UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.  20549

FORM 10-Q
 
ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2018March 31, 2019

OR
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____to_____

Commission file number: 001-07964

nbllogoupdated9302014a68.jpg

NOBLE ENERGY, INC.
(Exact name of registrant as specified in its charter)
Delaware 73-0785597
(State or other jurisdiction of incorporation or organization) (I.R.S. employer identification number)
1001 Noble Energy Way  
Houston, Texas 77070
(Address of principal executive offices) (Zip Code)
(281) 872-3100
(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes ý    No o 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes ý    No o
 Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller
reporting company or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. 
Large accelerated filer x
Accelerated filer o
Non-accelerated filer o
Smaller reporting company o
Emerging growth company o
(Do not check if a smaller reporting company)
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o    No ý
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common Stock, $0.01 par valueNBLNew York Stock Exchange

As of June 30, 2018,March 31, 2019, there were 483,118,790478,231,487 shares of the registrant’s common stock, par value $0.01 per share, outstanding.



TABLE OF CONTENTS
 
Part I. Financial Information
3
  
Item 1. Financial Statements 
3
  
Consolidated Statements of Operations and Comprehensive (Loss) Income
3
  
Consolidated Balance Sheets
4
  
Consolidated Statements of Cash Flows
5
  
Consolidated Statements of Equity
6
  
Notes to Consolidated Financial Statements
7
  
Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations
2922
  
Item 3.  Quantitative and Qualitative Disclosures About Market Risk   
4635
  
Item 4.  Controls and Procedures
4836
  
Part II. Other Information  
4836
  
Item 1.  Legal Proceedings 
4836
  
Item 1A.  Risk Factors 
4836
  
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
4836
  
Item 3. Defaults Upon Senior Securities    
5036
  
Item 4. Mine Safety Disclosures  
5036
  
Item 5. ��Other Information
5036
  
Item 6.  Exhibits 
5137
  
Signatures
5338

Table of Contents

Part I. Financial Information
Item 1. Financial Statements
Noble Energy, Inc.
Consolidated Statements of Operations and Comprehensive (Loss) Income
(millions, except per share amounts)
(unaudited)
Three Months Ended June 30, Six Months Ended June 30,Three Months Ended March 31,
2018 2017 2018 20172019 2018
Revenues          
Oil, NGL and Gas Sales$1,100
 $1,017
 $2,273
 $2,011
$937
 $1,173
Income from Equity Method Investees and Other130
 42
 243
 84
Sales of Purchased Oil and Gas74
 53
Other Revenue41
 60
Total1,230
 1,059
 2,516
 2,095
1,052
 1,286
Costs and Expenses 
  
       
Production Expense292
 283
 613
 586
305
 319
Exploration Expense29
 30
 64
 72
Depreciation, Depletion and Amortization465
 503
 933
 1,031
508
 468
Loss on Marcellus Shale Upstream Divestiture—
 2,322
 —
 2,322
General and Administrative102
 104
Cost of Purchased Oil and Gas87
 57
Other Operating Expense, Net49
 50
Gain on Divestitures, Net(78) —
 (666) —
—
 (588)
Asset Impairments—
 —
 168
 —
—
 168
General and Administrative105
 103
 209
 202
Other Operating Expense, Net74
 118
 144
 147
Firm Transportation Exit Cost92
 —
Total887
 3,359
 1,465
 4,360
1,143
 578
Operating Income (Loss)343
 (2,300) 1,051
 (2,265)
Other (Income) Expense 
  
    
Loss (Gain) on Commodity Derivative Instruments249
 (57) 328
 (167)
Operating (Expense) Income(91) 708
Other Expense   
Loss on Commodity Derivative Instruments212
 79
Interest, Net of Amount Capitalized73
 96
 146
 183
66
 73
Other Non-Operating Expense (Income), Net11
 (5) 24
 (6)
Other Non-Operating Expense, Net4
 13
Total333
 34
 498
 10
282
 165
Income (Loss) Before Income Taxes10
 (2,334) 553
 (2,275)
Income Tax Expense (Benefit)16
 (836) (15) (824)
(Loss) Income Before Income Taxes(373) 543
Income Tax Benefit(84) (31)
Net (Loss) Income and Comprehensive (Loss) Income Including Noncontrolling Interests(6) (1,498) 568
 (1,451)(289) 574
Less: Net Income and Comprehensive Income Attributable to Noncontrolling Interests17
 14
 37
 25
24
 20
Net (Loss) Income and Comprehensive Income (Loss) Attributable to Noble Energy$(23) $(1,512) $531
 $(1,476)
Net (Loss) Income and Comprehensive (Loss) Income Attributable to Noble Energy$(313) $554
       

 

Net (Loss) Income Attributable to Noble Energy per Common Share       
Net (Loss) Income Attributable to Noble Energy Common Shareholders per Share   
Basic$(0.05) $(3.20) $1.09
 $(3.27)$(0.65) $1.14
Diluted$(0.05) $(3.20) $1.09
 $(3.27)$(0.65) $1.14
Weighted Average Number of Common Shares Outstanding          
Basic484
 472
 485
 452
478
 487
Diluted484
 472
 487
 452
478
 488







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

Noble Energy, Inc.
Consolidated Balance Sheets
(millions)
(unaudited)

June 30,
2018		 December 31,
2017		March 31, 2019 December 31, 2018
ASSETS      
Current Assets      
Cash and Cash Equivalents$621
 $675
$528
 $716
Accounts Receivable, Net743
 748
573
 616
Other Current Assets187
 780
142
 418
Total Current Assets1,551
 2,203
1,243
 1,750
Property, Plant and Equipment 
  
 
  
Oil and Gas Properties (Successful Efforts Method of Accounting)28,334
 29,678
29,364
 29,002
Property, Plant and Equipment, Other896
 879
1,012
 891
Total Property, Plant and Equipment, Gross29,230
 30,557
30,376
 29,893
Accumulated Depreciation, Depletion and Amortization(11,313) (13,055)(11,675) (11,474)
Total Property, Plant and Equipment, Net17,917
 17,502
18,701
 18,419
Other Noncurrent Assets984
 461
1,376
 841
Goodwill1,402
 1,310
Total Assets$21,854
 $21,476
$21,320
 $21,010
LIABILITIES AND EQUITY   
LIABILITIES, MEZZANINE EQUITY AND SHAREHOLDERS' EQUITY   
Current Liabilities   
   
Accounts Payable – Trade$1,308
 $1,161
$1,284
 $1,207
Other Current Liabilities745
 578
659
 519
Total Current Liabilities2,053
 1,739
1,943
 1,726
Long-Term Debt6,555
 6,746
6,738
 6,574
Deferred Income Taxes970
 1,127
961
 1,061
Other Noncurrent Liabilities995
 1,245
1,438
 1,165
Total Liabilities10,573
 10,857
$11,080
 $10,526
Commitments and Contingencies

 



 


Mezzanine Equity   
Redeemable Noncontrolling Interest, Net$97
 $—
Shareholders’ Equity 
  
 
  
Preferred 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, respectively5
 5
Preferred 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; 522 Million and 520 Million Shares Issued, respectively5
 5
Additional Paid in Capital8,329
 8,438
8,219
 8,203
Accumulated Other Comprehensive Loss(28) (30)(32) (32)
Treasury Stock, at Cost; 39 Million Shares(731) (725)(735) (730)
Retained Earnings2,677
 2,248
1,614
 1,980
Noble Energy Share of Equity10,252
 9,936
9,071
 9,426
Noncontrolling Interests1,029
 683
1,072
 1,058
Total Equity11,281
 10,619
Total Liabilities and Equity$21,854
 $21,476
Total Shareholders' Equity10,143
 10,484
Total Liabilities, Mezzanine Equity and Shareholders' Equity$21,320
 $21,010




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

Table of Contents

Noble Energy, Inc.
Consolidated Statements of Cash Flows
(millions)
(unaudited)
Six Months Ended June 30,Three Months Ended March 31,
2018 20172019 2018
Cash Flows From Operating Activities      
Net Income (Loss) Including Noncontrolling Interests$568
 $(1,451)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities   
Net (Loss) Income Including Noncontrolling Interests$(289) $574
Adjustments to Reconcile Net (Loss) Income to Net Cash Provided by Operating Activities   
Depreciation, Depletion and Amortization933
 1,031
508
 468
Loss on Marcellus Shale Upstream Divestiture—
 2,322
Deferred Income Tax Benefit(100) (157)
Loss on Commodity Derivative Instruments212
 79
Net Cash Received (Paid) in Settlement of Commodity Derivative Instruments14
 (28)
Other Adjustments for Noncash Items Included in Income28
 (2)
Gain on Divestitures, Net(666) —
—
 (588)
Asset Impairments168
 —
—
 168
Deferred Income Tax Benefit(164) (873)
Loss (Gain) on Commodity Derivative Instruments328
 (167)
Net Cash (Paid) Received in Settlement of Commodity Derivative Instruments(93) 14
Stock Based Compensation35
 67
Other Adjustments for Noncash Items Included in Income (Loss)22
 33
Firm Transportation Exit Cost92
 —
Changes in Operating Assets and Liabilities      
Decrease (Increase) in Accounts Receivable76
 (123)
(Decrease) Increase in Accounts Payable(24) 120
Decrease in Current Income Taxes Payable3
 (42)
Decrease in Accounts Receivable9
 89
Increase (Decrease) in Accounts Payable106
 (33)
Increase in Current Income Taxes Payable45
 14
Other Current Assets and Liabilities, Net(58) (42)(52) (18)
Other Operating Assets and Liabilities, Net(49) (12)(45) 17
Net Cash Provided by Operating Activities1,079

877
528

583
Cash Flows From Investing Activities      
Additions to Property, Plant and Equipment(1,782) (1,215)(763) (787)
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—
 1,028
Clayton Williams Energy Acquisition—
 (616)
Acquisitions, Net of Cash Acquired(650) (351)
Proceeds from Other Divestitures72
 101
Acquisitions, Net of Cash Received—
 (650)
Additions to Equity Method Investments—
 (68)(271) —
Other—
 —
Proceeds from Divestitures, Net123
 865
Net Cash Used in Investing Activities(1,050)
(1,121)(911)
(572)
Cash Flows From Financing Activities      
Proceeds from Revolving Credit Facility50
 245
Repayment of Revolving Credit Facility(50) (475)
Proceeds from Noble Midstream Services Revolving Credit Facility345
 405
Repayment of Noble Midstream Services Revolving Credit Facility(175) (55)
Dividends Paid, Common Stock(102) (92)(53) (48)
Purchase and Retirement of Common Stock(130) —
—
 (67)
Proceeds from Noble Midstream Services Revolving Credit Facility610
 195
Repayment of Noble Midstream Services Revolving Credit Facility(165) (5)
Contributions from Noncontrolling Interest Owners331
 —
10
 333
Issuance of Noble Midstream Partners Common Units, Net of Offering Costs—
 138
Proceeds from Revolving Credit Facility905
 1,310
Repayment of Revolving Credit Facility(1,135) (1,310)
Repayment of Clayton Williams Energy Long-term Debt—
 (595)
Repayment of Senior Notes(384) —
Proceeds from Issuance of Mezzanine Equity, Net of Offering Costs99
 —
Other(51) (67)(32) (40)
Net Cash Used in Financing Activities(121)
(426)
Decrease in Cash, Cash Equivalents, and Restricted Cash(92)
(670)
Net Cash Provided by Financing Activities194

298
(Decrease) Increase in Cash, Cash Equivalents, and Restricted Cash(189)
309
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period713
 1,210
719
 713
Cash, Cash Equivalents, and Restricted Cash at End of Period$621
 $540
$530
 $1,022


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


Noble Energy, Inc.
Consolidated Statements of Shareholders' Equity
(millions)
(unaudited)

Attributable to Noble Energy    Attributable to Noble Energy    
Common
Stock
 
Additional
Paid in
Capital
 
Accumulated Other
Comprehensive
Loss
 
Treasury
Stock at
Cost
 
Retained
Earnings
 
Non-
controlling Interests
 Total EquityCommon Stock Additional Paid in Capital Accumulated Other Comprehensive Loss Treasury Stock at Cost Retained Earnings Non- controlling Interests Total Equity
December 31, 2018$5
 $8,203
 $(32) $(730) $1,980
 $1,058
 $10,484
Net (Loss) Income—
 —
 —
 —
 (313) 24
 (289)
Stock-based Compensation—
 14
 —
 —
 —
 —
 14
Dividends (11 cents per share)—
 —
 —
 —
 (53) —
 (53)
Distributions to Noncontrolling Interest Owners—
 —
 —
 —
 —
 (17) (17)
Contributions from Noncontrolling Interest Owners—
 —
 —
 —
 —
 10
 10
Other—
 2
 —
 (5) —
 (3) (6)
March 31, 2019$5
 $8,219
 $(32) $(735) $1,614
 $1,072
 $10,143
             
December 31, 2017$5
 $8,438
 $(30) $(725) $2,248
 $683
 $10,619
$5
 $8,438
 $(30) $(725) $2,248
 $683
 $10,619
Net Income—
 —
 —
 —
 531
 37
 568
—
 —
 —
 —
 554
 20
 574
Stock-based Compensation—
 46
 —
 —
 —
 —
 46
—
 17
 —
 —
 —
 —
 17
Dividends (21 cents per share)—
 —
 —
 —
 (102) —
 (102)
Dividends (10 cents per share)—
 —
 —
 —
 (48) —
 (48)
Purchase and Retirement of Common Stock—
 (130) —
 —
 —
 —
 (130)—
 (67) —
 —
 —
 —
 (67)
Clayton Williams Energy Acquisition—
 (25) —
 —
 —
 —
 (25)—
 (25) —
 —
 —
 —
 (25)
Distributions to Noncontrolling Interest Owners—
 —
 —
 —
 —
 (22) (22)—
 —
 —
 —
 —
 (11) (11)
Contributions from Noncontrolling Interest Owners—
 —
 —
 —
 —
 331
 331
—
 —
 —
 —
 —
 331
 331
Other—
 —
 2
 (6) —
 —
 (4)—
 —
 1
 (6) —
 2
 (3)
June 30, 2018$5
 $8,329
 $(28) $(731) $2,677
 $1,029
 $11,281
             
December 31, 2016$5
 $6,450
 $(31) $(692) $3,556
 $312
 $9,600
Net (Loss) Income—
 —
 —
 —
 (1,476) 25
 (1,451)
Clayton Williams Energy Acquisition—
 1,876
 —
 (25) —
 —
 1,851
Stock-based Compensation—
 65
 —
 —
 —
 —
 65
Dividends (20 cents per share)—
 —
 —
 —
 (92) —
 (92)
Issuance of Noble Midstream Partners Common Units, Net of Offering Costs—
 —
 —
 —
 —
 138
 138
Distributions to Noncontrolling Interest Owners—
 —
 —
 —
 —
 (12) (12)
Other—
 8
 1
 (10) —
 —
 (1)
June 30, 2017$5
 $8,399
 $(30) $(727) $1,988
 $463
 $10,098
March 31, 2018$5
 $8,363
 $(29) $(731) $2,754
 $1,025
 $11,387



















The accompanying notes are an integral part of these consolidated financial statements.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)




