production on three operated wells. Our joint venture partner drilled 25 wells and 29 dry gas wells commenced production.


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 platform. The drilling rig is currently performing development work at Gunflint.  Topsides equipment fabrication is underway for installation in 2015 through early 2016, and first production is targeted for mid-2016.


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. All drilling and completion activities are complete, and development work is progressing on schedule. First production for Big Bend is targeted for fourth quarter 2015, and first production for Dantzler is targeted for end of 2015.


Tamar Compression (Onshore Israel) The Tamar compression project is near completion. The compression is targeted to increase deliverability at Tamar to approximately 1.2 Bcf/d, gross, beginning in mid-2015.


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 placed the project at risk of delay. We have petitioned the Israeli courts to expedite the needed approvals. Timely development of Tamar Southwest is important to maintain well capacity and reliability for our overall Tamar project.


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, as well as execution of natural gas sales and purchase agreements (GSPAs), which will be subject to, among other conditions, the receipt of regulatory


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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) We are currently evaluating development scenarios for Block 12 and plan to submit a plan of development to the Cypriot government in 2015. There is also potential for a farm-out arrangement of our working interest.


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


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 March 31, 2015 ( See Item 1. Financial Statements – Note 8. Capitalized Exploratory Well Costs ), 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 Operating Outlook – Potential for Future Asset Impairment, Dry Hole or Lease Abandonment Expense, below.


Updates on significant exploration activities are as follows:


Northeast Nevada We have drilled four exploratory wells to date. Further testing is required to assess commercial viability, and we are preparing to conduct production testing of the third well during second quarter 2015. Currently, no exploratory drilling is planned for the remainder of 2015.


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 Blocks O and I which will aid in advancing other regional exploration and development opportunities, including Diega/Carmen and Carla.


During first quarter, the Government of Cameroon approved a farmout of a portion of our working interest in the Tilapia PSC to Woodside Energy, Ltd.  We remain the operator (46.67% working interest) and plan to drill the Cheetah exploration prospect in the second half of 2015. We are also reprocessing 3D seismic data over our YoYo mining concession.


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


Offshore Falkland Islands We anticipate drilling operations to begin at the Humpback prospect (35% operated working interest), located in the South Falkland Basin, in May 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 nearly 285,000 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.


Argentine officials have recently filed charges against Noble and other oil and gas companies operating offshore the Falkland Islands. We believe the charges have no merit. Our concessions are offshore the Falkland Islands and our concession contracts are with the Falkland Islands Government.


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Non-Core Divestiture Program


We have continued our non-core asset divestiture program with the sale of certain smaller onshore US property packages during the first three months of 2015. Divestitures of non-core properties allow us to allocate capital and human resources to high-value and high-growth areas. See Item 1. Financial Statements – Note 3. Divestitures  and Operating Outlook - Potential for Future Asset Impairment, Dry Hole or Lease Abandonment Expense , below.


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 Core Area – Israel


Noble Energy and its partners have been 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 government-owned 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 country’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 resources at Tamar and Leviathan have positioned Israel to meet domestic needs for years 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.


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.


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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. Subsequently, we requested an oral hearing with the Antitrust Authority. The hearing took place on January 27, 2015, and we are awaiting final disposition.


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.


During March 2015, general elections were held, and a new coalition government is under formation. Under this new governing coalition, leadership changes in certain of the government ministries could occur, which could impact the timing of decisions regarding natural gas development.


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.


As of March 31, 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 $76 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.


Update on Regulations


DOI 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 will take 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.


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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 its development and do not believe it will have a material impact on our activities.


DOI Proposed Offshore Drilling Regulations


On April 13, 2015, the DOI 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 regulations to determine the impacts, including additional costs and reporting burdens, they may have on our deepwater Gulf of Mexico operations.


Endangered Species Act


The US Fish and Wildlife Service (the Agency), 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 Agency 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.


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 are presently being considered by the legislature and the governor is reviewing the remaining recommendations, but has not yet indicated how he plans to proceed.


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.


Sales Volumes


On a BOE basis, total sales volumes were 11%  higher for first quarter 2015 as compared with first quarter 2014 , and our mix of sales volumes was 43% global liquids, 25% international natural gas, and 32% US natural gas. See Results of Operations – Revenues, below.


