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10-Q



























































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)























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

















483,118,790








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Part I.Financial Information3Item 1.Financial Statements3Consolidated Statements of Operations and Comprehensive Income3Consolidated Balance Sheets4Consolidated Statements of Cash Flows5Consolidated Statements of Equity6Notes to Consolidated Financial Statements7Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations29Item 3.Quantitative and Qualitative Disclosures About Market Risk46Item 4.Controls and Procedures48Part II.Other Information48Item 1.Legal Proceedings48Item 1A.Risk Factors48Item 2.Unregistered Sales of Equity Securities and Use of Proceeds48Item 3.Defaults Upon Senior Securities50Item 4.Mine Safety Disclosures50Item 5.Other Information50Item 6.Exhibits51Signatures53











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Three Months Ended June 30,Six Months Ended June 30,2018201720182017RevenuesOil, NGL and Gas Sales$1,100$1,017$2,273$2,011Income from Equity Method Investees and Other1304224384Total1,2301,0592,5162,095Costs and ExpensesProduction Expense292283613586Exploration Expense29306472Depreciation, Depletion and Amortization4655039331,031Loss on Marcellus Shale Upstream Divestiture—2,322—2,322Gain on Divestitures, Net(78)—(666)—Asset Impairments——168—General and Administrative105103209202Other Operating Expense, Net74118144147Total8873,3591,4654,360Operating Income (Loss)343(2,300)1,051(2,265)Other (Income) ExpenseLoss (Gain) on Commodity Derivative Instruments249(57)328(167)Interest, Net of Amount Capitalized7396146183Other Non-Operating Expense (Income), Net11(5)24(6)Total3333449810Income (Loss) Before Income Taxes10(2,334)553(2,275)Income Tax Expense (Benefit)16(836)(15)(824)Net (Loss) Income and Comprehensive (Loss) Income Including Noncontrolling Interests(6)(1,498)568(1,451)Less: Net Income and Comprehensive Income Attributable to Noncontrolling Interests17143725Net (Loss) Income and Comprehensive Income (Loss) Attributable to Noble Energy$(23)$(1,512)$531$(1,476)Net (Loss) Income Attributable to Noble Energy per Common ShareBasic$(0.05)$(3.20)$1.09$(3.27)Diluted$(0.05)$(3.20)$1.09$(3.27)Weighted Average Number of Common Shares OutstandingBasic484472485452Diluted484472487452














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June 30, 2018December 31, 2017ASSETSCurrent AssetsCash and Cash Equivalents$621$675Accounts Receivable, Net743748Other Current Assets187780Total Current Assets1,5512,203Property, Plant and EquipmentOil and Gas Properties (Successful Efforts Method of Accounting)28,33429,678Property, Plant and Equipment, Other896879Total Property, Plant and Equipment, Gross29,23030,557Accumulated Depreciation, Depletion and Amortization(11,313)(13,055)Total Property, Plant and Equipment, Net17,91717,502Other Noncurrent Assets984461Goodwill1,4021,310Total Assets$21,854$21,476LIABILITIES AND EQUITYCurrent LiabilitiesAccounts Payable – Trade$1,308$1,161Other Current Liabilities745578Total Current Liabilities2,0531,739Long-Term Debt6,5556,746Deferred Income Taxes9701,127Other Noncurrent Liabilities9951,245Total Liabilities10,57310,857Commitments and ContingenciesShareholders’ EquityPreferred Stock - Par Value $1.00 per share; 4 Million Shares Authorized; None Issued——Common Stock - Par Value $0.01 per share; 1 Billion Shares Authorized; 526 Million and 529 Million Shares Issued, respectively55Additional Paid in Capital8,3298,438Accumulated Other Comprehensive Loss(28)(30)Treasury Stock, at Cost; 39 Million Shares(731)(725)Retained Earnings2,6772,248Noble Energy Share of Equity10,2529,936Noncontrolling Interests1,029683Total Equity11,28110,619Total Liabilities and Equity$21,854$21,476

















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Six Months Ended June 30,20182017Cash Flows From Operating ActivitiesNet Income (Loss) Including Noncontrolling Interests$568$(1,451)Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating ActivitiesDepreciation, Depletion and Amortization9331,031Loss on Marcellus Shale Upstream Divestiture—2,322Gain on Divestitures, Net(666)—Asset Impairments168—Deferred Income Tax Benefit(164)(873)Loss (Gain) on Commodity Derivative Instruments328(167)Net Cash (Paid) Received in Settlement of Commodity Derivative Instruments(93)14Stock Based Compensation3567Other Adjustments for Noncash Items Included in Income (Loss)2233Changes in Operating Assets and LiabilitiesDecrease (Increase) in Accounts Receivable76(123)(Decrease) Increase in Accounts Payable(24)120Decrease in Current Income Taxes Payable3(42)Other Current Assets and Liabilities, Net(58)(42)Other Operating Assets and Liabilities, Net(49)(12)Net Cash Provided by Operating Activities1,079877Cash Flows From Investing ActivitiesAdditions to Property, Plant and Equipment(1,782)(1,215)Proceeds from Sale of 7.5% Interest in Tamar Field484—Proceeds from Sale of CONE Gathering LLC and CNX Midstream Partners Common Units443—Proceeds from Gulf of Mexico Divestiture383—Proceeds from Marcellus Shale Upstream Divestiture—1,028Clayton Williams Energy Acquisition—(616)Acquisitions, Net of Cash Acquired(650)(351)Proceeds from Other Divestitures72101Additions to Equity Method Investments—(68)Other——Net Cash Used in Investing Activities(1,050)(1,121)Cash Flows From Financing ActivitiesDividends Paid, Common Stock(102)(92)Purchase and Retirement of Common Stock(130)—Proceeds from Noble Midstream Services Revolving Credit Facility610195Repayment of Noble Midstream Services Revolving Credit Facility(165)(5)Contributions from Noncontrolling Interest Owners331—Issuance of Noble Midstream Partners Common Units, Net of Offering Costs—138Proceeds from Revolving Credit Facility9051,310Repayment of Revolving Credit Facility(1,135)(1,310)Repayment of Clayton Williams Energy Long-term Debt—(595)Repayment of Senior Notes(384)—Other(51)(67)Net Cash Used in Financing Activities(121)(426)Decrease in Cash, Cash Equivalents, and Restricted Cash(92)(670)Cash, Cash Equivalents, and Restricted Cash at Beginning of Period7131,210Cash, Cash Equivalents, and Restricted Cash at End of Period$621$540











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Attributable to Noble EnergyCommonStockAdditionalPaid inCapitalAccumulated OtherComprehensiveLossTreasuryStock atCostRetainedEarningsNon-controlling InterestsTotal EquityDecember 31, 2017$5$8,438$(30)$(725)$2,248$683$10,619Net Income————53137568Stock-based Compensation—46————46Dividends (21 cents per share)————(102)—(102)Purchase and Retirement of Common Stock—(130)————(130)Clayton Williams Energy Acquisition—(25)————(25)Distributions to Noncontrolling Interest Owners—————(22)(22)Contributions from Noncontrolling Interest Owners—————331331Other——2(6)——(4)June 30, 2018$5$8,329$(28)$(731)$2,677$1,029$11,281December 31, 2016$5$6,450$(31)$(692)$3,556$312$9,600Net (Loss) Income————(1,476)25(1,451)Clayton Williams Energy Acquisition—1,876—(25)——1,851Stock-based Compensation—65————65Dividends (20 cents per share)————(92)—(92)Issuance of Noble Midstream Partners Common Units, Net of Offering Costs—————138138Distributions to Noncontrolling Interest Owners—————(12)(12)Other—81(10)——(1)June 30, 2017$5$8,399$(30)$(727)$1,988$463$10,098














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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 historical operating areas include: US onshore, primarily the DJ Basin, Delaware Basin, Eagle Ford Shale and Marcellus Shale (until June 2017); US offshore Gulf of Mexico (until April 2018); Eastern Mediterranean; and West Africa. Our Midstream segment owns, operates, develops and acquires domestic midstream infrastructure assets with current focus areas being the DJ and Delaware Basins.








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 atJune 30, 2018andDecember 31, 2017and for thethree and six months ended June 30, 2018and2017contain all normally recurring adjustments considered necessary for a fair presentation of our financial position, results of operations, cash flows and equity for such periods. For the periods presented, activity within other comprehensive income or loss was de minimis; therefore, net income is materially consistent with comprehensive income or loss.





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 endedDecember 31, 2017 .


Consolidation
 Our consolidated financial statements include our accounts, the accounts of subsidiaries which Noble Energy wholly owns, and the accounts of Noble Midstream Partners, which is considered a variable interest entity (VIE) for which Noble Energy is the primary beneficiary. In addition, we use the equity method of accounting for investments in entities that we do not control, but over which we exert significant influence. All significant intercompany balances and transactions have been eliminated upon consolidation.