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 DJDenver-Julesburg (DJ) Basin, Delaware Basin and Eagle Ford Shale and Marcellus Shale (until June 2017);Shale; US offshore Gulf of Mexico (until April 2018); Eastern Mediterranean; and West Africa. Our Midstream segment develops, owns operates, develops and acquiresoperates domestic midstream infrastructure assets, as well as invests in other midstream projects, 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 at June 30, 2018March 31, 2019 and December 31, 20172018 and for the three and six months ended June 30,March 31, 2019 and 2018 and 2017 contain all normally recurring adjustments considered necessary for a fair presentation of our financial position, results of operations, cash flows and equity for such periods. Certain prior-period amounts have been reclassified to conform to the current period presentation. 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.
Operating results for the three and six months ended June 30, 2018March 31, 2019 are not necessarily indicative of the results that may be expected for the year ending December 31, 2018.2019.
These consolidated financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, 2017.2018.
Consolidation Our consolidated financial statements include our accounts, the accounts of subsidiaries which Noble Energy wholly owns, and the accounts of Noble Midstream Partners LP (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 PetroleumLeases We account for our investment in shares of Tamar Petroleum Ltd. at fair valuedetermine whether an arrangement contains a lease based on the conveyed rights and record changes in fair value in other non-operating expense (income), net in our consolidated statements of operations. See Note 3. Acquisitions and Divestitures and 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 valuesobligations at the inception date. If an agreement contains an operating or financing lease, at the commencement date, of acquisition. Amortization is calculated usingwe record a right-of-use (ROU) asset and a corresponding lease liability based on 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 of seven to 13 years. As of June 30, 2018, the gross bookpresent value of the intangible asset was $340 million. Amortizationminimum lease payments.
As most of our leases do not provide an implicit borrowing rate, to determine the present value of lease payments, we use our hypothetical secured borrowing rate based on information available at lease commencement. Further, we make a number of estimates and judgments regarding the lease term and lease payments.
Lease Term Leases with an initial term of 12 months or less are not recorded on the balance sheet and we recognize lease expense for these leases on a straight-line basis over the lease term. Most leases include one or more options to renew, with renewal terms that can extend the lease term from one month to one year or more. Additionally, some of $9 millionour leases include an option for early termination. We include renewal periods and $14 million forexclude termination periods from our lease term if, at commencement, it is reasonably likely that we will exercise the three 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. See Note 3. Acquisitions and Divestitures.option.
Stock Repurchase ProgramLease Payments On February 15, 2018, we announcedCertain of our lease agreements include rental payments that are adjusted periodically for inflation or passage of time. These step payments are included within our present value calculation as they are known adjustments at commencement. Some of our lease agreements include variable payments that are excluded from our present value calculation. For example, drilling rig ROU assets and lease liabilities are recorded using the Company's Board of Directors authorized a $750 million share repurchase programcontractual standby rate, which expires December 31, 2020. All purchases will be made from timeis the fixed, minimum monthly payment, as opposed to time in the open market or private transactions,operating rate, which varies depending on market conditions,the asset's use.
Additionally, we have lease agreements that include lease and may be discontinued atnon-lease components, such as equipment maintenance, which are generally accounted for as a single lease component. For these leases, lease payments include all fixed payments stated within the contract. For office space, lease and non-lease components are accounted for separately. Our lease agreements do not contain any time. During second quarter and the first six months of 2018, we repurchased and retired 1.8 million shares and 4.0 million shares of common stock at an average purchase price of $35.15 per share and $32.41 per share, respectively.
ASC 606, Revenue from Contracts with CustomersOur 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 thematerial residual value guarantees that would impact our lease payments.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)



modified retrospective method. Under ASC 606, performance obligations areRevenue RecognitionWe recognize revenue at an amount that reflects the unit of account and generally represent distinctconsideration we expect to be entitled to in exchange for transferring goods or services that are promised to customers. For sales of crude oil, NGLs and natural gas, each unit sold is generally considered a distinct good and the related performance obligation is generally satisfied at a point in time. We recognize our sales revenues at a point in time and upon delivery to a customer, at the contractually stated price and for the quantity of product delivered. In Israel, because our contracts are long-term arrangements, we recognize revenues from the sale of natural gas over the life of the contract based on the quantity of natural gas delivered.
ASC 606 provides additional clarification related to principal versus agent considerations. Under this guidance, we record revenue onusing a gross basis if we control a promised good or service before transferring it to a customer. For example, gathering, processing, transportation and fractionation costs incurred before transfer of control to the customer at the tailgate of a plant are accounted for as fulfillment costs and are presented as a component of gathering, transportation and processing expense in our consolidated statements of operations. On the other hand, we record revenue on a net basis if our role is to arrange for another entity to provide the goods or services. For example, costs incurred after control over the product has transferred to the customer, such as at the wellhead or inlet of a plant, are recorded as a reduction of the transaction price received within revenue.
Certain of our contracts for the sale of commodities contain embedded derivatives. We have elected the normal purchases and normal sales scope exception as provided by ASC 815, Derivatives and Hedging, and will account for such contractsfive-step process, in accordance with ASC 606.
In the US, we enter into marketing agreements with our non-operating partners to market and sell their share of production to third parties. We have determined that we act as an agent in such arrangements and account for such arrangements on a net basis.
ASC 606 adoption did not have an impact on the opening balance of retained earnings. The adoption resulted in de minimis increases of $2 million and $7 million to both revenues and expenses for second quarter and the first six months of 2018, respectively, but did not affect operating or net income or operating cash flows. The comparative information for the prior period has not been recast and continues to be reported under the accounting standards in effect for the period. Adoption of the new standard did not impact our financial position, and we do not expect that it will do so going forward.
Changes to the presentation of commodity sales revenue and production expense resulted from our assessment of certain contractual arrangements under principal versus agent guidance and assessment of control under ASC 606. In particular, we have determined that the processor is our customer with regard to the sale of natural gas at the wellhead or the sale of NGLs at the tailgate. This is a change from previous conclusions reached under principal versus agent guidance per ASC 605, Revenue Recognition, where we previously retained control over our production until the sale to the end customer in the downstream markets. As such, effective January 1, 2018, revenues and expenses are presented on a net basis within revenues in our consolidated statements of operations at the time control over production is transferred to the processor under these arrangements.
Following the control model in ASC 606, we determined that we remain the principal in arrangements with the end customers, such as when we take product in-kind at the tailgate and when we are directly responsible for the transportation and marketing of our production in the downstream markets. In such arrangements, we record NGL and natural gas sales and production expense on a gross basis.
Our commodity sale contracts in the US are index-based and, thus, include variable consideration. In accordance with ASC 606, we allocate variable consideration (market price) to the distinct commodities transferred in the period, but not to the future obligations to deliver production. Such allocation represents the amount of consideration to which we are entitled for deliveries of our commodities to-date and represents the value of product delivered to the customer. Therefore, our revenue is recognized at the time of delivery and is the product of the volume delivered and the index-based price for the period.
The following is a summary of our types of revenue arrangements by commodity and geographic location.
EXPLORATION AND PRODUCTION (E&P) REVENUE ARRANGEMENTS
Crude Oil Sale Arrangements – US We sell the majority of our US crude oil productionunder short-term contracts at market-based prices, adjusted for location, quality and transportation charges. Market-based pricing is based on the price index applicable for the location of the sale.
We sell our crude oil production either at the lease location or in downstream markets. Crude oil production at the lease location is sold through netback arrangements, under which we sell crude oil net of transportation costs incurred by the purchaser. We record revenue, net, at the lease location when the customer receives delivery of the product.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)



When we move our crude oil production from the lease location to the downstream markets in the US, we incur gathering and transportation costs, which we consider contract fulfillment activities. Such costs are reported as expense within gathering, transportation and processing expense in the consolidated statements of operations. Revenue from the sale of crude oil in downstream markets is recognized upon delivery, as specified in the contract, when control of the product has transferred to the customer.
In second quarter 2018, we entered into a long-term contract to sell firm quantities of crude oil under index-based prices adjusted by applicable fees, including transportation, insurance, and marketing.
Crude Oil Buy/Sell Transactions – US Contracts with CustomersWe enter into buy/sell arrangements that effect a change in location and/or grade with required repurchase of crude oil at a delivery point. The sale and repurchase of crude oil is settled at the same contractually fixed price (before application of transportation and grade deductions) on a net basis. We account for these transactions on a net basis, in accordance with ASC 845, Nonmonetary Transactions (ASC 606). We record the residual transportation fee as transportation expense within gathering, transportation and processing expense in the consolidated statements of operations.
Crude Oil Sale Arrangements – West AfricaOur share of crude oil and condensate from the Aseng, Alen and Alba fields is sold at market-based prices to Glencore Energy UK Ltd (Glencore Energy). Crude oil is priced at a Dated Brent FOB net realized price achieved by Glencore Energy and is adjusted by applicable fees, including transportation, insurance, and marketing. We recognize revenue on the sale of crude oil to Glencore Energy at the time crude oil cargo is loaded onto the tanker and control transfers to Glencore Energy. We record revenue at the realized price received from Glencore Energy, net of applicable fees.
Natural Gas and NGLs Sale Arrangements – US Certain of our commodity contracts in the US are for the sale of natural gas to processors at prevailing market prices. We evaluate the contract terms of these arrangements to determine whether the processor is a service provider or a customer on a contract by contract basis. In arrangements where we determine that we sold our product to the processor, we record revenue when the processor takes physical possession of the natural gas and NGLs and in the amount of proceeds expected to be received, net of any fees or deductions charged by the processor.
In other natural gas processing arrangements, we receive natural gas and NGL products "in-kind" after processing at the tailgate of the plant. In these arrangements, we are responsible for the transportation, fractionation and marketing costs of our production. In such cases, we record the sale of natural gas and NGLs and applicable gathering, processing, transportation and fractionation fees on a gross basis at the time the product is delivered to the end customer.
Natural Gas Purchase and Sale Arrangements – USWeenter into purchase transactions and separate sale transactions with third parties at prevailing market prices to mitigate unutilized pipeline transportation commitments, primarily related to retained Marcellus Shale firm transportation agreements. 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.
Natural Gas Sale Arrangements – West Africa We sell our share of natural gas production from the Alba field under a long-term contract for $0.25 per MMBtu to a methanol plant, a liquefied petroleum gas (LPG) plant, a liquefied natural gas (LNG) plant and a power generation plant. We recognize revenue upon transfer of control of product to these processors.
Natural Gas Sale Arrangements – Israel Our natural gas sales in Israel are primarily based on long-term contracts with fixed volume commitments over the life of the arrangements. Our performance obligations for the sale of natural gas are satisfied over time using production output to measure progress. The nature of these contracts gives rise to several types of variable consideration, including index-based annual price escalations, commodity-based index pricing, tiered pricing and sales price discounts in periods of volume deficiencies. Additionally, the majority of our sales contracts contain take-or-pay provisions where the customers are required to purchase a contractual minimum over varying time periods. Where the variable consideration is related to market-based pricing or index-based escalations of a fixed base price, we have elected the variable consideration allocation exception pursuant toUnder ASC 606. We record revenue related to the volumes delivered at the contract price at the time of delivery. To date, there have been no impacts of variability in consideration due to tiered pricing, take-or-pay provisions and/or volume deficiency discounts. We believe that any variability due to future sales price adjustments associated with potential volume deficiencies will not have a significant impact on our financial position or results of operations.
Transaction Price Allocated to Remaining Performance Obligations – Israel Remaining606, 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,In Israel, certain of our Tamar 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 uponas of March 31, 2019, for those certain agreements with fixed minimum take-or-pay sales volumes.agreements. Our actual future sales volumes under these agreements may exceed future minimum volume commitments.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)



(millions)July - Dec 201820192020TotalRemainder of 2019 2020 Total
Natural Gas Revenues (1)
$107
$137
$169
$413
$108
 $116
 $224
(1)
The remaining performance obligations are estimated using the contractual base or floor price provision in effect. Future revenues under these contracts will vary from the amounts above due to components of variable consideration exceeding the contractual base or floor price provision.
(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
Our Midstream segment revenues are derived from fixed fee contract arrangements for gathering, transportation and storage services. We have determined that our performance obligations for the provision of such services are satisfied over time using volumes delivered as the measure of progress. ASC 606 adoption did not have an impact on the recognition, measurement and presentation of our midstream revenues and expenses.
Crude Oil Purchase and Sale Arrangements – USRedeemable Noncontrolling Interest On March 25, 2019, Noble Midstream Partners secured a $200 million equity commitment (preferred equity) from Global Infrastructure Partners Capital Solutions Fund (GIP), of which $100 million has been funded, with associated offering costs of $3 million. The preferred equity was recorded initially at fair value on the issuance date. As partGIP’s redemption right is outside of Noble Midstream Partners' control, the preferred equity is not considered to be a component of equity on the consolidated balance sheet, and such preferred equity is reported as mezzanine equity on the consolidated balance sheet. In addition, because the preferred equity was issued by a subsidiary of Noble Midstream Partners and is held by a third party, it is considered a redeemable noncontrolling interest. Subsequent to issuance, we accrete changes in the redemption value of the Saddle Butte acquisition inpreferred equity from the date of issuance to the earliest redemption date of the preferred equity. Accretion for first quarter 2018, we acquired a pipeline2019 was also de minimis. See Note 4. Acquisitions 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.Divestitures.
Recently Issued Accounting Standards
LeasesIn February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2016-02 (ASU 2016-02): Leases. The standard requires lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by leases with terms of more than 12 months. ASU 2016-02 also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued Accounting Standards Update No. 2018-01 (ASU 2018-01): Land Easement Practical Expedient for Transition to Topic 842, to provide an optional practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under Topic 840. In July 2018, the FASB issued Accounting Standards Update No. 2018-10 (ASU 2018-10): Codification Improvements to Topic 842, Leases, to clarify application of certain aspects of the standard and to remove inconsistencies within the guidance. Furthermore, in July 2018, the FASB issued Accounting Standards Update No. 2018-11 (ASU 2018-11): Leases (Topic 842): Targeted Improvements, which provides for another transition method, in addition to the existing transition method, by allowing entities to initially apply the new leases standard at the adoption date (such as January 1, 2019) and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption (i.e. comparative periods presented in the financial statements will continue to be in accordance with current GAAP (Topic 840, Leases)). The standard will be effective for annual and interim periods beginning after December 15, 2018, with earlier application permitted.
In the normal course of business, we enter into capital and operating lease agreements to support our exploration and development operations and lease assets such as drilling rigs, platforms, storage facilities, field services and well equipment, pipeline capacity, office space and other assets. We will adopt the new standard on the effective date of January 1, 2019. Although we continue to assess the impact of the standard on our consolidated financial statements, we believe adoption and implementation will result in an increase in assets and liabilities as well as additional disclosures. We do not expect a material impact on our consolidated statement of operations. We have developed and are executing a project plan, which includes contract review and assessment, as well as evaluation of our systems, processes and internal controls. In addition, we plan to implement new lease accounting software.
Accumulated Other Comprehensive Income In February 2018, the FASB issued Accounting Standards Update No. 2018-02 (ASU 2018-02): Income Statement – Reporting Comprehensive Income, to allow reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act. ASU 2018-02 will be effective for annual and interim periods beginning after December 15, 2018, with earlier application permitted. As of June 30, 2018, we have a disproportionate tax effect of approximately $7 million stranded in accumulated other comprehensive income. We are currently evaluating the provisions of this standard.
Intangibles – Goodwill and Other: Simplifying the Test for Goodwill Impairment In January 2017, the FASB issued Accounting Standards Update No. 2017-04 (ASU 2017-04): Intangibles – Goodwill and Other – Simplifying the Test for Goodwill Impairment, to simplify how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. Under the new standard, we will perform our goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount, with an impairment charge being recognized for the
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)



amount by which the carrying amount exceeds the reporting unit’s fair value. ASU 2017-04 will be effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019, with early adoption permitted. We are currently evaluating the provisions of ASU 2017-04.
Financial Instruments: Credit Losses In June 2016, the FASBFinancial Accounting Standards Board (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.permitted, and shall be applied using a modified retrospective approach. 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 wouldwill not be significant. As such, based on our current portfolio, we do not believe adoption of the standard will have a material impact on our financial statements. As our implementation team progresses assessment, we will continue to monitor changes in our credit portfolio in light of the provisions in ASU 2016-13.
Intangibles—Goodwill and Other—Internal-Use SoftwareIn August 2018, the FASB issued Accounting Standards Update No. 2018-15 (ASU 2018-15): Intangibles—Goodwill and Other—Internal-Use Software, to align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The amended standard is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. We are currently evaluating the provisions of ASU 2018-15.
Recently Adopted Accounting Standards
LeasesIn February 2016, the FASB issued Accounting Standards Update No. 2016-02 (ASU 2016-02), which created Topic 842 – Leases (ASC 842). The standard requires lessees to recognize a ROU asset and lease liability on the balance sheet for the rights and obligations created by leases. ASC 842 also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. This standard does not apply to leases to explore for or use minerals, oil, natural gas or similar nonregenerative resources, including the intangible right to explore for those resources and rights to use the land in in which those natural resources are contained.
The new standard provided a number of optional practical expedients. We elected:
the package of transition “practical expedients”, permitting us not to reassess our prior conclusions about lease identification, lease classification and initial direct costs;
the practical expedient pertaining to land easements, allowing us to account for existing land easements under previous accounting policy; and
the practical expedient to not separate lease and non-lease components for the majority of our leases (elected by asset class).
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)