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:


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

|  |                                                                                   
|- | ----------------------------------------------------------------------------------
|• | the level of horizontal drilling activity in the DJ Basin and the Marcellus Shale;

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

|  |                                                                                                                                                                                                
|- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | timing of start up of DCP Midstream's Lucerne 2 cryogenic plant and occurrence of other events which impact capacity constraints of midstream facilities serving our DJ Basin horizontal wells;

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

|  |                                                                                                                                                                               
|- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | 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;

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

|  |                                                                                                                                                                       
|- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | potential weather-related volume curtailments due to hurricanes in the deepwater Gulf of Mexico, or winter storms and flooding in the DJ Basin and/or Marcellus Shale;

|  |                                                                                                                                                                                                                 
|- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | 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;

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

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

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

|  |                                                                                         
|- | ----------------------------------------------------------------------------------------
|• | 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 environment and will be responsive to conditions that develop during 2015. Our preliminary capital program for 2015 will accommodate an investment level of approximately $2.9 billion which represents an approximate 40% reduction from 2014. The program allocates 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.


The 2015 investment program allocates approximately $1.8 billion to onshore US development split between DJ Basin and Marcellus Shale drilling programs and continued infrastructure investments. We and our Marcellus Shale joint venture partner continue to work together to determine the optimal investment plan for 2015 and 2016.


Approximately $600 million will be invested in the continued development of our sanctioned Gulf of Mexico projects, and additional amounts have been allocated to the Alba and Tamar compression projects.


The 2015 capital investment program is anticipated to exceed operating cash flows during the first half of 2015 and 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, by the second half of 2015. See Liquidity and Capital Resources – Financing Activities .


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


Exploration Activities We have an active exploratory drilling program. In the event we conclude that an exploratory well did not encounter hydrocarbons or that a discovery is not economically or operationally viable, the associated capitalized exploratory well costs would be charged to expense. For example, during first quarter 2015, we recorded dry hole expense of $20 million. See also Item 1. Financial Statements - Note 8. Capitalized Exploratory Well Costs.


Additionally, we may not conduct exploration activities prior to lease expirations. For example, in the deepwater Gulf of Mexico, while we continue to mature our prospect portfolio, regulations have become more stringent due to the Deepwater Horizon incident in 2010. In some instances, specifically engineered blowout preventers, rigs, and completion equipment may be required for high pressure environments. Regulatory requirements or lack of readily available equipment could prevent us from engaging in future exploration activities during our current lease terms. We currently have capitalized undeveloped leasehold cost of approximately $308 million related to deepwater Gulf of Mexico prospects that have not yet been drilled. These leases will expire over the years 2015 - 2024.


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


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.


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Impairment expense would be recorded for any excess of net book value over anticipated sales proceeds less costs to sell. In addition, we would allocate a portion of goodwill to any non-core onshore US property held for sale that constitutes a business, which could potentially decrease any gain or increase any loss recorded on the sale.


In addition, certain assets offshore Israel were classified as held for sale at March 31, 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 .


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RESULTS OF OPERATIONS


Revenues


Revenues were as follows: Increase/(Decrease)from Prior Year(millions)20152014Three Months Ended March 31,Oil, Gas and NGL Sales$740$1,327(44)%Income from Equity Method Investees1852(65)%Other1—N/MTotal$759$1,379(45)%


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, which are 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.


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 March 31, 2015United States7361925201$44.39$2.72$14.65Equatorial Guinea(2)30231—6849.650.27—Israel—242—40—5.45—Other International(3)1——152.89——Total Consolidated Operations1041,0922531045.962.8114.65Equity Investees(4)2—6848.63—30.17Total1061,09231318$46.01$2.81$17.64Three Months Ended March 31, 2014United States6448318163$97.02$4.81$44.50Equatorial Guinea(2)34242—74105.730.27—Israel—218—37—5.60—Other International(3)5——5104.28——Total Consolidated Operations10394318279100.233.8344.50Equity Investees(4)2—57104.71—74.51Total10594323286$100.30$3.83$51.54


|    |                                                                                                                                                                                                                                                                                                                                                                           
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(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.