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


Investment in Shares of Tamar Petroleum
 We account for our investment in shares of Tamar Petroleum Ltd. at fair value and record changes in fair value in other non-operating expense (income), net in our consolidated statements of operations.
 Note 3. Acquisitions and Divestitures  Note 6. Fair Value Measurements and Disclosures


Intangible Assets
 Intangible assets consist of customer contracts and relationships acquired by Noble Midstream Partners in its acquisition of Saddle Butte Rockies Midstream, LLC and affiliates (collectively, Saddle Butte). We recorded the intangible assets at their estimated fair values at the date of acquisition. Amortization is calculated using the straight-line method, which reflects the pattern in which the estimated economic benefit is expected to be received over the estimated useful life of the intangible asset, which is currently over periods ofsevento13years. As of June 30, 2018, the gross book value of the intangible asset was$340 million. Amortization expense of$9 millionand$14 millionfor thethree and six months ended June 30, 2018, respectively, is included in depreciation, depletion and amortization expense in our consolidated statements of operations. Intangible assets with finite useful lives are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. SeeNote 3. Acquisitions and Divestitures.


Stock Repurchase Program
 OnFebruary 15, 2018, we announced that the Company's Board of Directors authorized a $750million share repurchase program which expiresDecember 31, 2020 . All purchases will be made from time to time in the open market or private transactions, depending on market conditions, and may be discontinued at any time.
   1.8
  4.0
  35.15
  32.41


ASC 606, Revenue from Contracts with Customers
 Our revenue is derived from the sale of crude oil, NGL and natural gas production primarily to crude oil refining companies, midstream marketing companies, marketers, industrial companies, electric utility companies, independent power producers and cogeneration facilities, among others. We account for revenue in accordance with ASC 606,Revenue from Contracts with Customers(ASC 606), which we adopted on January 1, 2018 using the








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  7





























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0.25





Transaction Price Allocated to Remaining Performance Obligations – Israel Remaining performance obligations represent the transaction price of firm sales arrangements for which volumes have not been delivered. Pursuant to ASC 606, short and long-term interruptible contracts, and long-term dedicated production agreements, are excluded from the disclosure due to uncertainty associated with estimating future production volumes and future market prices. However, certain of our natural gas sales contracts in Israel have fixed annual sales volumes and fixed base pricing with annual index escalations. The following table includes estimated revenues based upon those certain agreements with fixed minimum take-or-pay sales volumes. Our actual future sales volumes under these agreements may exceed future minimum volume commitments.








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(millions)July - Dec 201820192020TotalNatural Gas Revenues(1)$107$137$169$413


(1) The remaining performance obligations are estimated utilizing the contractual base or floor price provision in effect. Our future revenues from the sale of natural gas under these associated contracts will vary from the amounts presented above due to components of variable consideration above the contractual base or floor provision, such as index-based escalations and market price changes.


MIDSTREAM REVENUE ARRANGEMENTS





Crude Oil Purchase and Sale Arrangements – US As part of the Saddle Butte acquisition in first quarter 2018, we acquired a pipeline and associated third party contracts which include transactions for the purchase and sale of crude oil with varying counterparties. Revenues and expenses from the sales and purchases are recorded on a gross basis as we act as a principal in these transactions by assuming control of the purchased commodity before it is transferred to the customer. The purchases and sales of crude oil are at the prevailing market prices.


Recently Issued Accounting Standards








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Financial Instruments: Credit LossesIn June 2016, the FASB issued Accounting Standards Update No. 2016-13 (ASU 2016-13):Financial Instruments – Credit Losses , which replaces the incurred loss impairment methodology with a methodology that reflects expected credit losses. The update is intended to provide financial statement users with more useful information about expected credit losses. The amended standard is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. From evaluation of our current credit portfolio, which includes receivables for commodity sales, joint interest billings due from partners and other receivables, historical credit losses have been de minimis and we believe that our expected future credit losses would not be significant. As such, we do not believe adoption of the standard will have a material impact on our financial statements.





Other statements of operations information is as follows:
 Three Months Ended June 30,Six Months Ended June 30,(millions)2018201720182017Income From Equity Method Investees and OtherIncome from Equity Method Investees$49$38$96$80Sales of Purchased Oil and Gas(1)66—119—Midstream Services Revenues – Third Party154284Total$130$42$243$84Production ExpenseLease Operating Expense$132$124$287$263Production and Ad Valorem Taxes503210473Gathering, Transportation and Processing Expense100121195240Other Royalty Expense1062710Total$292$283$613$586Exploration ExpenseLeasehold Impairment and Amortization$—$—$—$18Seismic, Geological and Geophysical281313Staff Expense13162729Other1462412Total$29$30$64$72Other Operating Expense, NetMarketing Expense(2)$7$14$12$33Purchased Oil and Gas(1)71—128—Clayton Williams Energy Acquisition Expenses—90—94Other, Net(4)14420Total$74$118$144$147Other Non-Operating Expense (Income), NetLoss on Investment in Shares of Tamar Petroleum Ltd., Net(3)$11$—$26$—Other—(5)(2)(6)Total$11$(5)$24$(6)








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|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | As part of the Saddle Butte acquisition in first quarter 2018, we acquired certain contracts which include the purchase and sale of crude oil with third parties. In addition, we have entered into certain transactions beginning in first quarter 2018 for the purchase of third party natural gas and the subsequent sale of natural gas to other third parties. The natural gas is transported through firm transportation capacity we retained following the Marcellus Shale upstream divestiture in second quarter 2017 and is part of our mitigation efforts to utilize capacity and reduce our financial commitment. The cost to purchase natural gas includes transportation expense incurred of$6 millionand$11 millionforsecond quarter and the first six months of 2018, respectively. SeeNote11. Segment InformationandNote12. Commitments and Contingencies.

|    |                                                                                                                                          
|--- | -----------------------------------------------------------------------------------------------------------------------------------------
|(2) | Expense relates to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments.

|    |                                                                                                                                                                                                                                                                                                                      
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(3) | Amounts forsecond quarter and the first six months of 2018include losses of$11 millionand$40 million, respectively, related to the change in fair value.  The loss for the six months ended June 30, 2018 is partially offset by dividend income of$14 million. There was no dividend income for second quarter 2018.







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Other balance sheet information is as follows:


(millions)June 30, 2018December 31, 2017Accounts Receivable, NetCommodity Sales$460$455Joint Interest Billings210207Other89103Allowance for Doubtful Accounts(16)(17)Total$743$748Other Current AssetsInventories, Materials and Supplies$46$66Inventories, Crude Oil2716Commodity Derivative Assets292Assets Held for Sale(1)40629Restricted Cash(2)—38Prepaid Expenses and Other Current Assets4529Total$187$780Other Noncurrent AssetsEquity Method Investments(3)$357$305Customer-Related Intangible Assets(4)326—Investment in Shares of Tamar Petroleum Ltd.(5)150—Mutual Fund Investments5757Net Deferred Income Tax Asset2525Other Assets, Noncurrent6974Total$984$461Other Current LiabilitiesProduction and Ad Valorem Taxes$111$84Commodity Derivative Liabilities25058Income Taxes Payable518Asset Retirement Obligations9251Interest Payable6467Current Portion of Capital Lease Obligations4761Liabilities Associated with Assets Held for Sale(1)—55Compensation and Benefits Payable6698Other Liabilities, Current11086Total$745$578Other Noncurrent LiabilitiesDeferred Compensation Liabilities$180$197Asset Retirement Obligations543824Marcellus Shale Firm Transportation Commitment(6)7176Production and Ad Valorem Taxes3969Commodity Derivative Liabilities8515Other Liabilities, Noncurrent7764Total$995$1,245


|    |                                                                                                                                                                                                                                                                                                                                                                                                              
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | Assets held for sale atJune 30, 2018include assets in the Greeley Crescent area of the DJ Basin. Assets held for sale atDecember 31, 2017include assets in the Greeley Crescent area of the DJ Basin, a7.5%interest in the Tamar field, offshore Israel, our interest in Southwest Royalties, Inc. acquired in the Clayton Williams Energy Acquisition, and the CONE investments. Liabilities associated with







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Note


|    |                                                                                                                                                      
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------
|(2) | Balance atDecember 31, 2017represents amount held in escrow pending closing of the Saddle Butte acquisition. SeeNote3. Acquisitions and Divestitures.

|    |                                                                                                                                                                                                                                                     
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(3) | Includes$49 millionfor our investment in shares of CNX Midstream Partners LP. AtDecember 31, 2017, this investment was included in assets held for sale. SeeNote 3. Acquisitions and DivestituresandNote 6. Fair Value Measurements and Disclosures.

|    |                                                                                                                                                                           
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(4) | Amount relates to intangible assets acquired in the Saddle Butte acquisition and is net of$14 millionof accumulated amortization. SeeNote3. Acquisitions and Divestitures.

|    |                                                                                                                                                             
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------
|(5) | Amount relates to our investment in shares of Tamar Petroleum Ltd.SeeNote3. Acquisitions and DivestituresandNote 6. Fair Value Measurements and Disclosures.

|    |                                                                                                                                                                                                                                                                                                                  
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(6) | Amounts relate to the long-term portion of retained firm transportation agreements. AtJune 30, 2018andDecember 31, 2017, we recorded$12 millionand$14 million, respectively, associated with the current portion of the Marcellus Shale firm transportation commitment. SeeNote12. Commitments and Contingencies.