We adopted ASC 842 on January 1, 2019 using the modified retrospective approach and, therefore, prior period financial statements were not adjusted. At adoption, we recorded ROU assets and lease liabilities of $282 million and $287 million, respectively, primarily related to operating leases. The difference between amounts recorded for ROU assets and amounts recorded for lease liabilities totaled $5 million. This amount was recognized as other operating expense. Our accounting for finance leases remains substantially unchanged. Adoption did not materially impact our consolidated statement of operations and comprehensive income and had no impact on our consolidated statement of cash flows. See Note 8. Leases.
Derivatives and Hedging – Targeted Improvements to Accounting for Hedging Activities In August 2017, the FASB issued Accounting Standards Update No. 2017-12 (ASU 2017-12): Derivatives and Hedging – Targeted Improvements to Accounting for Hedging Activities. The update is intended to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition to that main objective, ASU 2017-12 makes certain targeted improvements to simplify the application of the hedge accounting guidance in current US GAAP. We adopted this ASU on January 1, 2019. The amended standard is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We are currently evaluating the provisions of ASU 2017-12.did not have an impact on our financial statements.
Statements of Operations Information  Other statements of operations information is as follows:
Three Months Ended June 30, Six Months Ended June 30,Three Months Ended March 31,
(millions)2018 2017 2018 20172019 2018
Income From Equity Method Investees and Other 
  
    
Other Revenue   
Income from Equity Method Investees$49
 $38
 $96
 $80
$17
 $47
Sales of Purchased Oil and Gas (1)
66
 —
 119
 —
Midstream Services Revenues – Third Party15
 4
 28
 4
24
 13
Total$130
 $42
 $243
 $84
$41
 $60
Production Expense 
  
       
Lease Operating Expense$132
 $124
 $287
 $263
$151
 $155
Production and Ad Valorem Taxes50
 32
 104
 73
49
 54
Gathering, Transportation and Processing Expense100
 121
 195
 240
102
 93
Other Royalty Expense10
 6
 27
 10
3
 17
Total$292
 $283
 $613
 $586
$305
 $319
Other Operating Expense, Net   
Exploration Expense       $24
 $35
Leasehold Impairment and Amortization$—
 $—
 $—
 $18
Seismic, Geological and Geophysical2
 8
 13
 13
Staff Expense13
 16
 27
 29
Other14
 6
 24
 12
Total$29
 $30
 $64
 $72
Other Operating Expense, Net       
Marketing Expense (2)
$7
 $14
 $12
 $33
Purchased Oil and Gas (1)
71
 —
 128
 —
Clayton Williams Energy Acquisition Expenses—
 90
 —
 94
Other, Net(4) 14
 4
 20
25
 15
Total$74
 $118
 $144
 $147
$49
 $50
Other Non-Operating Expense (Income), Net       
Loss on Investment in Shares of Tamar Petroleum Ltd., Net (3)
$11
 $—
 $26
 $—
Other—
 (5) (2) (6)
Total$11
 $(5) $24
 $(6)


Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)



(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 million and $11 million for second quarter and the first six months of 2018, respectively. See Note 11. Segment Information and Note 12. Commitments and Contingencies.
(2)
Expense relates to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments.
(3)
Amounts for second quarter and the first six months of 2018 include losses of $11 million and $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.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)



Balance Sheet Information  Other balance sheet information is as follows:
(millions)June 30,
2018		 December 31,
2017		March 31, 2019 December 31, 2018
Accounts Receivable, Net      
Commodity Sales$460
 $455
$384
 $383
Joint Interest Billings210
 207
124
 137
Other89
 103
80
 111
Allowance for Doubtful Accounts(16) (17)(15) (15)
Total$743
 $748
$573
 $616
Other Current Assets 
  
 
  
Commodity Derivative Assets$9
 $180
Inventories, Materials and Supplies$46
 $66
70
 55
Inventories, Crude Oil27
 16
Commodity Derivative Assets29
 2
Assets Held for Sale (1)
40
 629
—
 133
Restricted Cash (2)
—
 38
Prepaid Expenses and Other Current Assets45
 29
63
 50
Total$187
 $780
$142
 $418
Other Noncurrent Assets 
  
 
  
Equity Method Investments (3)
$357
 $305
Customer-Related Intangible Assets (4)
326
 —
Investment in Shares of Tamar Petroleum Ltd. (5)
150
 —
Mutual Fund Investments57
 57
Net Deferred Income Tax Asset25
 25
Equity Method Investments (2)
$559
 $286
Operating Lease Right-of-Use Assets (3)
273
 —
Customer-Related Intangible Assets, Net (4)
302
 310
Goodwill (4)
110
 110
Other Assets, Noncurrent69
 74
132
 135
Total$984
 $461
$1,376
 $841
Other Current Liabilities 
  
 
  
Production and Ad Valorem Taxes$111
 $84
$106
 $103
Commodity Derivative Liabilities250
 58
Income Taxes Payable5
 18
Asset Retirement Obligations92
 51
118
 118
Interest Payable64
 67
85
 66
Current Portion of Capital Lease Obligations47
 61
Liabilities Associated with Assets Held for Sale (1)
—
 55
Compensation and Benefits Payable66
 98
Other Liabilities, Current110
 86
350
 232
Total$745
 $578
$659
 $519
Other Noncurrent Liabilities 
  
 
  
Deferred Compensation Liabilities$180
 $197
$149
 $147
Asset Retirement Obligations543
 824
749
 762
Marcellus Shale Firm Transportation Commitment (6)
71
 76
Operating Lease Liabilities (3)
194
 —
Firm Transportation Exit Cost Accrual (5)
156
 67
Production and Ad Valorem Taxes39
 69
88
 83
Commodity Derivative Liabilities85
 15
Other Liabilities, Noncurrent77
 64
102
 106
Total$995
 $1,245
$1,438
 $1,165
(1) 
Assets held for sale at June 30, 2018 include assets in the Greeley Crescent area of the DJ Basin.
Assets held for sale at December 31, 20172018 include assets related to the first quarter 2019 divestiture of non-core acreage in the Greeley Crescent area of the DJ Basin, a 7.5% 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
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)



assets held for sale primarily represent asset retirement obligations and other liabilities to be assumed by the purchaser. See Note 3.Reeves County, Texas. See Note 4. Acquisitions and Divestitures.
(2) 
Balance at December 31, 2017 representsThe 2019 amount heldincludes Noble Midstream Partners' $227 million investment in escrow pending closing of the Saddle Butte acquisition.EPIC Y-Grade, LP and EPIC Crude Holdings, LP and $38 million investment in Delaware Crossing LLC. See Note 3.4. Acquisitions and Divestitures.
(3) 
Includes $49 million for our investmentAmounts relate to assets and liabilities recorded as a result of ASC 842 adoption in shares of CNX Midstream Partners LP. At December 31, 2017, this investment was included in assets held for sale.first quarter 2019. See Note 3. Acquisitions and Divestitures and 8. LeasesNote 6. Fair Value Measurements and Disclosures.
(4) 
Amount relatesAmounts relate to intangible assets acquired in the first quarter 2018 Saddle Butte acquisitionAcquisition. Intangible asset amounts at March 31, 2019 and isDecember 31, 2018 are net of $14accumulated amortization of $38 million of accumulated amortization.and $30 million, respectively. See Note 3.4. Acquisitions and Divestitures.Divestitures.
(5) 
Amount relates to our investment in shares of Tamar Petroleum Ltd. See Note 3. Acquisitions and Divestitures9. Exit Cost – Transportation Commitments and .Note 6. Fair Value Measurements and Disclosures.
(6)
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
Amounts relate to the long-term portion of retained firm transportation agreements. At June 30, 2018 and December 31, 2017, we recorded $12 million and $14 million, respectively, associated with the current portion of the Marcellus Shale firm transportation commitment. See Note 12. Commitments and Contingencies.

Reconciliation of Total Cash We define total cash as cash, cash equivalents and restricted cash. The following table provides a reconciliation of total cash:
Six Months Ended June 30,Three Months Ended March 31,
(millions)2018 20172019 2018
Cash and Cash Equivalents at Beginning of Period$675
 $1,180
$716
 $675
Restricted Cash at Beginning of Period38
 30
3
 38
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period$713
 $1,210
$719
 $713
Cash and Cash Equivalents at End of Period$621
 $540
$528
 $992
Restricted Cash at End of Period—
 —
2
 30
Cash, Cash Equivalents, and Restricted Cash at End of Period$621
 $540
$530
 $1,022


Note 3. Acquisitions and DivestituresSegment Information
2018 Asset Transactions
Divestiture ofWe have the following reportable segments: United States (US onshore and Gulf of Mexico Assets  On February 15, 2018, we announced that we had signed a definitive agreement(until April 2018)); Eastern Mediterranean (Israel and Cyprus); West Africa (Equatorial Guinea, Cameroon and Gabon); Other International (Canada and New Ventures, including Colombia); and Midstream. The Midstream segment includes the consolidated accounts of Noble Midstream Partners and other US onshore midstream assets.
The geographical reportable segments are in the business of crude oil and natural gas acquisition and exploration, development, and production (Oil and Gas Exploration and Production). The Midstream reportable segment develops, owns, and operates domestic midstream infrastructure assets, as well as invests in other midstream projects. The chief operating decision maker analyzes income before income taxes to sellassess the performance of Noble Energy's reportable segments as management believes this measure provides useful information in assessing our Gulf of Mexico assets, including alloperating and financial performance across periods.
Corporate level expenses include debt, headquarters depreciation, corporate general and administrative expenses, exit costs and certain costs associated with mitigating the effects of our interests in producing properties and undeveloped acreage, for cash consideration of $480 million, along with the assumption, by the purchaser, of all abandonment obligations associated with the properties. As a result, we recorded impairment expense of $168 million during first quarter 2018.retained Marcellus Shale firm transportation agreements.
   Oil and Gas Exploration and Production Midstream  
(millions)Consolidated United States Eastern Mediter-ranean West Africa Other Int'l United States 
Intersegment Eliminations and Other (1)
 Corporate
Three Months Ended March 31, 2019  
  
  
        
Crude Oil Sales$612
 $545
 $1
 $66
 $—
 $—
 $—
 $—
NGL Sales96
 96
 —
 —
 —
 —
 —
 —
Natural Gas Sales229
 108
 117
 4
 —
 —
 —
 —
Total Crude Oil, NGL and Natural Gas Sales937
 749
 118
 70
 —
 —
 —
 —
Sales of Purchased Oil and Gas74
 14
 —
 —
 —
 33
 —
 27
Income from Equity Method Investees17
 —
 —
 15
 —
 2
 —
 —
Midstream Services Revenues – Third Party
24
 —
 —
 —
 —
 24
 —
 —
Intersegment Revenues—
 —
 —
 —
 —
 106
 (106) —
Total Revenues1,052
 763
 118
 85
 —
 165
 (106) 27
Lease Operating Expense151
 125
 10
 24
 —
 1
 (9) —
Production and Ad Valorem Taxes49
 47
 —
 —
 —
 2
 —
 —
Gathering, Transportation and Processing Expense102
 142
 —
 —
 —
 29
 (69) —
Other Royalty Expense3
 3
 —
 —
 —
 —
 —
 —
Total Production Expense305
 317
 10
 24
 —
 32
 (78) —
Depreciation, Depletion and Amortization508
 439
 16
 20
 —
 25
 (7) 15
In second quarter 2018, we closed the transaction with an effective date of January 1, 2018. After consideration of customary closing adjustments, we received net proceeds of $383 million and recorded an additional loss of $19 million.
In addition, a cumulative contingent payment of up to $100 million is payable to us in the period after the closing of the transaction, beginning third quarter 2018, through the end of 2022, determined quarterly, at a rate of $2 per barrel produced by these assets when the average purchase price for Light Louisiana Sweet (LLS) crude oil exceeds $63 per barrel, and if produced crude oil volumes exceed certain minimum thresholds. As of June 30, 2018, no amounts have been accrued related to the contingent payment. 
Proved reserves associated with these properties totaled approximately 23 MMBoe as of December 31, 2017.
Divestiture of 7.5% Interest in Tamar Field
On March 14, 2018, we closed the sale of a 7.5% working interest in the Tamar field to Tamar Petroleum Ltd. (Tamar Petroleum), a publicly traded entity on the Tel Aviv Stock Exchange (TASE: TMRP). Total consideration included cash and 38.5 million shares of Tamar Petroleum that had a publicly traded value of $224 million. The transaction had an effective date of January 1, 2018 and after consideration of closing adjustments and before consideration of taxes, we received $484 million of cash.
Our shares of Tamar Petroleum are currently subject to certain temporary lock-up provisions and have no voting rights. Upon subsequent sale of the shares to a third party, the voting rights will be restored and granted to the third party. Due to the lock-up provisions associated with the Tamar Petroleum shares, we initially attributed $190 million of fair value to the shares, or 15% lower than the publicly traded value on the TASE. These shares are currently being accounted for at fair value. See Note 6. Fair Value Measurements and Disclosures.
Total consideration received was applied to the field's basis and resulted in the recognition of a pre-tax gain of $376 million. In connection with the transaction, we incurred tax expense of $86 million.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)



The sale is in accordance with the terms of the Israel Natural Gas Framework (Framework) that requires us to reduce our ownership interest in the Tamar field from 32.5% to 25% by year-end 2021. We expect to sell the Tamar Petroleum shares before year-end 2021. Proved reserves related to the 7.5% interest totaled approximately 84 MMBoe as of December 31, 2017.
   Oil and Gas Exploration and Production Midstream  
(millions)Consolidated United States Eastern Mediter-ranean West Africa Other Int'l United States 
Intersegment Eliminations and Other (1)
 Corporate
Cost of Purchased Oil and Gas87
 14
 —
 —
 —
 31
 —
 42
Firm Transportation Exit Cost92
 —
 —
 —
 —
 —
 —
 92
Loss on Commodity Derivative Instruments212
 188
 —
 24
 —
 —
 —
 —
(Loss) Income Before Income Taxes(373) (247) 84
 11
 (16) 73
 (14) (264)
Additions to Long-Lived Assets, Excluding Acquisitions712
 511
 132
 5
 10
 66
 (23) 11
Investments in Equity Method Investees271
 —
 —
 —
 —
 271
 —
 —
Three Months Ended March 31, 2018  
  