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

|    |                                                                                                                                 
|--- | --------------------------------------------------------------------------------------------------------------------------------
|(3) | Other International includes primarily China (through June 30, 2014). North Sea sales volumes for 2014 and 2015 were de minimis.

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

An analysis of revenues from sales of crude oil, natural gas and NGLs is as follows: Sales Revenues(millions)Crude Oil & CondensateNaturalGasNGLsTotalThree Months Ended March 31, 2014$928$325$74$1,327Changes due toIncrease in Sales Volumes11512486Decrease in Sales Prices(508)(100)(65)(673)Three Months Ended March 31, 2015$431$276$33$740


Crude Oil and Condensate Sales – Revenues from crude oil and condensate sales decreased by $497 million or 54% during first quarter of 2015 as compared with 2014 due to the following:


|  |                                                                                                                                                                                                                                                                 
|- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | a 54% decrease in total consolidated average realized prices primarily due to the NYMEX WTI crude oil price decline between June and December 2014, with a similar Brent crude oil price decline, with sales prices continuing to be weak in first quarter 2015;

|  |                                                       
|- | ------------------------------------------------------
|• | natural field decline in the deepwater Gulf of Mexico;

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

|  |                                                                         
|- | ------------------------------------------------------------------------
|• | a volume reduction in West Africa due to natural field decline at Aseng;

partially offset by:


|  |                                                                                       
|- | --------------------------------------------------------------------------------------
|• | higher sales volumes for crude oil and condensate in the DJ Basin and Marcellus Shale.

Natural Gas Sales – Revenues from natural gas sales decreased by $49 million or 15% during first quarter 2015 as compared with 2014 due to the following:


|  |                                         
|- | ----------------------------------------
|• | a 43% decrease in US natural gas prices;

partially offset by:


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

|  |                                                                        
|- | -----------------------------------------------------------------------
|• | higher sales volumes in the Eastern Mediterranean from the Tamar field.

NGL Sales – The majority of our US NGL production is currently from the DJ Basin. Additional NGL production from the Marcellus Shale added 4 MBbl/d during first quarter 2015 as compared with 2014 , primarily due to increased production from the wet gas acreage. NGL sales in the DJ Basin increased by 2 MBbl/d during first quarter 2015 as compared with 2014.  Additionally, consolidated average sales prices decreased 67% for the first three months of 2015 compared to the first three months of 2014.


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.


We recorded income of $11 million related to our investments in CONE Gathering LLC and CONE Midstream Partners LP in first quarter 2015. Our West Africa geographical segment had an 86% decrease in equity method investee income, as compared to first quarter 2014. This decrease is due to expenses related to the 45-day AMPCO methanol plant turnaround. Production at AMPCO was shut down during first quarter 2015, which resulted in a quarterly loss.


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Operating Costs and Expenses


Operating costs and expenses were as follows:


Increase (Decrease)from Prior Year(millions)20152014Three Months Ended March 31,Production Expense$245$2297%Exploration Expense6574(12)%Depreciation, Depletion and Amortization4544257%General and Administrative94140(33)%Asset Impairments2797(72)%Other Operating (Income) Expense, Net810(20)%Total$893$975(8)%


Changes in operating costs and expenses are discussed below.


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 March 31, 2015Lease Operating Expense(3)$5.61$157$103$34$12$8Production and Ad Valorem Taxes1.163232———Transportation and Gathering Expense2.005656———Total Production Expense$8.77$245$191$34$12$8Total Production Expense per BOE$8.77$10.55$5.55$3.27N/MThree Months Ended March 31, 2014Lease Operating Expense(3)$5.66$142$85$31$12$14Production and Ad Valorem Taxes1.964940——9Transportation and Gathering Expense1.523837——1Total Production Expense$9.14$229$162$31$12$24Total Production Expense per BOE$9.14$11.04$4.67$3.65N/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 first quarter 2015 , total production expense increased as compared with 2014 due to the following:


|  |                                                                                                                           
|- | --------------------------------------------------------------------------------------------------------------------------
|• | an increase of $15 million in lease operating expense due to increased production in the DJ Basin and Marcellus Shale; and

|  |                                                                                                  
|- | -------------------------------------------------------------------------------------------------
|• | an increase in transportation and gathering expenses due to an increase in onshore US production.

partially offset by:


|  |                                                                                                                 
|- | ----------------------------------------------------------------------------------------------------------------
|• | 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 decreased 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.