Reconciliation of Total CashWe define total cash as cash, cash equivalents and restricted cash. The following table provides a reconciliation of total cash:Six Months Ended June 30,(millions)20182017Cash and Cash Equivalents at Beginning of Period$675$1,180Restricted Cash at Beginning of Period3830Cash, Cash Equivalents, and Restricted Cash at Beginning of Period$713$1,210Cash and Cash Equivalents at End of Period$621$540Restricted Cash at End of Period——Cash, Cash Equivalents, and Restricted Cash at End of Period$621$540








Note
 3. Acquisitions and Divestitures





480
  168


383
  19


100
  2
  63


23


7.5
   7.5
  38.5
  224
  484


190
  15
  Note 6. Fair Value Measurements and Disclosures


376
  86








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32.5
  25
  7.5
  84


60


50
  308
  196


21.7
  34.1
  7.5
  135
  109
  14.2
  22.3





681
  663
  18
  343


206
  340
  111


12
  4





301
  246


56
  1.9
  637
  2.5


The following table represents the final allocation of the total purchase price of Clayton Williams Energy to the assets acquired and liabilities assumed, based on the fair value at the acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable ne








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(millions)Fair Value of Common Stock Issued$1,851Plus: Cash Consideration Paid to Clayton Williams Energy Stockholders637Total Purchase Price$2,488Plus Liabilities Assumed by Noble Energy:Accounts Payable99Other Current Liabilities38Long-Term Deferred Tax Liability515Long-Term Debt595Asset Retirement Obligations63Total Purchase Price Plus Liabilities Assumed$3,798


The fair value of Clayton Williams Energy's identifiable assets was as follows:(millions)Cash and Cash Equivalents$21Other Current Assets70Oil and Gas Properties:Proved Reserves722Undeveloped Leasehold Costs1,571Gathering and Processing Assets48Asset Retirement Costs63Other Noncurrent Assets12Implied Goodwill1,291Total Asset Value$3,798


595





1.3





The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Clayton Williams Energy Acquisitio








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Three Months Ended June 30,Six Months Ended June 30,(millions, except per share amounts)2018(1)20172018(1)2017Revenues$1,230$1,070$2,516$2,141Net (Loss) Income and Comprehensive (Loss) Income Attributable to Noble Energy(23)(1,354)531(1,324)Net (Loss) Income Attributable to Noble Energy per Common ShareBasic$(0.05)$(2.77)$1.09$(2.71)Diluted$(0.05)$(2.77)$1.09$(2.71)


|    |                                                                                                                                
|--- | -------------------------------------------------------------------------------------------------------------------------------
|(1) | No pro forma adjustments were made for the period as Clayton Williams Energy operations are included in our historical results.




1.2
  1.0
  100
  33.3
  3.30
  Note 5. Debt


2.3
  1.5
  3.4
  883


41
  Note 12. Commitments and Contingencies


393
  241
  190
  51


15
  40
  20
  270


111,000


270
  245
  562,430
  138
  90


Noble Midstream Partners Advantage AcquisitionOn April 3, 2017, Noble Midstream Partners and Plains Pipeline, L.P., a wholly owned subsidiary of Plains All American Pipeline, L.P., acquired Advantage Pipeline, L.L.C. (Advantage Pipeline) for$133 millionthrough a newly formed50/50 joint venture (Advantage Joint Venture). Noble Midstream Partners contributed$66.5 million of cash to the joint venture, funded by available cash on hand and the Noble Midstream Services Revolving Credit Facility. The Advantage Joint Venture is accounted for under the equity method and is included within our Midstream segment. Noble Midstream Partners serves as the operator of the Advantage Pipeline system, which includes a crude oil pipeline in the Delaware Basin from Reeves County, Texas to Crane County, Texas.











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Note
 4. Derivative Instruments and Hedging Activities





Note


As of
 June 30, 2018, the following crude oil derivative contracts were outstanding:SwapsCollarsSettlementPeriodType of ContractIndexBbls PerDayWeighted Average DifferentialWeightedAverageFixedPriceWeightedAverageShort PutPriceWeightedAverageFloorPriceWeightedAverageCeilingPrice2018SwapsNYMEX WTI66,000$—$60.30$—$—$—2018CollarsNYMEX WTI18,000———50.4258.822018Three-Way CollarsNYMEX WTI10,000——45.5052.5069.092018Three-Way CollarsDated Brent3,000——40.0050.0070.412018SwapsICE Brent2,000—59.00———2018CollarsICE Brent2,000———50.0055.252018Three-Way CollarsICE Brent5,000——43.0050.0059.502018Basis Swaps(1)20,000(2.30)————2019SwapsNYMEX WTI44,000—58.37———2019Three-Way CollarsNYMEX WTI6,000——50.0060.0072.752019SwapsICE Brent5,000—57.00———2019Three-Way CollarsICE Brent3,000——43.0050.0064.072019Basis Swaps(1)27,000(3.23)————2020Swaption(2)NYMEX WTI5,000—61.79———2020Basis Swaps(1)15,000(5.01)————


(1)


(2)

















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SwapsCollarsSettlementPeriodType of ContractIndexMMBtuPer DayWeightedAverageFixedPriceWeightedAverageShort PutPriceWeightedAverageFloorPriceWeightedAverageCeilingPrice2018Three-Way CollarsNYMEX HH120,000$—$2.50$2.88$3.65


The fair values of commodity derivative instruments in our consolidated balance sheets were as follows:Fair Value of Derivative InstrumentsAsset Derivative InstrumentsLiability Derivative InstrumentsJune 30, 2018December 31, 2017June 30, 2018December 31, 2017(millions)Balance Sheet LocationFairValueBalance Sheet LocationFairValueBalance Sheet LocationFairValueBalance Sheet LocationFairValueCommodity DerivativeInstrumentsCurrent Assets$29Current Assets$2Current Liabilities$250Current Liabilities$58Noncurrent Assets—Noncurrent Assets—Noncurrent Liabilities85Noncurrent Liabilities15Total$29$2$335$73





The effect of commodity derivative instruments on our consolidated statements of operations was as follows:Three Months Ended June 30,Six Months Ended June 30,(millions)2018201720182017Cash Paid (Received) in Settlement of Commodity Derivative InstrumentsCrude Oil$66$(11)$96$(16)Natural Gas(1)—(3)2Total Cash Paid (Received) in Settlement of Commodity Derivative Instruments65(11)93(14)Non-cash Portion of Loss (Gain) on Commodity Derivative InstrumentsCrude Oil181(28)231(91)Natural Gas3(18)4(62)Total Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments184(46)235(153)Loss (Gain) on Commodity Derivative InstrumentsCrude Oil247(39)327(107)Natural Gas2(18)1(60)Total Loss (Gain) on Commodity Derivative Instruments$249$(57)$328$(167)








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Note
 5. Debt


Debt consists of the following:
 June 30, 2018December 31, 2017(millions, except percentages)DebtInterest RateDebtInterest RateRevolving Credit Facility, due March 9, 2023$——%$2302.27%Noble Midstream Services Revolving Credit Facility, due March 9, 20235303.25%852.75%Leviathan Term Loan Facility, due February 23, 2025——%——%Senior Notes, due May 1, 2021(1)——%3795.63%Senior Notes, due December 15, 20211,0004.15%1,0004.15%Senior Notes, due October 15, 20231007.25%1007.25%Senior Notes, due November 15, 20246503.90%6503.90%Senior Notes, due April 1, 20272508.00%2508.00%Senior Notes, due January 15, 20286003.85%6003.85%Senior Notes, due March 1, 20418506.00%8506.00%Senior Notes, due November 15, 20431,0005.25%1,0005.25%Senior Notes, due November 15, 20448505.05%8505.05%Senior Notes, due August 15, 20475004.95%5004.95%Other Senior Notes and Debentures(2)927.13%927.13%Capital Lease Obligations241—%273—%Total6,6636,859Unamortized Discount(23)(24)Unamortized Premium(1)—12Unamortized Debt Issuance Costs(38)(40)Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs6,6026,807Less Amounts Due Within One YearCapital Lease Obligations(47)(61)Long-Term Debt Due After One Year$6,555$6,746


(1)


(2)
  8
  84
  7.13


4
          500








350
  800








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0.5
  1.00


530
  Note 3. Acquisitions and Divestitures


1.0
  625


35


3.50
  3.25
  3.75
  1.00





Note


379
  395
  11
  5
  10
  5


1.0


500


0.00
  0.50
  1.00
  1.50











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Services Term Credit Agreement, the lenders may declare all amounts outstanding under the Noble Midstream Services Term Credit Agreement to be immediately due and payable and exercise other remedies as provided by applicable law.