  
        
Crude Oil Sales$773
 $682
 $2
 $89
 $—
 $—
 $—
 $—
NGL Sales146
 146
 —
 —
 —
 —
 —
 —
Natural Gas Sales254
 120
 129
 5
 —
 —
 —
 —
Total Crude Oil, NGL and Natural Gas Sales1,173
 948
 131
 94
 —
 —
 —
 —
Sales of Purchased Oil and Gas53
 —
 —
 —
 —
 22
 —
 31
Income from Equity Method Investees47
 —
 —
 35
 —
 12
 —
 —
Midstream Services Revenues – Third Party
13
 —
 —
 —
 —
 13
 —
 —
Intersegment Revenues—
 —
 —
 —
 —
 81
 (81) —
Total Revenues1,286
 948
 131
 129
 —
 128
 (81) 31
Lease Operating Expense155
 126
 7
 22
 —
 —
 —
 —
Production and Ad Valorem Taxes54
 53
 —
 —
 —
 1
 —
 —
Gathering, Transportation and Processing Expense93
 128
 —
 —
 —
 20
 (53) —
Other Royalty Expense17
 17
 —
 —
 —
 —
 —
 —
Total Production Expense319
 324
 7
 22
 —
 21
 (53) —
Depreciation, Depletion and Amortization468
 404
 13
 26
 —
 17
 (3) 11
Gain on Divestitures, Net(588) (6) (386) —
 —
 (196) —
 —
Asset Impairments168
 168
 —
 —
 —
 —
 —
 —
Cost of Purchased Oil and Gas57
 —
 —
 —
 —
 21
 —
 36
Loss on Commodity Derivative Instruments79
 64
 —
 15
 —
 —
 —
 —
Income (Loss) Before Income Taxes543
 (43) 473
 64
 (9) 247
 (15) (174)
Additions to Long-Lived Assets, Excluding Acquisitions905
 534
 147
 2
 2
 242
 (32) 10
March 31, 2019 
  
  
  
        
Property, Plant and Equipment, Net$18,701
 $13,145
 $2,728
 $736
 $119
 $1,801
 $(162) $334
December 31, 2018   
  
  
        
Property, Plant and Equipment, Net$18,419
 $13,044
 $2,630
 $805
 $37
 $1,742
 $(145) $306
Divestiture of Southwest Royalties
In January 2018, we closed the sale of our interest in Southwest Royalties, Inc. (Southwest Royalties), a subsidiary of Clayton Williams Energy, Inc. (Clayton Williams Energy), which we acquired in the acquisition of Clayton Williams Energy (Clayton Williams Energy Acquisition) in 2017. We received proceeds of $60 million, resulting in no gain or loss recognition on the sale of these assets.
Divestiture of Marcellus Shale CONE Gathering In January 2018, we closed the sale of our 50% interest in CONE Gathering LLC (CONE Gathering) to CNX Resources Corporation. CONE Gathering owns the general partner of CNX Midstream Partners LP (CNX Midstream Partners, NYSE: CNXM). We received proceeds of $308 million in cash and recognized a pre-tax gain of $196 million.
After the sale, we continued to hold 21.7 million common units, representing a 34.1% limited partner interest, in CNX Midstream Partners. During second quarter 2018, we sold 7.5 million of the common units, receiving net proceeds of approximately $135 million, net of underwriting fees, and recognized a gain of $109 million. As of June 30, 2018, we continue to hold 14.2 million common units, representing a 22.3% limited partner interest, in CNX Midstream Partners and account for the investment under equity method accounting.
Noble Midstream Partners Saddle Butte Acquisition On January 31, 2018, Black Diamond Gathering LLC (Black Diamond), an entity formed by Black Diamond Gathering Holdings LLC, a wholly-owned subsidiary of Noble Midstream Partners, and Greenfield Midstream, LLC (Greenfield), completed the acquisition of Saddle Butte Rockies Midstream, LLC and affiliates (collectively, Saddle Butte) from Saddle Butte Pipeline II, LLC. Saddle Butte owned a large-scale integrated gathering system, located in the DJ Basin, which we subsequently renamed the Black Diamond gathering system.
Consideration totaled $681 million, which included $663 million of cash and assumption of $18 million of liabilities. Greenfield funded approximately $343 million of the purchase price, which is reflected as a contribution from noncontrolling interest within our consolidated statement of equity, and Noble Midstream Partners funded the remainder. We consolidate Black Diamond and reflect the third-party ownership within noncontrolling interest within our consolidated statement of equity.
We accounted for the transaction as a business combination using the acquisition method. The total purchase price was allocated to assets acquired and liabilities assumed based on the fair value at the acquisition date. We have recognized goodwill for the amount of the purchase price exceeding the fair value of the assets acquired. Allocated fair value included: $206 million to property, plant and equipment; $340 million to customer-related intangible assets (acquired customer contracts); and $111 million to implied goodwill. The purchase price allocation is preliminary as certain data necessary to complete the purchase price allocation is not yet available, such as analysis of the final appraisals of assets acquired and liabilities assumed. We expect to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the value of the assets and liabilities, including any goodwill, may be revised as appropriate.
Other Divestitures During the first six months of 2018, we also closed the sale of certain other smaller US onshore properties and received total cash consideration of $12 million, recording a gain of $4 million.
2017 Asset Transactions
Delaware Basin Acquisition During the first six months of 2017, we closed a bolt-on acquisition in the Delaware Basin for $301 million, approximately $246 million of which was allocated to undeveloped leasehold costs. The acquisition included interests in seven producing wells, four of which are operated by us.
Clayton Williams Energy Acquisition On April 24, 2017, we completed the Clayton Williams Energy Acquisition. The acquisition was effected through the issuance of 56 million shares of Noble Energy common stock, with a fair value of $1.9 billion, and cash consideration of $637 million, for total consideration of $2.5 billion, in exchange for all of the outstanding Clayton Williams Energy shares, including stock options, restricted stock awards and warrants.
The transaction was accounted for as a business combination using the acquisition method. 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
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)



t assets acquired recorded as goodwill.
(millions) 
Fair Value of Common Stock Issued$1,851
Plus: Cash Consideration Paid to Clayton Williams Energy Stockholders637
Total Purchase Price$2,488
Plus Liabilities Assumed by Noble Energy: 
Accounts Payable99
Other Current Liabilities38
Long-Term Deferred Tax Liability515
Long-Term Debt595
Asset Retirement Obligations63
Total 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$21
Other Current Assets70
Oil and Gas Properties: 
Proved Reserves722
Undeveloped Leasehold Costs1,571
Gathering and Processing Assets48
Asset Retirement Costs63
Other Noncurrent Assets12
Implied Goodwill1,291
Total Asset Value$3,798

In connection with the acquisition, we assumed, and then subsequently retired in second quarter 2017, all of Clayton Williams Energy's long-term debt at a cost of $595 million. The fair value measurements of long-term debt were estimated based on the early redemption prices and represent Level 1 inputs.
The fair value measurements of crude oil and natural gas properties and asset retirement obligations were based on inputs that are not observable in the market and, therefore, represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert expected future cash flows to a single discounted amount. Significant inputs to the valuation of crude oil and natural gas properties included estimates of: (i) proved, possible and probable reserves; (ii) production rates and related development timing; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average cost of capital rate. These inputs required significant judgments and estimates by management at the time of the valuation and were the most sensitive.
Based upon the final purchase price allocation, we recognized $1.3 billion of goodwill, all of which is assigned to the Texas reporting unit.
The following pro forma condensed combined financial information was derived from the historical financial statements of Noble Energy and Clayton Williams Energy and gives effect to the acquisition as if it had occurred on January 1, 2017. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including: (i) Noble Energy's common stock and equity awards issued to convert Clayton Williams Energy's outstanding shares of common stock and equity awards and conversion of warrants as of the closing date of the acquisition, (ii) depletion of Clayton Williams Energy's fair-valued proved crude oil and natural gas properties, and (iii) the estimated tax impacts of the pro forma adjustments.
The pro forma results of operations do not include any cost savings or other synergies that we expect to realize from the Clayton Williams Energy Acquisition or any estimated costs that have been or will be incurred by us to integrate the Clayton Williams Energy assets. 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
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)



n taken place on January 1, 2017; furthermore, the financial information is not intended to be a projection of future results.
 Three Months Ended June 30, Six Months Ended June 30,
(millions, except per share amounts)
2018 (1)
 2017 
2018 (1)
 2017
Revenues$1,230
 $1,070
 $2,516
 $2,141
Net (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 Share       
Basic$(0.05) $(2.77) $1.09
 $(2.71)
Diluted$(0.05) $(2.77) $1.09
 $(2.71)
(1) 
No pro forma adjustments were made forThe intersegment eliminations related to income before income taxes are the periodresult of midstream expenditures.  These costs are presented as Clayton Williams Energy operationsproperty, plant and equipment within the E&P business on an unconsolidated basis, in accordance with the successful efforts method of accounting, and are included in our historical results.eliminated upon consolidation.

Marcellus Shale Upstream Divestiture On June 28, 2017, we closed the sale of all of our Marcellus Shale upstream assets, which were primarily natural gas properties. The purchase price totaled $1.2 billion, and we received $1.0 billion of net cash proceeds, after consideration of customary adjustments, at closing. The purchase price includes additional contingent consideration of up to $100 million structured as three separate payments of $33.3 million each. The contingent payments are in effect should the average annual price of the Appalachia Dominion, South Point index exceed $3.30 per MMBtu in the individual annual periods from 2018 through 2020. No amounts have been accrued related to the contingent consideration. Proceeds from the transaction were used to repay borrowings resulting from the Clayton Williams Energy Acquisition. See Note 5. Debt.
In second quarter 2017, we recognized a total loss of $2.3 billion, or $1.5 billion after-tax, on this transaction. The aggregate net book value of the properties prior to the sale was approximately $3.4 billion, which included approximately $883 million of undeveloped leasehold cost.
As part of the total loss, we recorded a charge of $41 million, discounted, relating to a retained transportation contract. See Note 12. Commitments and Contingencies.
During second quarter 2017, production from the Marcellus Shale upstream assets totaled 393 MMcfe/d. With the closing of the sale, we recorded a decrease in net proved reserves of approximately 241 MMBoe, of which approximately 190 MMBoe were proved developed reserves and 51 MMBoe were proved undeveloped reserves.
Noble Midstream Partners Asset Contribution On June 26, 2017, Noble Midstream Partners acquired an additional 15% limited partner interest in Blanco River DevCo LP (Blanco River DevCo), increasing its ownership to 40% of the Blanco River DevCo LP, and acquired the remaining 20% limited partner interest in Colorado River DevCo LP (Colorado River DevCo) from Noble Energy for $270 million.
Blanco River DevCo holds Noble Midstream Partners’ Delaware Basin in-field gathering dedications for crude oil and produced water gathering services on approximately 111,000 net acres, with substantially all of the acreage also dedicated for natural gas gathering. Colorado River DevCo consists of gathering systems across Noble Energy’s Wells Ranch and East Pony development areas in the DJ Basin.
The $270 million consideration consisted of $245 million in cash and 562,430 common units representing limited partner interests in Noble Midstream Partners. Noble Midstream Partners funded the cash consideration with approximately $138 million of net proceeds from a concurrent private placement of common units and $90 million of borrowings under the Noble Midstream Services Revolving Credit Facility (defined below) and the remainder from cash on hand.
Noble Midstream Partners Advantage Acquisition On 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 million through a newly formed 50/50 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.

Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)



Note 4. Derivative InstrumentsAcquisitions and Hedging ActivitiesDivestitures
ObjectiveWe maintain an ongoing portfolio management program and Strategies for Using Derivative Instrumentshave engaged in various transactions over recent years.
2019 Asset Transactions
Divestiture of Reeves County Assets In February 2019, we closed the sale of certain proved and unproved non-core acreage in the Delaware Basin totaling approximately 13,000 net acres in southwestern Reeves County, Texas. We are exposedreceived cash consideration of $131 million, recognizing no gain or loss on the sale.
EPIC Pipelines In first quarter 2019, Noble Midstream Partners exercised and closed options with EPIC Midstream Holdings, LP (EPIC) to fluctuationsacquire a 15% equity interest in EPIC Y-Grade, LP (EPIC Y-Grade), which is constructing the EPIC Y-grade pipeline from the Delaware Basin to Corpus Christi, Texas, and a 30% equity interest in EPIC Crude Holdings, LP (EPIC Crude Holdings), which is constructing the EPIC crude oil natural gaspipeline also from the Delaware Basin to Corpus Christi, Texas. Cash consideration totaled $227 million. These investments are accounted for using the equity method.
Also, on March 25, 2019, Noble Midstream Partners secured a $200 million preferred equity commitment from GIP to fund capital contributions to Dos Rios Crude Intermediate LLC, a subsidiary formed by Noble Midstream Partners to hold the 30% equity interest in EPIC Crude Holdings. GIP funded $100 million and NGL pricing.the remaining $100 million is available for a one-year period, subject to certain conditions precedent. The preferred equity is perpetual and has a 6.5% annual dividend rate, payable quarterly in cash, with the ability to defer payment during the first two years following the closing. In order to mitigateaddition, Noble Midstream Partners can redeem the effectpreferred equity in whole or in part at any time for cash at a predetermined redemption price. GIP can request redemption of commodity price volatility and enhance the predictabilitypreferred equity following the later of cash flows relating to the marketingsixth anniversary of our globalthe preferred equity closing or the fifth anniversary of the EPIC crude oil and domestic natural gas, we enter into crude oil and natural gas price hedging arrangements.
While these instruments mitigatepipeline completion date at a pre-determined base return. Proceeds from the cash flow riskpreferred equity issuance were used to repay a portion of future decreasesoutstanding borrowings under the Noble Midstream Services Revolving Credit Facility, which were drawn to fund its exercise of the option to invest in commodity prices, they may also curtail benefits from future increases in commodity prices.EPIC Crude Holdings. See Note Note. 2 Basis of Presentation6. and Note 13. Fair Value Measurements and Disclosures.
Delaware Crossing Joint Venture In February 2019, Noble Midstream Partners executed definitive agreements with Salt Creek Midstream LLC (Salt Creek) to form a 50/50 joint venture, Delaware Crossing LLC (Delaware Crossing), to construct a 160 MBbl/d day crude oil pipeline system in the Delaware Basin. As Salt Creek had commenced construction of the pipeline prior to formation of the joint venture, Noble Midstream Partners made capital contributions of $38 million at closing. This investment is accounted for using the equity method.
Other Divestitures, Net In first quarter 2019, we also closed the sales of certain other non-core US onshore properties which resulted in net payments of approximately $8 million.
2018 Asset Transactions
Divestiture of Gulf of Mexico Assets  In February 2018, we announced plans to sell our Gulf of Mexico assets for cash consideration of $480 million, along with the assumption, by the purchaser, of all abandonment obligations associated with the properties. As of March 31, 2018, we reduced the net book value of the Gulf of Mexico assets to $480 million. In addition, we retained certain transaction related obligations approximating $92 million which were subsequently settled upon closing. During first quarter 2018, we recorded impairment expense of $168 million associated with these assets held for sale. The transaction closed in second quarter 2018.
Divestiture of 7.5% Interest in Tamar Field In March 2018, we closed the sale of a discussion7.5% working interest in the Tamar field to Tamar Petroleum Ltd., a publicly traded entity on the Tel Aviv Stock Exchange (Tamar Petroleum, TASE: TMRP). Total consideration included cash of methods$487 million and assumptions used38.5 million shares of Tamar Petroleum that had a publicly traded value of $224 million. Total consideration received from the sale was applied to estimate the fair valuesfield's basis and resulted in the recognition of a pre-tax gain of $386 million and tax expense of $90 million.
In October 2018, we sold our shares in Tamar Petroleum. The sale was in accordance with the terms of the Israel Natural Gas Framework and completed our obligation to reduce our ownership interest in the Tamar field from 32.5% to 25% by year-end 2021.
Divestiture of Southwest Royalties In January 2018, we closed the sale of our derivative instruments.investment in Southwest Royalties, Inc. We received proceeds of $60 million, recognizing no gain or loss on the sale.
Unsettled Commodity Derivative InstrumentsDivestiture of Marcellus Shale CONE Gathering    AsIn January 2018, we closed the sale of June 30, 2018,our 50% interest in CONE Gathering LLC (CONE Gathering) to CNX Resources Corporation. CONE Gathering owns the following crude oil derivative contracts were outstanding:
    Swaps Collars
Settlement
Period
Type of ContractIndex
Bbls Per
Day
Weighted Average Differential
Weighted
Average
Fixed
Price
 