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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 March 31, 2015Dry Hole Cost$20$17$—$—$3Seismic22———Staff Expense303(3)723Other1313———Total Exploration Expense$65$35$(3)$7$26Three Months Ended March 31, 2014Dry Hole Cost$2$3$—$—$(1)Seismic237—115Staff Expense3582322Other1414———Total Exploration Expense$74$32$2$4$36


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

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

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

Exploration expense for first quarter 2015 included:


|  |                                                                                    
|- | -----------------------------------------------------------------------------------
|• | $13 million of 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 first quarter 2014 included the following:


|  |                                                            
|- | -----------------------------------------------------------
|• | $12 million of 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 March 31,20152014DD&A Expense (millions)(1)$454$425Unit Rate per BOE(2)$16.24$16.95


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

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

Total DD&A expense for first quarter 2015  increased as compared with 2014 due to the following:


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

partially offset by:


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

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


Our year-end 2014 proved reserves estimates, upon which we based our first quarter 2015 DD&A calculation, were based on the previous 12-month average commodity prices. Therefore, the significant decline in crude oil prices at the end of 2014 and the continued price weakness into 2015, are not yet fully reflected in our proved reserves estimates. We expect to update our proved reserves estimates as of June 30, 2015. A decline in proved reserves estimates, caused by decreases in the 12-month average commodity prices as of June 30, 2015, could result in an increase in DD&A expense during second quarter 2015.





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General and Administrative Expense General and administrative expense (G&A) was as follows: Three Months Ended March 31,20152014G&A Expense (millions)$94$140Unit Rate per BOE(1)$3.36$5.57


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

G&A expense for first quarter 2015  decreased as compared with 2014 primarily due to the following:


|  |                                                                                        
|- | ---------------------------------------------------------------------------------------
|• | a $33 million decrease in short term incentive compensation and related payroll burden;

|  |                                                                  
|- | -----------------------------------------------------------------
|• | an $8 million decrease in contractor and consulting services; and

|  |                                                       
|- | ------------------------------------------------------
|• | reductions in travel and other discretionary expenses.

Asset Impairment Expense Asset impairment expense was as follows: Three Months Ended March 31,(millions)20152014Asset Impairments$27$97


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


Other (Income) Expense


Other (income) expense was as follows: Three Months Ended March 31,(millions)20152014(Gain) Loss on Commodity Derivative Instruments$(150)$75Interest, Net of Amount Capitalized5747Other Non-Operating (Income) Expense, Net15Total$(92)$127


(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 5. Derivative Instruments and Hedging Activities and  Note 7. Fair Value Measurements and Disclosures .


Interest Expense and Capitalized Interest Interest expense and capitalized interest were as follows: Three Months Ended March 31,20152014(millions, except unit rate)Interest Expense, Gross$93$81Capitalized Interest(36)(34)Interest Expense, Net$57$47Unit Rate per BOE(1)$2.05$1.89


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


The increase in interest expense, gross, for first quarter 2015 as compared with 2014 is due to the issuance of new senior debt in November 2014.  During first quarter 2015, we drew down and repaid amounts under our Credit Facility. There have been no other significant changes in our debt.


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Income Tax Provision


See Item 1. Financial Statements – Note 11. Income Taxes for a discussion of the change in our effective tax rate for first quarter 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 crude oil 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.


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. We 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 March 31, 2015 totaled $1.7 billion , which includes both domestic and foreign cash, and there were no amounts outstanding under our Credit Facility. See Item 1. Financial Statements – Note 6. Debt  and Credit Facility, below.