Note
 6. Fair Value Measurements and Disclosures














Note


15
  Note 2. Basis of Presentation  Note














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


Fair Value Measurements Using(millions)Quoted Prices inActive Markets(Level 1)(1)Significant OtherObservable Inputs(Level 2)(2)SignificantUnobservableInputs   (Level 3)(3)Adjustment(4)Fair Value MeasurementJune 30, 2018Financial Assets:Mutual Fund Investments$57$—$—$—$57Commodity Derivative Instruments—72—(43)29Investment in Tamar Petroleum Ltd. (38,495,575 Shares)(5)—150——150Financial Liabilities:Commodity Derivative Instruments—(378)—43(335)Portion of Deferred Compensation Liability Measured at Fair Value(73)———(73)Stock Based Compensation Liability Measured at Fair Value(12)———(12)December 31, 2017Financial Assets:Mutual Fund Investments$57$—$—$—$57Commodity Derivative Instruments—7—(5)2Financial Liabilities:Commodity Derivative Instruments—(78)—5(73)Portion of Deferred Compensation Liability Measured at Fair Value(71)———(71)Stock Based Compensation Liability Measured at Fair Value(10)———(10)


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

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

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

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

|    |                                                                                                                                         
|--- | ----------------------------------------------------------------------------------------------------------------------------------------
|(5) | As of June 30, 2018, the closing price on the TASE of publicly traded and unrestricted shares of Tamar Petroleum Ltd. was$4.60per share.







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168
  Note 3. Acquisitions and Divestitures





The fair value of the investment is based on the published market price of the common units for the date indicated below.
 June 30, 2018December 31, 2017(millions)Carrying AmountFair ValueCarrying AmountFair ValueInvestment in CNX Midstream Partners (14,217,198 Common Units and 21,692,198 Common Units, respectively)(1)$49$276$70$364


|    |                                                                                                                                                        
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | During second quarter 2018, we sold7.5 millioncommon units, reducing our ownership in CNX Midstream Partners. SeeNote 3. Acquisitions and Divestitures.




Note


Fair value information regarding our debt is as follows:
 June 30, 2018December 31, 2017(millions)Carrying AmountFair ValueCarrying AmountFair ValueLong-Term Debt(1)$6,422$6,591$6,586$7,142


|    |                                                                                           
|--- | ------------------------------------------------------------------------------------------
|(1) | Excludes unamortized discount, premium, debt issuance costs and capital lease obligations.







Note
 7. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs





Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the same period:
 (millions)Six Months Ended June 30, 2018Capitalized Exploratory Well Costs, Beginning of Period$520Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves4Divestitures(1)(167)Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves(1)Capitalized Exploratory Well Costs Charged to Expense—Capitalized Exploratory Well Costs, End of Period$356(1) Represents costs primarily related to Gulf of Mexico assets.








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The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced:


(millions)June 30, 2018December 31, 2017Exploratory Well Costs Capitalized for a Period of One Year or Less$8$10Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling348510Balance at End of Period$356$520Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling78








2.6
  1.6
    859
  129


53


During the first half of 2018, we transferred$247 millionand$20 millionof undeveloped leasehold costs associated with Delaware Basin and Eagle Ford Shale assets, respectively, to proved properties. These transfers resulted from additions of proved reserves through development activities. In addition,$43 millionof capitalized costs associated with Gulf of Mexico leases and licenses was removed from undeveloped leasehold costs due to divestiture of the associated assets in second quarter 2018. SeeNote 3. Acquisitions and Divestitures .





Note
 8. Asset Retirement Obligations


Changes in ARO are as follows:
 Six Months Ended June 30,(millions)20182017Asset Retirement Obligations, Beginning Balance$875$935Liabilities Incurred1482Liabilities Settled(261)(32)Revisions of Estimates(10)(15)Accretion Expense(1)1723Asset Retirement Obligations, Ending Balance$635$993


|    |                                                                                                                                     
|--- | ------------------------------------------------------------------------------------------------------------------------------------
|(1) | Accretion expense is included in depreciation, depletion and amortization (DD&A)expense in the consolidated statements ofoperations.

216
  44
  11
  6
  7


For theSix Months Ended June 30, 2017Liabilities incurred include$59 millionrelated to the Clayton Williams Energy Acquisition and$23 millionprimarily for other US onshore wells and facilities placed into service. Liabilities settled primarily related to US onshore property abandonments, as well as$12 millionrelated to properties sold in the Marcellus Shale upstream divestiture. Revisions of estimates related to decreases in cost and timing estimates of$30 millionfor US onshore and Gulf of Mexico, partially offset by an increase of$15 million for West Africa.








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Note
 9. Income Taxes


The income tax (benefit) expense consists of the following:
 Three Months Ended June 30,Six Months Ended June 30,(millions, except percentages)2018201720182017Current$23$37$149$49Deferred(7)(873)(164)(873)Total Income Tax Expense (Benefit)$16$(836)$(15)$(824)Effective Tax Rate160.0%35.8%(2.7)%36.2%





268
  252
  16
  107
  145








145
    7.5


In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US –2014, Israel –2015(2013 with respect to Israel Oil Profits Tax) andEquatorial Guinea –2013 .








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Note
 10. Income Per Share Attributable to Noble Energy


Noble Energy's basic income (loss) per share of common stock is computed by dividing net income (loss) attributable to Noble Energy by the weighted average number of shares of Noble Energy common stock outstanding during each period. The following table summarizes the calculation of basic and diluted income (loss) per share:Three Months Ended June 30,Six Months Ended June 30,(millions, except per share amounts)2018201720182017Net (Loss) Income and Comprehensive (Loss) Income Attributable to Noble Energy$(23)$(1,512)$531$(1,476)Weighted Average Number of Shares Outstanding, Basic484472485452Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust——2—Weighted Average Number of Shares Outstanding, Diluted484472487452(Loss) Income Per Share, Basic$(0.05)$(3.20)$1.09$(3.27)(Loss) Income Per Share, Diluted(0.05)(3.20)1.09(3.27)Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above14161415








Note
 11. Segment Information





Oil and Gas Exploration and ProductionMidstream(millions)ConsolidatedUnitedStatesEasternMediter-   raneanWestAfricaOther Int'lUnited StatesIntersegment Eliminations and Other(1)CorporateThree Months Ended June 30, 2018Crude Oil Sales$749$635$2$112$—$—$—$—NGL Sales137137——————Natural Gas Sales214981115————Total Crude Oil, NGL and Natural Gas Sales1,100870113117————Income from Equity Method Investees and Other64——36—28——Sales of Purchased Oil and Gas6624———42——Intersegment Revenues—————85(85)—Total Revenues1,230894113153—155(85)—Lease Operating Expense132114519——(6)—Production and Ad Valorem Taxes5048———2——Gathering, Transportation and Processing Expense100133———22(55)—Other Royalty Expense1010——————Total Production Expense292305519—24(61)—DD&A4653941526—22(4)12Loss (Gain) on Divestitures(78)2110——(109)——








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Purchased Oil and Gas7131———40——Loss on Commodity Derivative Instruments249196—53————(Loss) Income Before Income Taxes10(90)6248(13)175(18)(154)Three Months Ended June 30, 2017Crude Oil Sales$557$458$1$98$—$—$—$—NGL Sales108108——————Natural Gas Sales3522141326————Total Crude Oil, NGL and Natural Gas Sales1,017780133104————Income from Equity Method Investees and Other42——25—17——Intersegment Revenues—————69(69)—Total Revenues1,059780133129—86(69)—Lease Operating Expense124105618——(5)—Production and Ad Valorem Taxes3232——————Gathering, Transportation and Processing Expense121142———17(38)—Other Royalty Expense66——————Total Production Expense283285618—17(43)—DD&A503427193915—12Loss on Marcellus Shale Upstream Divestiture2,3222,322——————Loss on Commodity Derivative Instruments(57)(51)—(6)————(Loss) Income Before Income Taxes(2,334)(2,319)10672(4)58(13)(234)Six Months Ended June 30, 2018Crude Oil Sales$1,522$1,317$4$201$—$—$—$—NGL Sales283283——————Natural Gas Sales46821824010————Total Crude Oil, NGL and Natural Gas Sales2,2731,818244211————Income from Equity Method Investees and Other124——71—53——Sales of Purchased Oil and Gas11955———64——Intersegment Revenues—————166(166)—Total Revenues2,5161,873244282—283(166)—Lease Operating Expense2872401241——(6)—Production and Ad Valorem Taxes104101———3——Gathering, Transportation and Processing Expense195260———43(108)—Other Royalty Expense2727——————Total Production Expense6136281241—46(114)—DD&A9338002852—38(8)23Gain on Divestitures(666)15(376)——(305)——