Weighted
Average
 Short Put
 Price
Weighted
Average
Floor
Price
Weighted
Average
 Ceiling
Price
2018SwapsNYMEX WTI66,000$—
$60.30
 $—
$—
$—
2018CollarsNYMEX WTI18,000—
—
 —
50.42
58.82
2018Three-Way CollarsNYMEX WTI10,000—
—
 45.50
52.50
69.09
2018Three-Way CollarsDated Brent3,000—
—
 40.00
50.00
70.41
2018SwapsICE Brent2,000—
59.00
 —
—
—
2018CollarsICE Brent2,000—
—
 —
50.00
55.25
2018Three-Way CollarsICE Brent5,000—
—
 43.00
50.00
59.50
2018Basis Swaps
(1) 
20,000(2.30)—
 —
—
—
2019SwapsNYMEX WTI44,000—
58.37
 —
—
—
2019Three-Way CollarsNYMEX WTI6,000—
—
 50.00
60.00
72.75
2019SwapsICE Brent5,000—
57.00
 —
—
—
2019Three-Way CollarsICE Brent3,000—
—
 43.00
50.00
64.07
2019Basis Swaps
(1) 
27,000(3.23)—
 —
—
—
2020
Swaption (2)
NYMEX WTI5,000—
61.79
 —
—
—
2020Basis Swaps
(1) 
15,000(5.01)—
 —
—
—

(1) We have entered into crude oil basis swap contracts in order to establish a fixed amount for the differential between pricing in Midland, Texas, and Cushing, Oklahoma. The weighted average differential represents the amountgeneral partner of reduction to Cushing, Oklahoma prices for the notional volumes covered by the basis swap contracts.
(2) We have entered into certain derivative contracts (swaptions), which give counterparties the right, but not the obligation, to enter into swap agreements with us on the option expiration dates.



Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)



As of June 30, 2018, the following natural gas derivative contracts were outstanding:
    Swaps Collars
Settlement
Period
Type of ContractIndex
MMBtu
Per Day
Weighted
Average
Fixed
Price
 
Weighted
Average
Short Put
 Price
Weighted
Average
Floor
Price
Weighted
Average
Ceiling
Price
2018Three-Way CollarsNYMEX HH120,000
$—
 $2.50
$2.88
$3.65

Fair Value Amounts and Loss (Gain) on Commodity Derivative InstrumentsThe fair values of commodity derivative instruments in our consolidated balance sheets were as follows:
 Fair Value of Derivative Instruments
 Asset Derivative Instruments Liability Derivative Instruments
 June 30,
2018		 December 31,
2017		 June 30,
2018		 December 31,
2017
(millions)Balance Sheet Location 
Fair
Value
 Balance Sheet Location 
Fair
 Value
 Balance Sheet Location 
Fair
Value
 Balance Sheet Location 
Fair
Value
Commodity Derivative Instruments
Current Assets $29
 Current Assets $2
 Current Liabilities $250
 Current Liabilities $58
 Noncurrent Assets —
 Noncurrent Assets —
 Noncurrent Liabilities 85
 Noncurrent Liabilities 15
Total  $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)2018 2017 2018 2017
Cash Paid (Received) in Settlement of Commodity Derivative Instruments       
Crude Oil$66
 $(11) $96
 $(16)
Natural Gas(1) —
 (3) 2
Total Cash Paid (Received) in Settlement of Commodity Derivative Instruments65
 (11) 93
 (14)
Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments       
Crude 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 Instruments       
Crude Oil247
 (39) 327
 (107)
Natural Gas2
 (18) 1
 (60)
Total Loss (Gain) on Commodity Derivative Instruments$249
 $(57) $328
 $(167)

CNX Midstream
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)




Partners LP (CNX Midstream Partners, NYSE: CNXM). We received proceeds of $308 million in cash and recognized a pre-tax gain of $196 million. After the sale, we held 21.7 million common units, representing a 33.5% limited partner interest, in CNX Midstream Partners, which were subsequently divested in 2018.
Note 5. DebtNoble Midstream Partners Saddle Butte Acquisition In January 2018, Noble Midstream Partners acquired a 54.4% interest in Black Diamond Gathering LLC (Black Diamond), an entity formed by Black Diamond Gathering Holdings LLC, a wholly-owned subsidiary of Noble Midstream Partners, and Greenfield Midstream, LLC (Greenfield), which completed the acquisition of Saddle Butte Rockies Midstream, LLC and affiliates (collectively, Saddle Butte) from Saddle Butte Pipeline II, LLC. Saddle Butte owned a large-scale integrated gathering system, located in the DJ Basin, which we subsequently renamed the Black Diamond gathering system. Consideration totaled $681 million and Black Diamond is consolidated as a VIE.
Debt consistsWe accounted for the transaction as a business combination using the acquisition method. The total purchase price was allocated to assets acquired and liabilities assumed based on acquisition date fair values, and we recognized goodwill for the amount of the following:
 June 30,
2018		 December 31,
2017
(millions, except percentages)Debt Interest Rate
 Debt Interest Rate
Revolving Credit Facility, due March 9, 2023$—
 —% $230
 2.27%
Noble Midstream Services Revolving Credit Facility, due March 9, 2023530
 3.25% 85
 2.75%
Leviathan Term Loan Facility, due February 23, 2025—
 —% —
 —%
Senior Notes, due May 1, 2021 (1) 
—
 —% 379
 5.63%
Senior Notes, due December 15, 20211,000
 4.15% 1,000
 4.15%
Senior Notes, due October 15, 2023100
 7.25% 100
 7.25%
Senior Notes, due November 15, 2024650
 3.90% 650
 3.90%
Senior Notes, due April 1, 2027250
 8.00% 250
 8.00%
Senior Notes, due January 15, 2028600
 3.85% 600
 3.85%
Senior Notes, due March 1, 2041850
 6.00% 850
 6.00%
Senior Notes, due November 15, 20431,000
 5.25% 1,000
 5.25%
Senior Notes, due November 15, 2044850
 5.05% 850
 5.05%
Senior Notes, due August 15, 2047500
 4.95% 500
 4.95%
Other Senior Notes and Debentures (2) 
92
 7.13% 92
 7.13%
Capital Lease Obligations241
 —% 273
 —%
Total6,663
   6,859
  
Unamortized Discount(23)   (24)  
Unamortized Premium (1)
—
   12
  
Unamortized Debt Issuance Costs(38)   (40)  
Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs6,602
   6,807
  
Less Amounts Due Within One Year       
Capital Lease Obligations(47)   (61)  
Long-Term Debt Due After One Year$6,555
   $6,746
  

(1) In second quarter 2018, we redeemed allpurchase price exceeding the fair values of the Senior Notes due May 1, 2021, writing off the associated premium. See Redemption of Senior Notes, below.identifiable net assets acquired. The final purchase price allocation included: $206 million to property, plant and equipment; $340 million to customer-related intangible assets (acquired customer contracts); and $110 million to implied goodwill.
(2) Other Divestitures, Net Includes $8 million of Senior Notes due June 1, 2024 and $84 million of Senior Debentures due August 1, 2097. The weighted average interest rate for these instruments is 7.13%.
Revolving Credit Facility Our Credit Agreement, as amended, provides for a $4 billion unsecured revolving credit facility (Revolving Credit Facility), which is available for general corporate purposes. The Revolving Credit Facility (i) provides for facility fee rates that range from 10 basis points to 25 basis points per year depending upon our credit rating, (ii) provides for interest rates that are based upon the Eurodollar rate plus a margin that ranges from 90 basis points to 150 basis points depending upon our credit rating and (iii) includes sub-facilities for short-term loans and letters of credit up to an aggregate amount of $500 million under each sub-facility.
In first quarter 2018, we extendedalso closed the maturity datesales of the Revolving Credit Facility from August 2020 to March 2023. Asother non-core US onshore properties and received net cash consideration of June 30, 2018, no borrowings were outstanding under the Revolving Credit Facility.approximately $10 million, recording a gain of $6 million.
Noble Midstream Services Revolving Credit FacilityNote 5. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs
Capitalized Exploratory Well Costs Noble Midstream Services, LLC,We capitalize exploratory well costs until a subsidiarydetermination is made that the well has found proved reserves or is deemed noncommercial. On a quarterly basis, we review the status of Noble Midstream Partners, maintainssuspended exploratory well costs and assess the development of these projects. If a revolving credit facility (Noble Midstream Services Revolving Credit Facility), whichwell is availabledeemed to fund workingbe noncommercial, the well costs are charged to exploration expense as dry hole cost.
There were no significant changes to our capitalized exploratory well costs during the period. The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced:
(millions, except number of projects)March 31, 2019 December 31, 2018
Exploratory Well Costs Capitalized for a Period of One Year or Less$9
 $6
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling350
 348
Capitalized Exploratory Well Costs, End of Period$359
 $354
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling7
 7


Undeveloped Leasehold Costs Undeveloped leasehold costs are derived from allocated fair values as a result of business combinations or other purchases of unproved properties and are subject to impairment testing. We reclassify undeveloped leasehold costs to proved property costs when, as a result of exploration and development activities, probable and possible resources are reclassified to proved reserves, including proved undeveloped reserves. On the other hand, if, based upon a change in exploration plans, timing and extent of development activities, availability of capital and suitable rig and drilling equipment, resource potential, comparative economics, changing regulations and/or other factors, an impairment is indicated, we record impairment expense related to finance acquisitions and other capital expenditures of Noble Midstream Partners.the respective leases or licenses.
In first quarter 2018, the facility capacity was increased from $350
Changes in undeveloped leasehold costs were as follows:
(millions)Three Months Ended March 31, 2019
Undeveloped Leasehold Costs, Beginning of Period$2,306
Additions to Undeveloped Leasehold Costs47
Transfers to Proved Properties—
Assets Sold(2)
Undeveloped Leasehold Costs, End of Period$2,351

As of March 31, 2019, undeveloped leasehold costs included $2.1 billion, $100 million, to $800$70 million, and $59 million attributable to the maturity date was extended from September 2021 to March 2023.Delaware Basin, Eagle Ford Shale, other US onshore properties and international properties, respectively.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)



Borrowings by Noble Midstream Partners under the Noble Midstream Services Revolving Credit Facility bear interest at a rate equalCertain of these costs pertain to an applicable margin plus, at Noble Midstream Partners' option, either (a) in the case of base rate borrowings, a rate equal to the highest of (1) the prime rate, (2) the greater of the federal funds rateacquired leases or the overnight bank funding rate, plus 0.5% and (3) the LIBOR for an interest period of one month plus 1.00%; or (b) in the case of LIBOR borrowings, the offered rate per annum for deposits of dollars for the applicable interest period.
As of June 30, 2018, $530 million was outstanding under the Noble Midstream Services Revolving Credit Facility. The increase from December 31, 2017 was primarily used to fund the Saddle Butte acquisition, as well as construction activities. See Note 3. Acquisitions and Divestitures.
Leviathan Term Loan Agreement On February 24, 2017, Noble Energy Mediterranean Ltd. (NEML), a wholly owned subsidiary of Noble Energy, entered into a facility agreement (Leviathan Term Loan Facility) which provides for a limited recourse secured term loan facility with an aggregate principal borrowing amount of up to $1.0 billion, $625 million of which is initially committed. Any amounts borrowed under the Leviathan Term Loan Facility will be available to fund a portion of our share of costs for the initial phase of development of the Leviathan field offshore Israel.
Any amounts borrowed will belicenses that are subject to repayment on a quarterly basis following production startup for the first phase of development, which is targeted for the end of 2019. Repayment will be in accordance with an amortization schedule set forth in the facility agreement, with a final balloon payment of no more than 35% of the loans outstanding. The Leviathan Term Loan Facility matures on February 23, 2025, and we can prepay borrowings at any time, in whole or in part, without penalty. The Leviathan Term Loan Facility contains customary representations and warranties, affirmative and negative covenants, events of default and also includes a prepayment mechanism that reduces the final balloon amount if cash flows exceed certain defined coverage ratios.
Any amounts borrowed will accrue interest at LIBOR, plus a margin of 3.50% per annum prior to production startup, 3.25% during the period following production startup until the last two years of maturity, and 3.75% during the last two years until the maturity date. We are also required to pay a commitment fee equal to 1.00% per annum on the unused and available commitments under the Leviathan Term Loan Facility until the beginning of the repayment period.
The Leviathan Term Loan Facility is secured by a first priority security interest in substantially all of NEML's interests in the Leviathan field and its marketing subsidiary, and in assets related to the initial phase of the project. All of NEML’s revenues from the first phase of Leviathan development will be deposited in collateral accounts and we will be required to maintain a debt service reserve account for the benefit of the lenders under the Leviathan Term Loan Facility. Once servicing accounts are replenished and debt service made, all remaining cash will be available to us and our subsidiaries. As of June 30, 2018, there were no borrowings under the Leviathan Term Loan Facility.
See Note 6. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of debt.
Redemption of Senior Notes In May 2018, we redeemed $379 million of Senior Notes due May 1, 2021 that we assumed in the merger (Rosetta Merger) with Rosetta Resources, Inc. in 2015 for $395 million, including $11 million of accrued interest and $5 million of call premium. We fully amortized $10 million of remaining premium and recognized a gain of $5 million, which is reflected in other non-operating (income) expense in our consolidated statements of operations.
Annual Debt Maturities Our nearest annual maturity of outstanding debt, excluding capital lease payments and outstanding balances under the revolving credit facilities, is $1.0 billion of senior notes which mature in 2021. The Revolving Credit Facility and Noble Midstream Services Revolving Credit Facility both mature in March 2023. No other balances are due withinexpiration over the next five years.
Subsequent Event - Noble Midstream Services Term Credit Agreement On July 31, 2018, Noble Midstream Services, LLC entered into a three year senior unsecured term loan credit facility (Noble Midstream Services Term Credit Agreement)several years unless production is established on units containing the acreage. Other costs pertain to acreage that permits aggregate borrowings of up to $500 million. Proceeds from the Noble Midstream Services Term Credit Agreement will be used to repay a portion of the outstanding borrowings under the Noble Midstream Services Revolving Credit Facility, pay fees and expenses in connection with the Noble Midstream Services Term Credit Agreement transactions and for working capital, capital expenditures, acquisitions and other purposes as necessary of Noble Midstream Partners and its subsidiaries.
Borrowings under the Noble Midstream Services Term Credit Agreement will bear interest at a rate equal to, at Noble Midstream Partners' option, either (1) a base rate plus an applicable margin between 0.00% and 0.50% per annum or (2) a Eurodollar rate plus an applicable margin between 1.00% and 1.50% per annum.
The Noble Midstream Services Term Credit Agreement contains customary representations and warranties, affirmative and negative covenants, and events of default that are substantially the same as those contained in the Noble Midstream Services Revolving Credit Facility. Upon the occurrence and during the continuation of an event of default under the Noble Midstream
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)



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 providedis being held by applicable law.production.