Expanded development in the DJ Basin and Marcellus Shale, investment in major deepwater development projects, and  planned exploration and appraisal drilling activities, as well as the fourth quarter 2014 decline in crude oil prices, resulted in capital expenditures exceeding cash flows from operating activities for first quarter 2015. The extent to which capital investment will exceed operating cash flows depends on the pace of future DJ Basin and Marcellus Shale development activities, timing of future development project sanction, the results of exploration activities, and new business opportunities, as well as external factors such as commodity prices, among others. In particular, the sustained crude oil 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 additional production 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.


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Pension Plan Termination We are in the process of terminating our defined benefit pension plan. The Internal Revenue Service has approved the termination, and we expect to liquidate the associated pension obligation through lump-sum payments to participants or the purchase of annuities on their behalf.


As of December 31, 2014, the latest actuarial measurement date for the pension plan, the accumulated benefit obligation totaled $287 million, and the fair value of plan assets was $242 million. Therefore, we expect to make additional contributions to the plan of approximately $50 million during the period leading up to final termination and distribution to the extent necessary to fund the net obligation.


In addition, upon termination of the pension plan, all unamortized prior service cost and net actuarial loss remaining in accumulated other comprehensive loss will be charged to expense. This amount totaled approximately $82 million as of March 31, 2015 .


Available Liquidity Information regarding cash and debt balances is as follows: March 31,December 31,20152014(millions, except percentages)Cash and Cash Equivalents$1,709$1,183Amount Available to be Borrowed Under Credit Facility(1)4,0004,000Total Liquidity$5,709$5,183Total Debt(2)$6,203$6,197Total Shareholders' Equity11,35710,325Ratio of Debt-to-Book Capital(3)35%38%


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

|    |                                                                                                
|--- | -----------------------------------------------------------------------------------------------
|(2) | Total debt includes capital lease and other 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 $1.7 billion in cash and cash equivalents at March 31, 2015 , primarily denominated in US dollars and invested in money market funds and short-term deposits with major financial institutions. Approximately $791 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 March 31, 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 6. 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 March 31, 2015 , the fair value of our commodity derivative assets was $830 million and we had no derivative liabilities (after consideration of netting provisions within our master agreements).  See Item 1. Financial Statements –Note 7. Fair Value Measurements and Disclosures for a description of the methods we use to estimate the fair values of commodity derivative instruments and Credit Risk, below.


Credit Risk We monitor the creditworthiness of our trade creditors, joint venture partners, hedging counterparties, and financial institutions on an ongoing basis. Some of these entities are not as creditworthy as we are and may experience credit downgrades or liquidity problems. Counterparty credit downgrades or liquidity problems could result in a delay in our receiving proceeds from commodity sales, reimbursement of joint venture costs, and potential delays in our major development


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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.


Contractual Obligations


CONSOL Carried Cost Obligation See Item 1. Financial Statements - Note 13. Commitments and Contingencies .


Exploration Commitments The terms of some of our PSCs, 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 March 31, 2015 , we have the following commitments: remaining three-well obligation in Nevada; one-well obligation offshore Cameroon; one-well obligation offshore Cyprus; two-well obligation offshore Falkland Islands; 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 downgrade or other negative rating action could affect 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.


Cash Flows


Cash flow information is as follows: Three Months EndedMarch 31,20152014(millions)Total Cash Provided By (Used in)Operating Activities$541$929Investing Activities(1,036)(1,078)Financing Activities1,021386Increase in Cash and Cash Equivalents$526$237


Operating Activities Net cash provided by operating activities for the first three months of 2015 decreased significantly as compared with 2014 . Significant decreases in the average realized sales prices of crude oil and domestic natural gas were partially offset by increases in sales volumes, decreases in production expenses, and a decrease in general and administrative expense. Working capital changes contributed $18 million of positive operating cash flow in the first three months of 2015 as compared with a positive impact of $126 million in the first three 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 $47 million during the first three months of 2015 as compared with 2014 , primarily due to a reduced capital spending program. Investing activities included $44 million in CONE Gathering LLC during the first three months of 2015 as compared with $12 million in the first three months of 2014. We received $119 million in proceeds from asset divestitures during the first three months of 2015 , as compared with $92 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 three 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 ( $64 million ), make principal payments related to capital lease obligations ( $19 million ) and repurchase shares of our common stock ( $12 million ).