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Asset Impairments168168——————Purchased Oil and Gas12867———61——Loss on Commodity Derivative Instruments328260—68————Income (Loss) Before Income Taxes553(127)535112(27)428(40)(328)Six Months Ended June 30, 2017Crude Oil Sales$1,084$897$2$185$—$—$—$—NGL Sales213213——————Natural Gas Sales71444026311————Total Crude Oil, NGL and Natural Gas Sales2,0111,550265196————Income from Equity Method Investees and Other84——52—32——Intersegment Revenues—————127(127)—Total Revenues2,0951,550265248—159(127)—Lease Operating Expense2632111440——(2)—Production and Ad Valorem Taxes7372———1——Gathering, Transportation and Processing Expense240280———32(72)—Other Royalty Expense1010——————Total Production Expense5865731440—33(74)—DD&A1,0318863774210—22Loss on Marcellus Shale Upstream Divestiture2,3222,322——————Gain on Commodity Derivative Instruments(167)(154)—(13)————Income (Loss) Before Income Taxes(2,275)(2,251)207138(11)107(35)(430)June 30, 2018Goodwill(2)$1,402$1,291$—$—$—$111$—$—Total Assets21,85415,1382,9961,275622,280(140)243December 31, 2017Goodwill(2)1,3101,310——————Total Assets21,47615,7672,8461,3081141,357(163)247


(1)


(2) Goodwill in the United States reportable segment is associated with our Texas reporting unit. Goodwill in the Midstream segment is associated with the Saddle Butte acquisition.








Note
 12. Commitments and Contingencies





15
  1.4


450,000


83
    3





5
  5
  4
  83














Colorado Mechanical Integrity Testing Matter In July 2018, we received Notices of Alleged Violation (NOAVs) from the COGCC for alleged noncompliance of State mechanical integrity testing rules at eight shut-in wells in Weld County, Colorado.  The NOAVs order us to repair or plug and abandon each of the eight wells (or provide proof that such work has been completed) and to submit to COGCC certain environmental data.  We have met with COGCC enforcement leadership to discuss this matter and are working to timely complete the required corrective actions and submit the data requested in the NOAVs.  Given the uncertainty associated with administrative actions of this nature, we are unable to predict the ultimate outcome of this action at this time but believe that the resolution of this action will not have a material adverse effect on our financial position, results of operations or cash flows.














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

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

|  |                             
|- | ----------------------------
|• | Results of Operations – E&P;

|  |                                   
|- | ----------------------------------
|• | Results of Operations – Midstream;

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

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































Exploration and Production (E&P) – Results of Operations


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


Exploration and Production (E&P) – Development Projects


Exploration and Production (E&P) – Development Projects








---

Table of Contents





Exploration and Production (E&P) – Development Projects


Item 1. Financial Statements  – Note 4. Derivative Instruments and Hedging Activities


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


Item 1. Financial Statements – Note 5. Debt





Operating Outlook – 2018 Capital Investment Program








Exploration and Production (E&P) – Results of Operations





Item 1. Financial Statements – Note











|  |                                                                                                                              
|- | -----------------------------------------------------------------------------------------------------------------------------
|• | commodity prices which, if subject to a significant decline, could result in certain existing production becoming uneconomic;

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

|  |                                                                                                                                                                                                            
|- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | increased industry drilling activity in the basins in which we operate, which may cause US onshore cost inflation pressure and result in certain current production becoming less profitable or uneconomic;

|  |                                                                                                                                                                                         
|- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | Israeli industrial and residential demand for electricity, which is largely impacted by weather conditions and conversion of the Israeli electricity portfolio from coal to natural gas;

|  |                                                                                    
|- | -----------------------------------------------------------------------------------
|• | timing of crude oil and condensate liftings impacting sales volumes in West Africa;

|  |                                                                        
|- | -----------------------------------------------------------------------
|• | natural field decline in the US onshore and offshore Equatorial Guinea;

|  |                                                                                 
|- | --------------------------------------------------------------------------------
|• | additional purchases of producing properties or divestments of operating assets;







---

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|  |                                                                                                                         
|- | ------------------------------------------------------------------------------------------------------------------------
|• | potential weather-related volume curtailments (e.g., due to winter storms and flooding) impacting US onshore operations;

|  |                                                                                                                                                              
|- | -------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | availability or reliability of supplier materials and services, including access to support equipment and/or facilities which may cause delays in operations;

|  |                                                                                                                                                                                                                             
|- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | availability of, or curtailments imposed by, third party processing facilities, which could result in capacity constraints, and interruptions in midstream processing, which may cause production and sales volumes impacts;

|  |                                                                                                                                     
|- | ------------------------------------------------------------------------------------------------------------------------------------
|• | occurrence of pipeline disruptions, which may cause delays, restrictions or interruptions in production and/or midstream processing;

|  |                                                                                                                                                                                                                  
|- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | access to transportation and takeaway pipelines for increasing US onshore production volumes, such as in the Delaware Basin, which may cause infield bottlenecks and/or widening of location-basis differentials;

|  |                                                                                          
|- | -----------------------------------------------------------------------------------------
|• | malfunctions and/or mechanical failures at terminals or other US onshore delivery points;

|  |                                                             
|- | ------------------------------------------------------------
|• | impact of enhanced completion efforts for US onshore assets;

|  |                                                                                             
|- | --------------------------------------------------------------------------------------------
|• | potential growth from participation in future, or decline from existing, non-operated wells;

|  |                                            
|- | -------------------------------------------
|• | abandonment of low-margin US onshore wells;

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

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













|  |                                                                                                      
|- | -----------------------------------------------------------------------------------------------------
|• | commodity prices, including price realizations on specific crude oil, natural gas and NGL production;

|  |                                 
|- | --------------------------------
|• | operating and development costs;

|  |                                                                                 
|- | --------------------------------------------------------------------------------
|• | production, drilling and delivery commitments, or other contractual obligations;

|  |                                                                                                                          
|- | -------------------------------------------------------------------------------------------------------------------------
|• | access and availability of gathering, transportation, takeaway and processing capacity for US onshore production volumes;

|  |                  
|- | -----------------
|• | drilling results;

|  |                                        
|- | ---------------------------------------
|• | property acquisitions and divestitures;

|  |                      
|- | ---------------------
|• | exploration activity;

|  |                            
|- | ---------------------------
|• | cash flows from operations;

|  |                     
|- | --------------------
|• | indebtedness levels;

|  |                                                       
|- | ------------------------------------------------------
|• | availability of financing or other sources of funding;

|  |                                                                                                                                                                   
|- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | impact of new laws and regulations on our business practices, including potential legislative or regulatory changes regarding the use of hydraulic fracturing; and

|  |                                                                                           
|- | ------------------------------------------------------------------------------------------
|• | potential changes in the fiscal regimes of the US and other countries in which we operate.

Liquidity and Capital Resources – Financing Activities











---

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---

Table of Contents





























Item 1. Financial Statements – Note











|  |                                                    
|- | ---------------------------------------------------
|• | total average daily sales volumes of346MBoe/d, net;

|  |                                                                              
|- | -----------------------------------------------------------------------------
|• | record average daily sales volumes for US onshore crude oil of105MBbl/d, net;

|  |                                                                                                      
|- | -----------------------------------------------------------------------------------------------------
|• | record average daily sales volumes of over 1 Bcf/d, gross, in Israel, primarily from the Tamar field;

|  |                                                 
|- | ------------------------------------------------
|• | closed the Gulf of Mexico asset divestiture; and

|  |                                                                                                                                
|- | -------------------------------------------------------------------------------------------------------------------------------
|• | executed Heads of Agreement regarding framework for development of natural gas from the Alen field, offshore Equatorial Guinea.




|  |                                                                                                          
|- | ---------------------------------------------------------------------------------------------------------
|• | net cash proceeds of $383million, after closing adjustments, received from the Gulf of Mexico asset sale;

|  |                                                              
|- | -------------------------------------------------------------
|• | total loss of$249 millionon commodity derivative instruments;

|  |                                                                                                       
|- | ------------------------------------------------------------------------------------------------------
|• | pre-tax income of $7million, as compared with pre-tax loss of $2.1billion for second quarter 2017; and

|  |                                                                                                                    
|- | -------------------------------------------------------------------------------------------------------------------
|• | capital expenditures, excluding acquisitions, of$787 million, as compared with $613 millionfor second quarter 2017.