Note 6. Fair Value Measurements and Disclosures
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values: 
Cash, Cash Equivalents, Accounts Receivable and Accounts Payable The carrying amounts approximate fair value due to the short-term nature or maturity of the instruments. 
Mutual Fund Investments  Our mutual fund investments consist of various publicly-traded mutual funds that include investments ranging from equities to money market instruments. The fair values are based on quoted market prices for identical assets.
Commodity Derivative Instruments   Our commodity derivative instruments may include variable to fixed price commodity swaps, two-way collars, three-way collars, swaptions, enhanced swaps and basis swaps. We estimate the fair values of these instruments using published forward commodity price curves as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. In addition, for collars, we estimate the option values of the put options sold and the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract terms. SeeNote 4. Derivative Instruments and Hedging Activities. 
Investment in Tamar Petroleum Ltd Our investment in shares of Tamar Petroleum was acquired on March 14, 2018. The fair value of these shares is determined at the end of each quarter based on the trading price of Tamar Petroleum shares on the Tel Aviv Stock Exchange and is reduced by a 15% discount. The discount rate is based on analysis of historical discounts realized in private placements of public common stock, which we believe represents a reasonable estimate of the impact of the temporary lock-up provisions applicable to the shares we own. See Note 2. Basis of Presentation and Note 3. Acquisitions and Divestitures.
Deferred Compensation LiabilityThe value is dependent upon the fair values of mutual fund investments and shares of our common stock held in a rabbi trust.See Mutual Fund Investments above.
Stock-Based Compensation Liability A portion of the value of the liability associated with our phantom unit plan is dependent upon the fair value of Noble Energy common stock as of the end of each reporting period.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)



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 in 
Active Markets
(Level 1) (1)
 
Significant Other
Observable Inputs
(Level 2) (2)
 
Significant
Unobservable
Inputs (Level 3) (3)
 
Adjustment (4)
 Fair Value Measurement
June 30, 2018         
Financial Assets:         
Mutual Fund Investments$57
 $—
 $—
 $—
 $57
Commodity Derivative Instruments—
 72
 —
 (43) 29
Investment in Tamar Petroleum Ltd. (38,495,575 Shares) (5)
—
 150
 —
 —
 150
Financial 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, 2017         
Financial Assets:         
Mutual Fund Investments$57
 $—
 $—
 $—
 $57
Commodity Derivative Instruments—
 7
 —
 (5) 2
Financial 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 $4.60 per share.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)



Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Certain assets and liabilities such, as oil and gas properties, goodwill and other intangible assets, are not required to be measured at fair value on a recurring basis. However, these assets are assessed for impairment, and a resulting asset impairment would require the asset be recorded at fair value.
Asset Impairments During first quarter 2018, upon classification of the Gulf of Mexico properties as assets held for sale, we recognized an impairment of $168 million. See Note 3. Acquisitions and Divestitures. For second quarter 2018 and the first six months of 2017, we had no adjustments in fair value related to oil and gas properties.
Additional Fair Value Disclosures
Investment in CNX Midstream Partners Our investment in CNX Midstream Partners, which is included in our Midstream reportable segment, is accounted for using the equity method. The fair value of the investment is based on the published market price of the common units for the date indicated below.
 June 30, 2018 December 31, 2017
(millions)Carrying Amount Fair Value Carrying Amount Fair Value
Investment 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 sold 7.5 million common units, reducing our ownership in CNX Midstream Partners. See Note 3. Acquisitions and Divestitures.
Debt   The fair value of fixed-rate, public debt is estimated based on the published market prices for the same or similar issues. As such, we consider the fair value of our public, fixed-rate debt to be a Level 1 measurement on the fair value hierarchy.
Our Revolving Credit Facility, the Noble Midstream Services Revolving Credit Facility and the Leviathan Term Loan Facility are variable-rate, non-public debt. The fair value is estimated based on significant other observable inputs. As such, we consider the fair value of these facilities to be a Level 2 measurement on the fair value hierarchy. See Note 5. Debt.
Fair value information regarding our debt is as follows:
 June 30, 2018 December 31, 2017
(millions)Carrying Amount Fair Value Carrying Amount Fair Value
Long-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
Capitalized Exploratory Well CostsWe capitalize exploratory well costs until a determination is made that the well has found proved reserves or is deemed noncommercial. On a quarterly basis, we review the status of suspended exploratory well costs and assess the development of these projects. If a well is deemed to be noncommercial, the well costs are charged to exploration expense as dry hole cost.
Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the same period:
(millions)Six Months Ended June 30, 2018
Capitalized Exploratory Well Costs, Beginning of Period$520
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves4
Divestitures (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.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)




The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced:
(millions)June 30,
2018		 December 31,
2017
Exploratory Well Costs Capitalized for a Period of One Year or Less$8
 $10
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling348
 510
Balance at End of Period$356
 $520
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling7
 8


Undeveloped Leasehold Costs We reclassify undeveloped leasehold costs to proved property costs when, as a result of exploration and development activities, probable and possible resources are reclassified to proved reserves, including proved undeveloped reserves. On the other hand, if, based upon a change in exploration plans, timing and extent of development activities, availability of capital and suitable rig and drilling equipment, resource potential, comparative economics, changing regulations and/or other factors, an impairment is indicated, we record impairment expense related to the respective leases or licenses.
As of June 30, 2018, we had remaining undeveloped leasehold costs, to which proved reserves had not been attributed, of $2.6 billion, including $1.6 billion related to Delaware Basin assets acquired in the Clayton Williams Energy Acquisition in 2017, and $859 million and $129 million attributable to Delaware Basin and Eagle Ford Shale assets, respectively, acquired in the Rosetta Merger in 2015. Undeveloped leasehold costs were derived from allocated fair values as a result of business combinations or other purchases of unproved properties and are subject to impairment testing.
The remaining balance of undeveloped leasehold costs as of June 30, 2018 included $53 million related to international unproved properties. These costs pertain to acquired leases or licenses that are subject to expiration over the next several years unless production is established on units containing the acreage. These costs are evaluated as part of our periodic impairment review.
During the first half of 2018, we transferred $247 million and $20 million of 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 million of 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. See Note 3. Acquisitions and Divestitures.
Note 8.6. Asset Retirement Obligations
Asset retirement obligations (ARO) consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Changes in ARO are as follows:
Six Months Ended June 30,Three Months Ended March 31,
(millions)2018 20172019 2018
Asset Retirement Obligations, Beginning Balance$875
 $935
$880
 $875
Liabilities Incurred14
 82
2
 2
Liabilities Settled(261) (32)(27) (20)
Revisions of Estimates(10) (15)—
 (11)
Accretion Expense (1)
17
 23
Reclassification to Liabilities Associated with Assets Held for Sale—
 (227)
Accretion Expense12
 9
Asset Retirement Obligations, Ending Balance$635
 $993
$867
 $628

(1)
Accretion expense is included in depreciation, depletion and amortization (DD&A)expense in the consolidated statements ofoperations.
For the SixThree Months Ended June 30, 2018March 31, 2019 Liabilities settled include $216of $27 million relate to abandonment of US onshore properties, primarily in the DJ Basin where we have engaged in a program to plug and abandon older vertical wells. Costs associated with these abandonment activities will be incurred over several years.
Three Months Ended March 31, 2018 We transferred $227 million of ARO liabilities assumed by the purchaser of therelated to Gulf of Mexico properties and $44to liabilities associated with assets held for sale. Liabilities settled include $20 million related to abandonment of US onshore properties, primarily in the DJ Basin. Revisions of estimates primarily relate to decreases in cost and timing estimates of $11 million associated with the North Sea abandonment project and $6 million for Eastern Mediterranean, partially offset by an increase of $7 million for US onshore.project.
Note 7. Debt
ForDebt consists of the following:
 March 31, 2019 December 31, 2018
(millions, except percentages)Debt Interest Rate
 Debt Interest Rate
Revolving Credit Facility, due March 9, 2023 (1)
$—
 —% $—
 —%
Noble Midstream Services Revolving Credit Facility, due March 9, 2023 (2)
230
 3.66% 60
 3.67%
Noble Midstream Services Term Loan Credit Facility, due July 31, 2021500
 3.41% 500
 3.42%
Senior Notes and Debentures5,892
 
(3 
) 
 5,892
 
(3 
) 
Finance Lease Obligations (4)
215
 —% 223
 —%
Total6,837
   6,675
  
Net Unamortized Discounts and Debt Issuance Costs(58)   (60)  
Total Debt6,779
   6,615
  
Less Amounts Due Within One Year       
Finance Lease Obligations (4)
(41)   (41)  
Long-Term Debt Due After One Year$6,738
   $6,574
  

(1)
As of March 31, 2019 and December 31, 2018, the Revolving Credit Facility had $4.0 billion of capacity and the entire amount was available for borrowing.
(2)
As of March 31, 2019 and December 31, 2018, the Noble Midstream Services Revolving Credit Facility had $800 million of capacity. Amounts available for borrowing at totaled $570 million and $740 million, respectively.
(3)
The Senior Notes and Debentures have weighted average interest rates of 5.01% for both March 31, 2019 and December 31, 2018.
(4)
See Note 8. Leases.

Commercial Paper Program Six Months Ended June 30, 2017 Liabilities incurred include $59 million relatedIn first quarter 2019, we established a commercial paper program to the Clayton Williams Energy Acquisitionprovide for short-term funding needs. The program allows for a maximum of $4.0 billion of unsecured commercial paper notes and $23 million primarily for other US onshore wells and facilities placed into service. Liabilities settled primarily related to US onshore property abandonments, as well as $12 million related to properties sold in the Marcellus Shale upstream divestiture. Revisions of estimates related to decreases in cost and timing estimates of $30 million for US onshore and Gulf of Mexico, partially offsetis supported by an increase of $15 million for West Africa.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)

Noble Energy’s Revolving Credit Facility. Commercial paper generally has a maturity of between 1 and 90 days, although it can have a maturity of up to 397 days. The commercial paper is sold under customary terms in the commercial paper market and notes are either issued at a discounted price relative to the principal face value or will bear interest at varying interest rates on a fixed or floating basis. Such discounted prices or interest amounts are dependent on market conditions and ratings assigned to the commercial paper program by credit agencies at the time of commercial paper issuance. No borrowings or repayments occurred during first quarter 2019 under the commercial paper program.
Fair Value of Debt See Note 13. Fair Value Measurements and Disclosures.
Note 8. Leases
In the normal course of business, we enter into operating and finance lease agreements to support our operations. Operating leases include primarily office space for our corporate and field locations, US onshore compressors and drilling rigs, vessels and helicopters for offshore operations, storage facilities, and other miscellaneous assets. Finance leases include corporate office space, a trunkline in the DJ Basin, a floating production, storage and offloading vessel (FPSO) in West Africa, and vehicles. Our leasing activity is recorded and presented on a gross basis, with the exception of the FPSO which is recorded net to our interest.
Balance Sheet Information ROU assets and lease liabilities are as follows:
(millions)Balance Sheet LocationMarch 31, 2019
ROU Assets  
Operating Leases (1)
Other Noncurrent Assets$273
Finance Leases (2)
Total Property, Plant and Equipment, Net179
Total ROU Assets $452
Lease Liabilities  
Current Liabilities  
Operating LeasesOther Current Liabilities$86
Finance LeasesOther Current Liabilities41
Noncurrent Liabilities  
Operating LeasesOther Noncurrent Liabilities194
Finance LeasesLong-Term Debt174
Total Lease Liabilities $495
(1)
Operating lease ROU assets include primarily office space of $107 million, compressors of $87 million, and drilling rigs of $40 million.
(2)
Finance lease ROU assets are recorded net of accumulated amortization of $449 million as of March 31, 2019. Assets include primarily office space of $96 million, net.

Statement of Operations Information The components of lease cost are as follows:
(millions)Statement of Operations LocationThree Months Ended March 31, 2019
Operating Lease Cost
(1) 
$25
Finance Lease Cost  
Amortization Expense on ROU AssetsDepreciation, Depletion and Amortization8
Interest Expense on Lease LiabilitiesInterest, Net of Amount Capitalized3
Short-term Lease Cost (2)
(1) 
126
Variable Lease Cost (3)
(1) 
—
Sublease IncomeGeneral and Administrative(1)
Total Lease Cost $161
(1)
Cost classification varies depending on the leased asset. Costs are primarily included within production expense and general and administrative expense. In addition, in accordance with the successful efforts method of accounting, certain lease costs may be capitalized when incurred, as part of oil and gas properties on our consolidated balance sheet.
(2)
Short-term lease costs relate primarily to hydraulic fracturing services, well-to-well drilling rig contracts and other miscellaneous lease agreements. Amount excludes costs for leases with a term of one month or less.
(3)
Variable lease costs were de minimis for first quarter 2019.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)


Cash Flow Information Supplemental cash flow information is as follows:
 Three Months Ended March 31, 2019
(millions)Operating Leases Finance Leases
Cash Paid for Amounts Included in the Measurement of Lease Liabilities   
Operating Cash Flows$15
 $3
Financing Cash Flows—
 10
Investing Cash Flows9
 —
ROU Assets Obtained in Exchange for Lease Liabilities (1)
34
 2
(1)
Amounts exclude the impact from adopting ASC 842 on January 1, 2019. See Note 2. Basis of Presentation.

Maturity of Lease Liabilities Maturities of lease liabilities as of March 31, 2019 are as follows:
(millions)Operating Leases Finance Leases Total
Remainder of 2019$73
 $37
 $110
202083
 47
 130
202147
 32
 79
202232
 22
 54
202319
 20
 39
2024 and Thereafter67
 105
 172
Total Lease Liabilities, Undiscounted321
 263
 584
Less: Imputed Interest41
 48
  
Total Lease Liabilities (1)
$280
 $215
  
(1)
Includes the current portion of $86 million and $41 million for operating and finance leases, respectively.