In comparison, during the first three months of 2014 , funds were provided by cash proceeds from, and tax benefits related to, the exercise of stock options ( $16 million ) and net cash proceeds from our Credit Facility ($450 million).  We also used cash to


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pay dividends on our common stock ( $50 million ), make principal payments related to capital lease obligations ( $15 million ) and repurchase shares of our common stock ( $15 million ).


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


Investing Activities


Acquisition, Capital and Exploration Expenditures  Information for investing activities (on an accrual basis) is as follows: Three Months EndedMarch 31,20152014(millions)Acquisition, Capital and Exploration ExpendituresUnproved Property Acquisition(1)$26$55Exploration6990Development699703Midstream5844Corporate and Other2347Total$875$939OtherInvestment in Equity Method Investee(2)$44$12Increase in Capital Lease Obligations205


|    |                                                                                                                                                                                                                                                   
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | Unproved property acquisition cost for 2015 includes $11 million in the DJ Basin and $15 million in the Marcellus Shale.  Unproved property acquisition cost for 2014 includes $20 million in the DJ Basin and $35 million in the Marcellus Shale.

|    |                                                                                                                                                                                                        
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(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 first quarter 2015 as compared with 2014 due to our reduced capital spending program.  See Operating Outlook – 2015 Capital Investment Program, above.


Financing Activities


Long-Term Debt Our principal source of liquidity is our Credit Facility that matures October 3, 2018. At March 31, 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. See Item 1 Financial Statements – Note 6. Debt .


Our outstanding fixed-rate debt (excluding capital lease and other obligations) totaled approximately $5.8 billion at March 31, 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 18 cents per share of our common stock during the first three months of 2015 and 14 cents per share during the first three months of 2014 .


On April 27, 2015, the Board of Directors declared a quarterly cash dividend of 18 cents per common share, which will be paid on May 26, 2015 to shareholders of record on May 11, 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 three months of 2015 and $10 million during the first three 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 249,122 shares with a value of $12 million during the first three months of 2015 and 247,674 shares with a value of $15 million during the first three 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 March 31, 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 $830 million . Based on the March 31, 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 $194 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 $42 million .  Our derivative instruments are executed under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net cash settled at the time of election. See Item 1. Financial Statements – Note 5. Derivative Instruments and Hedging Activities .


Interest Rate Risk


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


At March 31, 2015 , we had approximately $5.8 billion (excluding capital lease and other 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 March 31, 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 March 31, 2015 , our cash and cash equivalents totaled approximately $1.7 billion , approximately 72% 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 first 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:


|  |                       
|- | ----------------------
|• | our growth strategies;

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

|  |                                    
|- | -----------------------------------
|• | anticipated trends in our business;

|  |                                  
|- | ---------------------------------
|• | our future results of operations;

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

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

|  |                                                
|- | -----------------------------------------------
|• | our ability to make and integrate acquisitions;

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

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

Forward-looking statements are typically identified by use of terms such as “may,” “will,” “expect,” “believe,” “anticipate,” “estimate,” “intend,” and similar words, although some forward-looking statements may be expressed differently. These forward-looking statements are made based upon our current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements. You should consider carefully the statements under Item 1A. Risk Factors included in our Annual Report on Form 10-K for the year ended December 31, 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 is subject to a 30 day public comment period before it may be considered for entry by the Court.


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)1/1/2015 - 1/31/201548,403$47.74——2/1/2015 - 2/28/2015199,70547.74——3/1/2015 - 3/31/20151,01446.94——Total249,122$47.74——





|    |                                                                                                                                                                                                                                                                     
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(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, which vested primarily on January 31 and February 1, 2015.




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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)DateMay 5, 2015/s/ Kenneth M. FisherKenneth M. FisherExecutive Vice President, Chief Financial Officer





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Index to Exhibits


Exhibit NumberExhibit3.1Certificate of Incorporation of the Registrant (as amended through April 29, 2015), filed herewith.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.10.1Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan (as amended through April 28, 2015), filed herewith.10.22015 Stock Plan for Non-Employee Directors of Noble Energy, Inc., filed herewith.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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