---

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Three Months Ended June 30,Six Months Ended June 30,(millions)2018201720182017Oil, NGL and Gas Sales to Third Parties(1)$1,100$1,017$2,273$2,011Sales of Purchased Gas(2)24—55—Income from Equity Method Investees36257152Total Revenues1,1601,0422,3992,063Production Expense(1)329309681627Exploration Expense29306472Depreciation, Depletion and Amortization435486880999Purchases of Gas(2)31—67—Loss on Marcellus Shale Upstream Divestiture—2,322—2,322(Loss) Gain on Divestitures(3)31—(361)—Asset Impairments(3)——168—Loss (Gain) on Commodity Derivative Instruments249(57)328(167)Clayton Williams Energy Acquisition Expenses(3)—90—94Income (Loss) Before Income Taxes7(2,145)493(1,917)


|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | On January 1, 2018, we adopted ASC 606. As a result of adoption, we changed the presentation of certain US midstream processing arrangements as related to net and gross presentation of revenues and expenses. This presentation change resulted in increases to revenues, and corresponding increases to production expense, of$2 millionand$7 millionfor second quarter and the first six months of 2018, respectively. SeeItem 1. Financial Statements – Note 2. Basis of Presentation.

|    |                                                                                                                                                                                                                                                        
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(2) | Beginning in first quarter 2018, as part of our Marcellus Shale firm transportation mitigation efforts, we entered into certain transactions for the purchase of third party natural gas and the subsequent sale of natural gas to other third parties.

|    |                                                                                                                         
|--- | ------------------------------------------------------------------------------------------------------------------------
|(3) | Amount relates to the Gulf of Mexico asset sale. SeeItem 1. Financial Statements - Note3. Acquisitions and Divestitures.










---

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Sales Volumes(1)Average Realized Sales Prices(1)Crude Oil & Condensate(MBbl/d)NGLs(MBbl/d)NaturalGas(MMcf/d)Total(MBoe/d)(2)Crude Oil & Condensate(Per Bbl)NGLs(Per Bbl)NaturalGas(Per Mcf)Three Months Ended June 30, 2018United States(3)10862467247$64.67$24.46$2.29Eastern Mediterranean——22538——5.46West Africa(4)17—2255472.79—0.27Total Consolidated Operations1256291733965.7724.462.57Equity Investees(5)25—776.0743.36—Total12767917346$65.93$25.90$2.57Three Months Ended June 30, 2017United States11063736296$45.78$18.79$3.20Eastern Mediterranean——27246——5.34West Africa(4)22—2316049.53—0.27Total Consolidated Operations132631,23940246.4018.793.13Equity Investees(5)24—650.9334.46—Total134671,239408$46.49$19.84$3.13Six Months Ended June 30, 2018United States(3)11563486259$63.23$25.00$2.47Eastern Mediterranean——24341——5.47West Africa(4)16—2155170.65—0.27Total Consolidated Operations1316394435164.1325.002.74Equity Investees(5)25—771.5641.61—Total13368944358$64.22$26.27$2.74Six Months Ended June 30, 2017United States10556733283$47.31$21.04$3.32Eastern Mediterranean——27246——5.33West Africa(4)20—2375951.28—0.27Total Consolidated Operations125561,24238847.9521.043.18Equity Investees(5)25—751.7135.38—Total127611,242395$48.01$22.29$3.18


|    |                                                                                                                                                                                                                                                                                                                                     
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | On January 1, 2018, we adopted ASC 606. As a result of adoption, we changed the presentation of certain US midstream processing arrangements as related to net and gross presentation of revenues and expenses. SeeItem 1. Financial Statements – Note 2. Basis of Presentation. This presentation change resulted in the following:

|  |                                                                                                                                                                               
|- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|◦ | increases in NGL revenues, and corresponding increases in production expense, of$4 millionand$9 millionfor second quarter 2018 and the first six months of 2018, respectively;

|  |                                                                                                                                                                 
|- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------
|◦ | decreases in natural gas revenues, and corresponding decreases in production expense, of$2 millionfor both second quarter 2018 and the first six months of 2018;

|  |                                                                                                                                                                         
|- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|◦ | increases in NGL and natural gas sales volumes of 5 MBbl/d and 31 MMcf/d, respectively, for both second quarter 2018 and the first six months of 2018, respectively; and

|  |                                                                                                                                                                                                               
|- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|◦ | reductions in average realized NGL and natural gas sales prices of $1.31/Bbl and $0.11/Mcf, respectively, for second quarter 2018 and $1.09/Bbl and $0.10/Mcf, respectively, for the first six months of 2018.







---

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|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(2) | 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 prices for a barrel of crude oil equivalent for US natural gas and NGLs are significantly less than the price for a barrel of crude oil. In Israel, we sell natural gas under contracts where the majority of the price is fixed, resulting in less commodity price disparity between reporting periods.

|    |                                                                                                                                                                                                                               
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(3) | Includes 3 MBoe/d and 14 MBoe/d for second quarter and the first six months of 2018, respectively,  related to Gulf of Mexico assets sold in April 2018. SeeItem Financial Statements – Note 3. Acquisitions and Divestitures.

|    |                                                                                                                                                                                                                                                                                                
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(4) | Natural gas from the Alba field in Equatorial Guinea is sold 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.

|    |                                                                                                                                     
|--- | ------------------------------------------------------------------------------------------------------------------------------------
|(5) | Volumes represent sales of condensate and LPG from the LPG plant in Equatorial Guinea. SeeIncome from Equity Method Investees,below.

Sales Revenues(millions)Crude Oil & CondensateNGLsNaturalGasTotalThree Months Ended June 30, 2017$557$108$352$1,017Changes due toDecrease in Sales Volumes(31)(10)(107)(148)Increase (Decrease) in Sales Prices(1)22335(29)229Impact of ASC 606 Adoption—4(2)2Three Months Ended June 30, 2018$749$137$214$1,100Six Months Ended June 30, 2017$1,084$213$714$2,011Changes due toIncrease (Decrease) in Sales Volumes491(192)(142)Increase (Decrease) in Sales Prices(1)38960(52)397Impact of ASC 606 Adoption—9(2)7Six Months Ended June 30, 2018$1,522$283$468$2,273


(1)





|  |                                                                                                                                                                                          
|- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | increases of42%and34%forsecond quarter and the first six months of 2018, respectively, in average realized prices due to the partial rebalancing of global supply and demand factors; and

|  |                                                                                                                                                                                                                                                                 
|- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | higher US onshore sales volumes of17MBbl/d and22MBbl/d forsecond quarter and the first six months of 2018, respectively, primarily driven by an increase in development activity in the Delaware Basin and DJ Basin and the Clayton Williams Energy acquisition;




|  |                                                                                                                                                                                                                             
|- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | lower Gulf of Mexico sales volumes of19MBbl/d and12MBbl/d forsecond quarter and the first six months of 2018, respectively, due to natural field decline as well as the sale of the Gulf of Mexico assets in April 2018; and

|  |                                                                                                                                                                    
|- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | lower offshore Equatorial Guinea sales volumes of5MBbl/d and4MBbl/d forsecond quarter and the first six months of 2018, respectively, due to natural field decline.




|  |                                                                                                                                                                                                                                                                                                                                             
|- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | higher US onshore sales volumes of 4 MBbl/d (exclusive of 5 MBbl/d from adoption of ASC 606) and 13 MBbl/d (exclusive of 5 MBbl/d from adoption of ASC 606) for second quarter and the first six months of 2018, respectively, primarily attributable to development activities in the southern area of Gates Ranch in the Eagle Ford Shale;

|  |                                                                                                                                                                                                  
|- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | increases of 37% and 24% in average realized prices for second quarter and the first six months of 2018, respectively,  due to the partial rebalancing of domestic supply and demand factors; and

|  |                                                                                                                                                
|- | -----------------------------------------------------------------------------------------------------------------------------------------------
|• | increases of $4 millionand $9 millionforsecond quarter and the first six months of 2018, respectively, associated with the adoption of ASC 606;




|  |                                                                                                                                                                           
|- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | lower sales volumes of 9 MBbl/d for second quarter and the first six months of 2018, due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017.