Lease commitments as of December 31, 2018 were as follows:
(millions)Operating Leases Finance Leases Total
2019$91
 $52
 $143
202074
 46
 120
202159
 31
 90
202262
 22
 84
202350
 20
 70
2024 and Thereafter176
 104
 280
Total Lease Liabilities, Undiscounted$512
 $275
 $787


Other Information Other information related to our leases is as follows:
March 31, 2019
Weighted-Average Remaining Lease Term
Operating Leases6.7 years
Finance Leases8.0 years
Weighted-Average Discount Rate
Operating Leases4.45%
Finance Leases5.61%

Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)

Note 9. Exit Cost – Transportation Commitments
In connection with the divestiture of Marcellus Shale upstream assets in 2017, we retained certain financial commitments on pipelines flowing natural gas production inside and outside of the Marcellus Basin. These financial commitments represent commitments to pay transportation fees; thus, we have no commitment to physically transport minimum volumes of natural gas.
Since closing, we have continued efforts to commercialize these firm transportation commitments, including permanent assignment of capacity, negotiation of capacity releases, utilization of capacity through purchase and transport of third-party natural gas, and other potential arrangements. In the event we execute a permanent assignment of capacity, we no longer have a contractual obligation to the pipeline company and, as such, our gross contractual commitment is reduced. In the event we execute a capacity release or utilize capacity through the purchase and transport of natural gas, we remain the primary obligor to the pipeline company. While our gross contractual commitment is not reduced, except through use under those arrangements, we would receive future cash payments from the third-parties with whom we negotiated a capacity release or from the sale of purchased natural gas to third-parties.
As of March 31, 2019, our gross retained firm transportation commitment for the remaining obligations under these agreements, which have remaining terms of approximately four to fourteen years, is approximately $1.1 billion, undiscounted.
Leach Xpress and Rayne Xpress Permanent Assignment In January2019, we executed agreements on the Leach Xpress and Rayne Xpress pipelines to permanently assign remaining capacity to a third-party effective January 1, 2021, extending through the end of the contract. The permanent assignment reduced our total financial commitment by approximately $350 million, undiscounted. As a result of the assignment, we recorded firm transportation exit cost of $92 million, discounted, related to future commitments to the third party. We will continue efforts to mitigate the impact of these transportation agreements during 2019 and 2020.
Financial Statement Impact In addition to the retained firm transportation commitments, we have the following accrued discounted liabilities associated with exit cost activities, including the permanent assignment described above:
 Three Months Ended March 31,
(millions)2019 2018
Balance at Beginning of Period (1)
$80
 $90
Firm Transportation Exit Cost Accrual92
 —
Payments, Net of Accretion(5) (6)
Balance at End of Period167

84
Less: Current Portion Included in Other Current Liabilities11
 11
Long-term Portion Included in Other Noncurrent Liabilities at End of Period$156
 $73
(1)
Balances include current accruals of $13 million which are included in other current liabilities on our consolidated balance sheets.
Revenues and expenses associated with capacity release agreements and purchases and sales of natural gas are as follows:
  Three Months Ended March 31,
(millions)Statements of Operations Location2019 2018
Sales of Purchased GasSales of Purchased Oil and Gas$27
 $31
Cost of Purchased Gas and Related Expense    
Cost of Purchased of GasCost of Purchased Oil and Gas27
 30
Utilized Firm Transportation Expense (1)
Cost of Purchased Oil and Gas15
 5
Unutilized Firm Transportation ExpenseCost of Purchased Oil and Gas—
 1
Cost of Purchased Gas and Related Expense, TotalCost of Purchased Oil and Gas$42
 $36
(1)
Includes the net impact of the difference in the firm transportation contract rates and rates agreed to in the capacity releases, as well as transportation expenses associated with transport of purchased natural gas.
Note 10. Commitments and Contingencies
Legal ProceedingsWe are involved in various legal proceedings in the ordinary course of business. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters, and we believe that the ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations or cash flows.
Colorado Air Matter In April 2015, we entered into a joint consent decree (Consent Decree) with the US Environmental Protection Agency (EPA), US Department of Justice, and State of Colorado to improve emission control systems at a number of our condensate storage tanks that are part of our upstream crude oil and natural gas operations within the Non-Attainment Area of the DJ Basin. The Consent Decree, entered by the US District Court for the District of Colorado on June 2, 2015, requires us to perform certain corrective actions, to complete mitigation projects and supplemental environmental projects (SEP), and to pay a civil penalty. Costs associated with the settlement consist of $5 million in civil penalties which were paid in 2015. Mitigation costs of $5 million, SEP costs of $4 million, and costs associated with the injunctive relief are being expended in accordance with schedules established in the Consent Decree. Since 2015, we have incurred approximately $84 million, of which $78 million was incurred to undertake corrective actions at certain tank systems following the outcome of adequacy of design evaluations and certain operation and maintenance activities to handle potential peak instantaneous vapor flow rates. Future costs associated with injunctive relief are not yet precisely quantifiable as we are continually evaluating various approaches to meet the ongoing obligations of the Consent Decree.
We have concluded that the penalties, injunctive relief, and mitigation expenditures that result from this settlement, based on currently available information, will not have a material adverse effect on our financial position, results of operations or cash flows. See Note 6. Asset Retirement Obligations.
Colorado Water Quality Control Division Matter In January 2017, we received a Notice of Violation/Cease and Desist Order (NOV/CDO) advising us of alleged violations of the Colorado Water Quality Control Act (Act) and its implementing regulations as it relates to our Colorado Discharge Permit System General Permit for construction activities associated with oil and gas exploration and/or production within our Wells Ranch Drilling and Production field located in Weld County, Colorado (Permit).  The NOV/CDO further orders us to cease and desist from all violations of the Act, the regulations and the Permit and to undertake certain corrective actions. In October 2018, we met with enforcement staff at the Colorado Department of Public Health and Environment to discuss a potential settlement of the alleged violations. Given the ongoing status of such settlement discussions, 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.
Colorado Clean Water Act Referral Notice In September 2018, we received a letter from the US Department of Justice providing notification of referral from the EPA of alleged Clean Water Act violations at an upstream production facility and a midstream gathering facility in Weld County, Colorado. The letter requests an opportunity to discuss settlement of the alleged violations. Given the uncertainty associated with enforcement 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.
Note 11. Income Taxes
The incomeIncome tax expense (benefit) expense consists of the following:
Three Months Ended June 30, Six Months Ended June 30,Three Months Ended March 31,
(millions, except percentages)2018 2017 2018 20172019 2018
Current$23
 $37
 $149
 $49
$16
 $126
Deferred(7) (873) (164) (873)(100) (157)
Total Income Tax Expense (Benefit)$16
 $(836) $(15) $(824)
Total Income Tax Benefit$(84) $(31)
Effective Tax Rate160.0% 35.8% (2.7)% 36.2%22.5% (5.7)%

Changes in US Tax Law On December 22, 2017, the US Congress enacted the Tax Cuts and Jobs Act (Tax Reform Legislation), which made significant changes to US federal income tax law, including a reduction in the federal corporate tax rate to 21%, effective January 1, 2018. In accordance with US GAAP, we recognized the effect of the rate change on deferred tax assets and liabilities as of December 31, 2017.
On April 2, 2018, the US Department of the Treasury and the Internal Revenue Service released Notice 2018-26, signaling intent to issue regulations related to the transition tax (toll tax) on a one-time “deemed repatriation” of accumulated foreign earnings for the year ended December 31, 2017. Notice 2018-26 clarifies that an Internal Revenue Code Section 965(n) election is available with respect to both current year operating losses and net operating losses from a prior year. As a result, during first quarter 2018, we released the valuation allowance recorded against foreign tax credits that will be utilized against the $268 million toll tax liability we had recorded as of December 31, 2017, resulting in a $252 million tax benefit, and reduced our estimated toll tax liability to $16 million to be paid in installments over eight years. We also recorded a corresponding expense of $107 million for the tax rate change adjustment on the previously utilized net operating losses. The impact on first quarter 2018 total tax expense, related to this additional guidance, was a net $145 million discrete tax benefit.
During second quarter 2018, we made no changes to the provisional amounts recognized in 2017.
The ultimate impact of the Tax Reform Legislation may differ from our estimates due to changes in interpretations and assumptions made by us, as well as additional regulatory guidance that may be issued. In particular, our estimate of the impact of the toll tax is a provisional amount, based on current legal interpretations. This amount may be adjusted further in future periods, as an adjustment to income tax expense or benefit, in the period in which the final amounts are determined.
Effective Tax Rate (ETR) At the end of each interim period, we apply a forecasted annualized effective tax rate (ETR)ETR to current period earnings or loss before tax, which can result in significantproduce interim ETR fluctuations. OurThe ETR for the six months ended June 30, 2018first quarter 2019 varied as compared with the six months ended June 30, 20172018, primarily due to a deferred tax benefit of $145 million recorded discretely in the current year, as discussed above, and a significant deferreddiscrete tax benefit recorded atin first quarter 2018 as a result of the higher prior yearintent of the US Department of the Treasury and Internal Revenue Service to issue additional regulatory guidance associated with Tax Reform Legislation and the transition tax rate of 35% on the Marcellus Shale upstream divestiture in second quarter 2017.(toll tax). In addition, the increase in the current income tax expense for the six months ended June 30,first quarter 2018 is primarily due toincludes foreign taxes on a gain associated withrelated to the first quarter 2018 divestiture of a 7.5% interest in the Tamar field, offshore Israel.
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) and Equatorial Guinea – 2013.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)



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)2018 2017 2018 2017
Net (Loss) Income and Comprehensive (Loss) Income Attributable to Noble Energy$(23) $(1,512) $531
 $(1,476)
Weighted Average Number of Shares Outstanding, Basic484
 472
 485
 452
Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust—
 —
 2
 —
Weighted Average Number of Shares Outstanding, Diluted484
 472
 487
 452
(Loss) Income Per Share, Basic$(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 Above14
 16
 14
 15


Note 11. Segment Information12. Derivative Instruments and Hedging Activities
Objective and Strategies for Using Derivative InstrumentsWe have the following reportable segments: United States (US onshore and Gulf of Mexico (until April 2018)); Eastern Mediterranean (Israel and Cyprus); West Africa (Equatorial Guinea, Cameroon and Gabon); Other International (Falkland Islands, Suriname, Canada, and New Ventures); and Midstream. The Midstream segment includes the consolidated accounts of Noble Midstream Partners, US onshore equity method investments and other US onshore midstream assets.
The geographical reportable segments are in the business ofenter into crude oil and natural gas acquisitionprice hedging arrangements in an effort to mitigate the effects of commodity price volatility and exploration, development,enhance the predictability of cash flows relating to the marketing of a portion of our crude oil and production (Oil and Gas Exploration and Production). The Midstream reportable segment owns, acquires, operates, and develops domestic midstream infrastructure assets, with current focus areas beingnatural gas production. While these instruments mitigate the DJ and Delaware Basins. Expenses related to debt, headquarters depreciation and corporate general and administrative expenses are recorded at the corporate level.
   Oil and Gas Exploration and Production Midstream  
(millions)Consolidated United
States		 Eastern
Mediter- ranean		 West
Africa		 Other Int'l United States 
Intersegment Eliminations and Other (1)
 Corporate
Three Months Ended June 30, 2018              
Crude Oil Sales$749
 $635
 $2
 $112
 $—
 $—
 $—
 $—
NGL Sales137
 137
 —
 —
 —
 —
 —
 —
Natural Gas Sales214
 98
 111
 5
 —
 —
 —
 —
Total Crude Oil, NGL and Natural Gas Sales1,100
 870
 113
 117
 —
 —
 —
 —
Income from Equity Method Investees and Other64
 —
 —
 36
 —
 28
 —
 —
Sales of Purchased Oil and Gas66
 24
 —
 —
 —
 42
 —
 —
Intersegment Revenues—
 —
 —
 —
 —
 85
 (85) —
Total Revenues1,230
 894
 113
 153
 —
 155
 (85) —
Lease Operating Expense132
 114
 5
 19
 —
 —
 (6) —
Production and Ad Valorem Taxes50
 48
 —
 —
 —
 2
 —
 —
Gathering, Transportation and Processing Expense100
 133
 —
 —
 —
 22
 (55) —
Other Royalty Expense10
 10
 —
 —
 —
 —
 —
 —
Total Production Expense292
 305
 5
 19
 —
 24
 (61) —
DD&A465
 394
 15
 26
 —
 22
 (4) 12
Loss (Gain) on Divestitures(78) 21
 10
 —
 —
 (109) —
 —

cash flow risk of future decreases in commodity prices, they may also curtail benefits from future increases in commodity prices. 
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)



Unsettled Commodity Derivative Instruments   As of March 31, 2019, the following crude oil derivative contracts were outstanding:
Purchased Oil and Gas71
 31
 —
 —
 —
 40
 —
 —
Loss on Commodity Derivative Instruments249
 196
 —
 53
 —
 —
 —
 —
(Loss) Income Before Income Taxes10
 (90) 62
 48
 (13) 175
 (18) (154)
                
Three Months Ended June 30, 2017  
  
  
        
Crude Oil Sales$557
 $458
 $1
 $98
 $—
 $—
 $—
 $—
NGL Sales108
 108
 —
 —
 —
 —
 —
 —
Natural Gas Sales352
 214
 132
 6
 —
 —
 —
 —
Total Crude Oil, NGL and Natural Gas Sales1,017
 780
 133
 104
 —
 —
 —
 —
Income from Equity Method Investees and Other42
 —
 —
 25
 —
 17
 —
 —
Intersegment Revenues—
 —
 —
 —
 —
 69
 (69) —
Total Revenues1,059
 780
 133
 129
 —
 86
 (69) —
Lease Operating Expense124
 105
 6
 18
 —
 —
 (5) —
Production and Ad Valorem Taxes32
 32
 —
 —
 —
 —
 —
 —
Gathering, Transportation and Processing Expense121
 142
 —
 —
 —
 17
 (38) —
Other Royalty Expense6
 6
 —
 —
 —
 —
 —
 —
Total Production Expense283
 285
 6
 18
 —
 17
 (43) —
DD&A503
 427
 19
 39
 1
 5
 —
 12
Loss on Marcellus Shale Upstream Divestiture2,322
 2,322
 —
 —
 —
 —
 —
 —
Loss on Commodity Derivative Instruments(57) (51) —
 (6) —
 —
 —
 —
(Loss) Income Before Income Taxes(2,334) (2,319) 106
 72
 (4) 58
 (13) (234)
                
Six Months Ended June 30, 2018  
  
  
        
Crude Oil Sales$1,522
 $1,317
 $4
 $201
 $—
 $—
 $—
 $—
NGL Sales283
 283
 —
 —
 —
 —
 —
 —
Natural Gas Sales468
 218
 240
 10
 —
 —
 —
 —
Total Crude Oil, NGL and Natural Gas Sales2,273
 1,818
 244
 211
 —
 —
 —
 —
Income from Equity Method Investees and Other124
 —
 —
 71
 —
 53
 —
 —
Sales of Purchased Oil and Gas119
 55
 —
 —
 —
 64
 —
 —
Intersegment Revenues—
 —
 —
 —
 —
 166
 (166) —
Total Revenues2,516
 1,873
 244
 282
 —
 283
 (166) —
Lease Operating Expense287
 240
 12
 41
 —
 —
 (6) —
Production and Ad Valorem Taxes104
 101
 —
 —
 —
 3
 —
 —
Gathering, Transportation and Processing Expense195
 260
 —
 —
 —
 43
 (108) —
Other Royalty Expense27
 27
 —
 —
 —
 —
 —
 —
Total Production Expense613
 628
 12
 41
 —
 46
 (114) —
DD&A933
 800
 28
 52
 —
 38
 (8) 23
Gain on Divestitures(666) 15
 (376) —
 —
 (305) —
 —
    Swaps Collars
Settlement PeriodType of ContractIndexBbls Per DayWeighted Average DifferentialWeighted Average Fixed Price Weighted Average Short Put PriceWeighted Average Floor PriceWeighted Average Ceiling Price
2019SwapsNYMEX WTI22,000$—
$56.96
 $—
$—
$—
2019Three-Way CollarsNYMEX WTI33,000—
—
 49.35
59.35
72.25
2019SwaptionNYMEX WTI5,000—
62.50
 —
—
—
2019SwapsICE Brent5,000—
57.00
 —
—
—
2019Three-Way CollarsICE Brent3,000—
—
 43.00
50.00
64.07
2019Basis Swaps
(1) 
27,000(3.23)—
 —
—
—
2020SwaptionNYMEX WTI5,000—
61.79
 —
—
—
2020Three-Way CollarsNYMEX WTI10,000—
—
 50.00
58.00
67.37
2020Basis Swaps
(1) 
15,000(5.01)—
 —
—
—