---

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|  |                                                                                                                                                                                                          
|- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | lower sales volumes of 331 MMcf/d and 350 MMcf/d for second quarter and the first six months of 2018, respectively, due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017;

|  |                                                                                     
|- | ------------------------------------------------------------------------------------
|• | lower sales volumes in Israel due to the sale of a 7.5% interest in the Tamar field;

|  |                                                                                                                                                                                                                                
|- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | lower Gulf of Mexico sales volume of 14 MMcf/d and 8 MMcf/d for the second quarter and the first six months of 2018, respectively, due to natural field decline as well as the sale of the Gulf of Mexico assets in April 2018;

|  |                                                                                                                                                                                                                                    
|- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | lower sales volumes of 6 MMcf/d and 21 MMcf/d for second quarter and the first six months of 2018, respectively, from the Alba field, offshore Equatorial Guinea, due to natural field decline and timing of field maintenance; and

|  |                                                                                                                                                                                                                                                             
|- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | decreases of 14% and 10% in average realized prices for second quarter and the first six months of 2018, respectively, due to the impact of increased onshore US supply, as well as wider summer price differentials for both DJ and Delaware Basin volumes;




|  |                                                                                                                                                                                                                                                                                                                                                                     
|- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | higher US onshore sales volumes of 53 MMcf/d (exclusive of 31 MMcf/d from adoption of ASC 606) and 89 MMcf/d (exclusive of 31 MMcf/d from adoption of ASC 606) the second quarter and the first six months of 2018, respectively, primarily attributable to development activities in the DJ Basin and the southern area of Gates Ranch in the Eagle Ford Shale; and

|  |                                                        
|- | -------------------------------------------------------
|• | higher sales volumes in Israel due to increased demand.
















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(millions, except unit rate)Total per BOE(1)  (2)TotalUnitedStates(2)EasternMediter-   raneanWest AfricaThree Months Ended June 30, 2018Lease Operating Expense(3)$4.47$138$114$5$19Production and Ad Valorem Taxes1.564848——Gathering, Transportation and Processing(4)4.31133133——Other Royalty Expense0.331010——Total Production Expense$10.67$329$305$5$19Total Production Expense per BOE$10.67$13.55$1.47$3.84Three Months Ended June 30, 2017Lease Operating Expense(3)$3.54$129$105$6$18Production and Ad Valorem Taxes0.893232——Gathering, Transportation and Processing(4)3.89142142——Other Royalty Expense0.1666——Total Production Expense$8.48$309$285$6$18Total Production Expense per BOE$8.48$10.60$1.46$3.28Six Months Ended June 30, 2018Lease Operating Expense(3)$4.62$293$240$12$41Production and Ad Valorem Taxes1.59101101——Gathering, Transportation and Processing(4)4.10260260——Other Royalty Expense0.432727——Total Production Expense$10.74$681$628$12$41Total Production Expense per BOE$10.74$13.42$1.64$4.39Six Months Ended June 30, 2017Lease Operating Expense(3)$3.78$265$211$14$40Production and Ad Valorem Taxes1.037272——Gathering, Transportation and Processing(4)3.99280280——Other Royalty Expense0.141010——Total Production Expense$8.94$627$573$14$40Total Production Expense per BOE$8.94$11.20$1.71$3.72


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

|    |                                                                                                                                                                                                
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(2) | United States E&P production expense includes charges from our midstream operations that are eliminated on a consolidated basis. SeeItem 1. Financial Statements – Note11. Segment Information.

|    |                                                                                                                                                                            
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(3) | Lease operating expense includes oil and gas operating costs (labor, fuel, repairs, replacements, saltwater disposal and other related lifting costs) and workover expense.

|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(4) | Upon adoption of ASC 606 on January 1, 2018, we changed the presentation for certain of our gathering, transportation and processing expenses in accordance with the control model under the new standard. As such, we reflected increases of$2 millionand$7 millionto gathering, transportation and processing expense related to US operations forsecond quarter and the first six months of 2018, respectively. On a per BOE basis, including the increase in production volumes, the presentation change resulted in decreases of$0.46/Boe and$0.35/Boe for US production expense for thesecond quarter and the first six months of 2018, respectively. No other geographical locations were affected by the presentation change. Comparative information for the prior period has not been recast and continues to be reported under ASC 605,Revenue Recognition, the accounting standard in effect for the prior period.




|  |                                                                                                                                                                   
|- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | an increase in US lease operating expense primarily due to increased development activities resulting in added production in across each of our onshore US basins;

|  |                                                                                  
|- | ---------------------------------------------------------------------------------
|• | an increase in US production and ad valorem taxes due to higher commodity prices;

|  |                                                                                                                                                                                                                
|- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | an increase in US gathering, transportation and processing expense attributable to development activities in the southern area of Gates Ranch in the Eagle Ford Shale which led to increased sales volumes; and







---

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|  |                                                                                  
|- | ---------------------------------------------------------------------------------
|• | an increase in US other royalty expense due to increased commodity market prices;




|  |                                                                                                                                                                                                               
|- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | a decrease in first quarter 2018 in US lease operating expense in the Gulf of Mexico due to lower production caused by natural field decline and the subsequent sale of the assets in second quarter 2018; and

|  |                                                                                                                                                                            
|- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | decreases in US lease operating and gathering, transportation and processing expenses due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017.













(millions, except unit rate)TotalUnitedStatesEasternMediter-   raneanWestAfricaOther Int'lThree Months Ended June 30, 2018DD&A Expense$435$394$15$26$—Unit Rate per BOE(1)$14.10$17.51$4.41$5.25$—Three Months Ended June 30, 2017DD&A Expense$486$427$19$39$1Unit Rate per BOE(1)$13.32$15.89$4.62$7.11$—Six Months Ended June 30, 2018DD&A Expense$880$800$28$52$—Unit Rate per BOE(1)$13.87$17.10$3.82$5.56$—Six Months Ended June 30, 2017DD&A Expense$999$886$37$74$2Unit Rate per BOE(1)$14.25$17.32$4.52$6.88$—








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







|  |                                                                                                                                                                                                                                                                                                    
|- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | year-end reserve additions, primarily in US onshore due to enhanced well design and completion techniques in our horizontal drilling program as well as reserve additions in the Tamar field due to well results and geological evaluation, and globally due to positive commodity price revisions;

|  |                                                                                                                                                                                               
|- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | the Marcellus Shale upstream divestiture in second quarter 2017, which reduced DD&A expense by $99 million and $118 million for second quarter and the first six months of 2018, respectively;

|  |                                                                                                                                                                                                                                                                                                                               
|- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | lower sales volumes in Gulf of Mexico due to natural field decline and classification of the assets as held for sale in first quarter 2018, resulting in the cessation of DD&A expense, together resulting in decreases of $62 million and $109 million for second quarter and the first six months of 2018, respectively; and

|  |                                                                                                                                                                                                                                                                                     
|- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | reclassification of a7.5%working interest in the Tamar field, offshore Israel, as asset held for sale at December 31, 2017, resulting in the cessation of DD&A expense and decreases of $3 million and $7 million for second quarter and the first six months of 2018, respectively;




|  |                                                                                                                                                                                           
|- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | higher sales volumes in the Delaware Basin, which more than doubled, due to increased development activities subsequent to the Clayton Williams Energy Acquisition in second quarter 2017;

|  |                                                                                                  
|- | -------------------------------------------------------------------------------------------------
|• | increased development activities in the southern area of Gates Ranch in the Eagle Ford Shale; and

|  |                                                                                           
|- | ------------------------------------------------------------------------------------------
|• | higher sales volumes from the Tamar field, offshore Israel, due to higher domestic demand.




Item 1. Financial Statements – Note   Item 1. Financial Statements – Note








|  |                                               
|- | ----------------------------------------------
|• | net cash settlement payment of$93 million; and

|  |                                                                                                                                                                                   
|- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | net non-cash increase of$235 millionin the fair value of our net commodity derivative liability, primarily driven by increases in the forward commodity price curve for crude oil.




|  |                                               
|- | ----------------------------------------------
|• | net cash settlement receipt of$14 million; and

|  |                                                                                                                                                                                         
|- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | net non-cash increase of$153 millionin the fair value of our net commodity derivative asset, driven by changes in the forward commodity price curves for both crude oil and natural gas.

Item 1. Financial Statements – Note    Note




















|  |                                                                      
|- | ---------------------------------------------------------------------
|• | commenced gathering services in the Mustang IDP area in the DJ Basin;

|  |                                                                                           
|- | ------------------------------------------------------------------------------------------
|• | completed construction of the Collier and Billy Miner Train II CGFs in the Delaware Basin;







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|  |                                                                                                                                                                                                             
|- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | secured long-term dedications, from existing and new third party customers, for the Black Diamond system, a large, integrated gathering system in the DJ Basin acquired in the Saddle Butte acquisition; and

|  |                                                                                                                                                           
|- | ----------------------------------------------------------------------------------------------------------------------------------------------------------
|• | received a third party producer's activity set and development plan for Delaware Basin acreage, with gathering services expected to commence in late 2018.




|  |                                                                                                                                                                             
|- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | net proceeds of approximately $135 million received, and gain of $109 million recognized, on the sale of a portion of our investment in CNX Midstream Partners common units;

|  |                                                                                                         
|- | --------------------------------------------------------------------------------------------------------
|• | pre-tax income of $175million, as compared with pre-tax income of $58million forsecond quarter 2017; and

|  |                                                                                                                   
|- | ------------------------------------------------------------------------------------------------------------------
|• | capital expenditures, excluding acquisitions, of$157 million, as compared with $88 million forsecond quarter 2017.

Three Months Ended June 30,Six Months Ended June 30,(millions)2018201720182017Midstream Services Revenues – Third Party$15$4$28$4Sales of Purchased Oil42—64—Income from Equity Method Investees13132528Intersegment Revenues8569166127Total Revenues15586283159Operating Costs and Expenses27236142Depreciation and Amortization2253810Gain on Divestitures(109)—(305)—Purchased Oil40—61—Total (Income) Expense(20)28(145)52Income Before Income Taxes$175$58$428$107

















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








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Three Months Ended June 30,Six Months Ended June 30,(millions, except unit rate)2018201720182017G&A Expense$105$103$209$202Unit Rate per BOE(1)$3.40$2.82$3.29$2.88


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




Item 1. Financial Statements – Note   Item 1. Financial Statements – Note


Three Months Ended June 30,Six Months Ended June 30,(millions, except unit rate)2018201720182017Interest Expense, Gross$91$107$181$206Capitalized Interest(18)(11)(35)(23)Interest Expense, Net$73$96$146$183Unit Rate per BOE(1)$2.37$2.63$2.30$2.61


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

Item 1. Financial Statements - Note


Item 1. Financial Statements - Note


























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Operating Outlook – Impact of Recent Changes in US Tax Law

















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|• | redemption of $379 millionin outstanding senior notes;

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|- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | acquisition of1.8 millionshares of Noble Energy stock, for $63 million, resulting in year to date repurchases of4.0 millionshares for $130 million, pursuant to the Board of Directors' authorized $750million share repurchase program; and

|  |                                                                                                                               
|- | ------------------------------------------------------------------------------------------------------------------------------
|• | announcement in July 2018 of an August 2018 dividend of 11 cents per common share, which continues the 10% increase over 2017.




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|• | repaid all amounts outstanding under the Revolving Credit Facility;

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|• | extended the Revolving Credit Facility maturity date by two and a half years to March 2023;

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|• | amended the Noble Midstream Services Revolving Credit Facility to increase the capacity from$350 millionto$800 million; and

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|- | ---------------------------------------------------------------------------------------------------------------------------
|• | extended the maturity date of the Noble Midstream Services Revolving Credit Facility by one and a half years to March 2023.







June 30,December 31,(millions, except percentages)20182017Total Cash(1)$621$713Amount Available to be Borrowed Under Revolving Credit Facility(2)4,0003,770Total Liquidity$4,621$4,483Total Debt(3)$6,663$6,859Noble Energy Share of Equity10,2529,936Ratio of Debt-to-Book Capital(4)39%41%








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|    |                                                                                                                                                                                                                                                                                                                       
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | As ofJune 30, 2018, total cash included cash and cash equivalents of $15 million related to Noble Midstream Partners. As ofDecember 31, 2017, total cash included $18 million cash of Noble Midstream Partners and $38 million restricted cash related to the Saddle Butte acquisition that closed first quarter 2018.

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|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(2) | Excludes amounts available to be borrowed under the Noble Midstream Services Revolving Credit Facility and Leviathan Term Loan Facility, which are not available to Noble Energy for general corporate purposes. See discussion below.

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|--- | --------------------------------------------------------------------------------------------------------------------------------------------
|(3) | Total debt includes capital lease obligations and excludes unamortized debt discount/premium. SeeItem 1. Financial Statements – Note5. Debt.

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|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(4) | 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 Noble Energy's share of equity.




Item 1. Financial Statements – Note 6. Debt








Item 1. Financial Statements – Note    Item 3. Quantitative and Qualitative Disclosures About Market Risk.


Item 1. Financial Statements – Note























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Item 1. Financial Statements – Note 12. Commitments and Contingencies








Six Months Ended June 30,(millions)20182017Total Cash Provided By (Used in)Operating Activities$1,079$877Investing Activities(1,050)(1,121)Financing Activities(121)(426)Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash$(92)$(670)











Operating Outlook – 2018 Capital Investment Program

















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Item 1. Financial Statements – Consolidated Statements of Cash Flows





Three Months Ended June 30,Six Months Ended June 30,(millions)2018201720182017Acquisition, Capital and Exploration ExpendituresUnproved Property Acquisition(1)$—$1,581$—$1,826Proved Property Acquisition(2)—782—840Exploration and Development7716051,4271,199Midstream(3)157152616245Corporate and Other16102715Total$944$3,130$2,070$4,125Investment in Equity Method Investee(4)$—$67$—$67


(1)


(2)


(3)


(4)














Results of Operations - E&P











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Item 1. Financial Statements – Note














Item 1. Financial Statements – Note




















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|• | our growth strategies;

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

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

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|- | -----------------------------------------------------------------------------------------------------------------------------------------------------
|• | our ability to satisfy contractual commitments, including utilization or commercialization of firm transportation commitments in the Marcellus Shale;

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

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

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







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

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

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































Part I. Financial Information, Item 1. Financial Statements - Note























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PeriodTotal Number ofSharesPurchased(1)AveragePrice PaidPer ShareTotal Number ofShares Purchasedas Part of PubliclyAnnounced Plans orPrograms(2)Approximate DollarValue of Shares thatMay Yet BePurchased Under thePlans or Programs(millions)4/1/2018 - 4/30/2018216$31.72—5/1/2018 - 5/31/2018837,99532.84837,4186/1/2018 - 6/30/2018941,77935.65941,502Total1,779,990$34.331,778,920$620


|    |                                                                                                                                                                                                                           
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | Includes stock repurchases of1,070during the period relating 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.

|    |                                                                                                                                                                                                                                                                  
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(2) | Duringsecond quarter 2018, we repurchased and retired1.8 millionshares of common stock at an average purchase price of$35.15per share pursuant to the $750million share repurchase program, authorized by our Board of Directors, which expiresDecember 31, 2020.







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Exhibit NumberExhibit*2.1Agreement and Plan of Merger, dated as of January 13, 2017, by and among Noble Energy, Inc., Wild West Merger Sub Inc., NBL Permian LLC, and Clayton Williams Energy, Inc. (filed as Exhibit 2.1 to the Registrant’s Current Report on Form 8-K (Date of Report: January 13, 2017) filed on January 17, 2017 and incorporated herein by reference).2.2Agreement and Plan of Merger, dated as of May 10, 2015, by and among Noble Energy, Inc., Bluebonnet Merger Sub Inc. and Rosetta Resources Inc. (filed as Exhibit 2.1 of the Registrant’s Current Report on Form 8-K (Date of Report: May 10, 2015) filed on May 11, 2015 and incorporated herein by reference).2.3Exchange Agreement, executed October 29, 2016, by and between CNX Gas Company LLC and Noble Energy, Inc. (filed as Exhibit 2.3 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2016 and incorporated herein by reference).3.1Restated Certificate of Incorporation of Noble Energy Inc., (filed as Exhibit 3.3 to the Registrant’s Current Report on Form 8-K (Date of Report: July 26, 2016) filed on July 28, 2016 and incorporated herein by reference).3.2By-Laws of Noble Energy, Inc. (as amended through January 30, 2018) (filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K (Date of Report: January 30, 2018) filed on February 1, 2018 and incorporated herein by reference).3.3Certificate of Elimination of the Series A Junior Participating Preferred Stock of Noble Energy, Inc. (filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K (Date of Report: July 26, 2016) filed on July 28, 2016 and incorporated herein by reference).3.4Certificate of Elimination of the Series B Mandatorily Convertible Preferred Stock of Noble Energy, Inc. (filed as Exhibit 3.2 to the Registrant’s Current Report on Form 8-K (Date of Report: July 26, 2016) filed on July 28, 2016 and incorporated herein by reference).10.1*Noble Energy, Inc. Short-Term Incentive Plan, 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), furnished 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), furnished herewith.101.INSInstance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.101.SCHXBRL Schema Document101.CALXBRL Calculation Linkbase Document101.LABXBRL Label Linkbase Document101.PREXBRL Presentation Linkbase Document101.DEFXBRL Definition Linkbase Document








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*Management contract or compensatory plan or arrangement required to be filed as an exhibit hereto.**Copies of exhibits will be furnished upon prepayment of 25 cents per page. Requests should be addressed to the Executive Vice President and Chief Financial Officer, Noble Energy, Inc., 1001 Noble Energy Way, Houston, Texas 77070.

















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NOBLE ENERGY, INC.(Registrant)DateAugust 3, 2018/s/ Kenneth M. FisherKenneth M. FisherExecutive Vice President, Chief Financial Officer