(1)
We entered into crude oil basis swap contracts to establish a fixed amount for the differential between pricing in Midland, Texas, and Cushing, Oklahoma. The weighted average differential represents the amount of reduction to Cushing, Oklahoma prices for the notional volumes covered by the basis swap contracts.
As of March 31, 2019, the following natural gas derivative contracts were outstanding:
    Swaps Collars
Settlement PeriodType of ContractIndexMMBtu Per DayWeighted Average DifferentialWeighted Average Fixed Price Weighted Average Short Put PriceWeighted Average Floor PriceWeighted Average Ceiling Price
2019Three-Way CollarsNYMEX HH104,000
$—
$—
 $2.25
$2.65
$2.95
2019SwapsNYMEX HH46,000
—
3.00
 —
—
—
2019Basis Swaps
CIG (1)
113,500
(0.65)—
 —
—
—
2019Basis Swaps
WAHA (1)
15,000
(1.44)—
 —
—
—
2020Basis Swaps
CIG (1)
44,000
(0.62)—
 —
—
—
2020Basis Swaps
WAHA (1)
17,000
(0.75)—
 —
—
—

(1)
We entered into natural gas basis swap contracts to establish a fixed amount for the differential between the noted index pricing and NYMEX Henry Hub. The weighted average differential represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes covered by the basis swap contracts.
Fair Value AmountsThe fair values of commodity derivative instruments in our consolidated balance sheets were as follows:
 Asset Derivative Instruments Liability Derivative Instruments
(millions)Balance Sheet LocationMarch 31, 2019 December 31, 2018 Balance Sheet LocationMarch 31, 2019 December 31, 2018
Commodity Derivative InstrumentsOther Current Assets$9
 $180
 Other Current Liabilities$63
 $1
 Other Noncurrent Assets1
 —
 Other Noncurrent Liabilities20
 26
 Total$10
 $180
  $83
 $27

See Note 13. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of our derivative instruments.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)



Gains and Losses on Commodity Derivative Instruments The effect of commodity derivative instruments on our consolidated statements of operations and comprehensive income was as follows:
Asset Impairments168
 168
 —
 —
 —
 —
 —
 —
Purchased Oil and Gas128
 67
 —
 —
 —
 61
 —
 —
Loss on Commodity Derivative Instruments328
 260
 —
 68
 —
 —
 —
 —
Income (Loss) Before Income Taxes553
 (127) 535
 112
 (27) 428
 (40) (328)
                
Six Months Ended June 30, 2017  
  
  
        
Crude Oil Sales$1,084
 $897
 $2
 $185
 $—
 $—
 $—
 $—
NGL Sales213
 213
 —
 —
 —
 —
 —
 —
Natural Gas Sales714
 440
 263
 11
 —
 —
 —
 —
Total Crude Oil, NGL and Natural Gas Sales2,011
 1,550
 265
 196
 —
 —
 —
 —
Income from Equity Method Investees and Other84
 —
 —
 52
 —
 32
 —
 —
Intersegment Revenues—
 —
 —
 —
 —
 127
 (127) —
Total Revenues2,095
 1,550
 265
 248
 —
 159
 (127) —
Lease Operating Expense263
 211
 14
 40
 —
 —
 (2) —
Production and Ad Valorem Taxes73
 72
 —
 —
 —
 1
 —
 —
Gathering, Transportation and Processing Expense240
 280
 —
 —
 —
 32
 (72) —
Other Royalty Expense10
 10
 —
 —
 —
 —
 —
 —
Total Production Expense586
 573
 14
 40
 —
 33
 (74) —
DD&A1,031
 886
 37
 74
 2
 10
 —
 22
Loss on Marcellus Shale Upstream Divestiture2,322
 2,322
 —
 —
 —
 —
 —
 —
Gain on Commodity Derivative Instruments(167) (154) —
 (13) —
 —
 —
 —
Income (Loss) Before Income Taxes(2,275) (2,251) 207
 138
 (11) 107
 (35) (430)
                
June 30, 2018 
  
  
  
        
Goodwill (2)
$1,402
 $1,291
 $—
 $—
 $—
 $111
 $—
 $—
Total Assets21,854
 15,138
 2,996
 1,275
 62
 2,280
 (140) 243
December 31, 2017   
  
  
        
Goodwill (2)
1,310
 1,310
 —
 —
 —
 —
 —
 —
Total Assets21,476
 15,767
 2,846
 1,308
 114
 1,357
 (163) 247
 Three Months Ended March 31,
(millions)2019 2018
Cash (Received) Paid in Settlement of Commodity Derivative Instruments   
Crude Oil$(9) $30
Natural Gas(5) (2)
Total Cash (Received) Paid in Settlement of Commodity Derivative Instruments$(14) $28
Non-cash Portion of Loss on Commodity Derivative Instruments   
Crude Oil$223
 $50
Natural Gas3
 1
Total Non-cash Portion of Loss on Commodity Derivative Instruments$226
 $51
Loss (Gain) on Commodity Derivative Instruments   
Crude Oil$214
 $80
Natural Gas(2) (1)
Total Loss on Commodity Derivative Instruments$212
 $79

(1) The intersegment eliminations related to income (loss) before income taxes are the result of midstream expenditures.  These costs are presented as property, plant and equipment within the E&P business on an unconsolidated basis, in accordance with the successful efforts method of accounting, and are eliminated upon consolidation.
(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. Commitments13. Fair Value Measurements and ContingenciesDisclosures
Legal ProceedingsAssets and Liabilities Measured at Fair Value on a Recurring Basis
Cash and Cash Equivalents, Accounts Receivable and Accounts Payable   The carrying amounts approximate fair value due to the short-term nature or maturity of the instruments. 
Mutual Fund Investments  Our mutual fund investments consist of various publicly-traded mutual funds that include investments ranging from equities to money market instruments. Fair values are based on quoted market prices for identical assets.
Commodity Derivative Instruments   Our commodity derivative instruments may include variable to fixed price commodity swaps, two-way collars, three-way collars, swaptions, enhanced swaps and basis swaps. We are involved in various legal proceedingsestimate the fair values using published forward commodity price curves as of the date of the estimate. The discount rate used in the ordinary coursecash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. The fair values of business. These proceedings are subject tocommodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and instruments in a liability position include a measure of our own nonperformance risk, each based on the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters,current published credit default swap rates. In addition, for collars, we estimate the values of put options sold and we believe that the ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations or cash flows.contract floors and ceilings using an option pricing model which considers market volatility, market prices and contract terms. SeeNote 12. Derivative Instruments and Hedging Activities. 
Marcellus Shale Deferred Compensation LiabilityFair value is dependent upon the fair values of mutual fund investments and shares of our common stock held in a rabbi trust.See Mutual Fund Investments, above.
Stock-Based Compensation Liability A portion of the value of the liability associated with our phantom unit plan is dependent upon the fair value of Noble Energy common stock at the end of each reporting period.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)

Measurement information for assets and liabilities measured at fair value on a recurring basis is as follows: 
 Fair Value Measurements Using    
(millions)
Quoted Prices in Active Markets
(Level 1)
 
Significant Other Observable Inputs
(Level 2)
 
Significant Unobservable Inputs
(Level 3)
 
Adjustment (1)
 Fair Value Measurement
March 31, 2019         
Financial Assets:         
Mutual Fund Investments$41
 $—
 $—
 $—
 $41
Commodity Derivative Instruments—
 23
 —
 (13) 10
Financial Liabilities:         
Commodity Derivative Instruments—
 (96) —
 13
 (83)
Portion of Deferred Compensation Liability Measured at Fair Value(48) —
 —
 —
 (48)
Stock Based Compensation Liability Measured at Fair Value(1) —
 —
 —
 (1)
December 31, 2018         
Financial Assets:         
Mutual Fund Investments$38
 $—
 $—
 $—
 $38
Commodity Derivative Instruments—
 187
 —
 (7) 180
Financial Liabilities:         
Commodity Derivative Instruments—
 (34) —
 7
 (27)
Portion of Deferred Compensation Liability Measured at Fair Value(43) —
 —
 —
 (43)
Stock Based Compensation Liability Measured at Fair Value(8) —
 —
 —
 (8)

(1)
Amount represents the impact of netting provisions within our master agreements allowing us to net cash settled asset and liability positions with the same counterparty.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Firm Transportation ContractsExit Cost Accrual In connection with the 2017 Marcellus Shale upstream divestiture,January 2019, we retained certainrecorded a firm transportation obligations to flow Marcellus Shale natural gas production to various markets inside and outside of the Marcellus Basin. Our financial commitment for these agreements, which have remaining terms of approximately four to 15 years, is approximately $1.4 billion, undiscounted. The agreements for firm transportation primarily relate to services on certain pipelines which were placed into service in late 2017 and early 2018 or for services on new pipeline projects to be constructed by, and connecting to, existing and new interstate pipeline systems, with estimated in-service dates in late 2018.
We are currently engaged in actions to commercialize these commitments which provide for the transportation of 450,000 MMBtu/d of natural gas. Actions include the permanent assignment of capacity, negotiation of capacity release, utilization of capacity through purchase of third party natural gas, and other potential arrangements. We continue to expect these actions, some of which may require pipeline and/or FERC approval, to ultimately reduce our financial commitment associated with these contracts. At the date each pipeline is placed in service and our commitment begins, we will evaluate our position. If we determine that we will not utilize a portion, or all, of the contracted pipeline capacity, we will accrue aexit cost liability at fair value forof $92 million, representing the net amountdiscounted present value of our remaining obligation under a permanent pipeline capacity assignment in the estimated remaining financial commitment.Marcellus Shale. See Note 9. Exit Cost – Transportation Commitments.
We cannot guarantee our commercialization efforts will be successful andRedeemable Noncontrolling Interest As of March 31, 2019, we may recognize substantial future liabilities,recorded redeemable noncontrolling interest, associated with the issuance of GIP preferred equity, at fair value for the net amount of the estimated remaining commitments under these contracts. As$97 million, representing issuance date proceeds of June 30, 2018, our exit cost accrual, relating to certain transportation arrangements, totals $83$100 million discounted. For the first six months of 2018, we incurred expensenetted with associated issuance costs of $3 million relatedmillion. See Note 4. Acquisitions and Divestitures.
Additional Fair Value Disclosures
Debt   The fair value of fixed-rate, public debt is estimated based on published market prices. As such, we consider the fair value this debt to unutilized transportation relatedbe a Level 1 measurement on the fair value hierarchy.
Our non-public debt, including our Revolving Credit Facility, Noble Midstream Services Revolving Credit Facility, Noble Midstream Services Term Loan Credit Facility and borrowings under the commercial paper program, are subject to these contracts.variable interest rates. The fair value is estimated based on significant other observable inputs; thus, we consider the fair values to be Level 2 measurements on the fair value hierarchy. See Note 7. Debt.
Colorado Air Matter Fair value information regarding our debt is as follows:
 March 31, 2019 December 31, 2018
(millions)Carrying Amount Fair Value Carrying Amount Fair Value
Long-Term Debt (1)
$6,622
 $6,841
 $6,452
 $6,121

(1)
Excludes unamortized discount, debt issuance costs and finance lease obligations. See Note 8. Leases.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)

Note 14. Net (Loss) Income Per Share Attributable to Noble Energy Common Shareholders
In April 2015, we entered into a joint consent decree (Consent Decree) withNoble Energy's basic (loss) income per share of common stock is computed by dividing net (loss) income attributable to Noble Energy by the US Environmental Protection Agency, US Department of Justice, and State of Colorado to improve emission control systems at aweighted average number of our condensate storage tanks that are partshares of our upstream crude oilNoble Energy common stock outstanding during each period. The following table summarizes the calculation of basic and natural gas operations within the Non-Attainment Area of the DJ Basin. The Consent Decree was entered by the US District Court for the District of Colorado on June 2, 2015.   diluted (loss) income per share:
The Consent Decree, which alleges violations of the Colorado Air Pollution Prevention and Control Act and Colorado’s federal approved State Implementation Plan, specifically Colorado Air Quality Control Commission Regulation Number 7, requires us to perform certain corrective actions, to complete mitigation projects, to complete supplemental environmental projects (SEP), and to pay a civil penalty. Costs associated with the settlement consist of $5 million in civil penalties which were paid in 2015. Mitigation costs of $5 million and SEP costs of $4 million are being expended in accordance with schedules established in the Consent Decree. Costs associated with the injunctive relief are also being expended in accordance with schedules established in the Consent Decree. Since 2015, we have incurred approximately $83 million to undertake corrective actions at certain tank systems following the outcome of adequacy of design evaluations and certain operation and maintenance activities to handle potential peak instantaneous vapor flow rates. Future costs associated with injunctive relief are not yet precisely quantifiable as we are continually evaluating various approaches to meet the ongoing obligations of the Consent Decree.
 Three Months Ended March 31,
(millions, except per share amounts)2019 2018
Net (Loss) Income and Comprehensive (Loss) Income Attributable to Noble Energy$(313) $554
Weighted Average Number of Shares Outstanding, Basic (1)
478
 487
Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust—
 1
Weighted Average Number of Shares Outstanding, Diluted478
 488
(Loss) Income Per Share, Basic$(0.65) $1.14
(Loss) Income Per Share, Diluted$(0.65) $1.14
Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above15
 16
Overall compliance with the Consent Decree has resulted in the temporary shut-in and permanent plugging and abandonment of certain wells and associated tank batteries. Consent Decree compliance could result in additional temporary shut-ins and permanent plugging and abandonment of certain wells and associated tank batteries. The Consent Decree sets forth a detailed compliance schedule with deadlines for achievement of milestones through early 2019 that may be extended depending on certain situations. The Consent Decree contains additional obligations for ongoing inspection and monitoring beyond that which is required under existing Colorado regulations.
We have concluded that the penalties, injunctive relief, and mitigation expenditures that resulted from this settlement did not have, and based on currently available information will not have, a material adverse effect on our financial position, results of operations or cash flows.
Colorado Water Quality Control Division Matter In January 2017, we received a Notice of Violation/Cease and Desist Order (NOV/CDO) advising us of alleged violations of the Colorado Water Quality Control Act (Act) and its implementing regulations as it relates to our Colorado Discharge Permit System General Permit for construction activities associated with oil and gas exploration and /or production within our Wells Ranch Drilling and Production field located in Weld County, Colorado (Permit).  The NOV/CDO further orders us to cease and desist from all violations of the Act, the regulations and the Permit and to undertake certain corrective actions.  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.
Colorado Oil and Gas Conservation Commission Administrative Order on Consent   In November 2017, we received a proposed Administrative Order on Consent (AOC) from the Colorado Oil and Gas Conservation Commission (COGCC) to resolve allegations of noncompliance associated with site preparation and stabilization at an oil and gas location in Weld County, Colorado. The AOC, which provides for an opportunity to further discuss the offer of settlement, has not yet been executed. 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.
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.
(1)
Decrease in weighted average number of shares outstanding reflects the impact of Noble Energy common stock repurchased in 2018 pursuant to our $750 million share repurchase program.

Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide a narrative about our business from the perspective of management. We use common industry terms, such as thousand barrels of oil equivalent per day (MBoe/d) and million cubic feet equivalent per day (MMcfe/d), to discuss production and sales volumes. Our MD&A is presented in the following major sections:
•
Executive Overview;
•
Operating Outlook;
•
Results of Operations – E&PExploration and Production;
•
Results of Operations – Midstream;
•
Results of Operations – Corporate; and
•
Liquidity and Capital Resources.

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

EXECUTIVE OVERVIEW
The following discussion highlights significant operating and financial results for secondfirst quarter 2018.2019. This discussion should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2017,2018, which includes disclosures regarding our critical accounting policies as part of “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Recent Achievements Operational Environment Update
Since 2015, weCommodity Prices Crude oil prices, although trending upward during first quarter 2019, did not reach comparable levels experienced in first quarter 2018, where Brent and WTI crude oil prices averaged in excess of $65 and $60 per barrel, respectively. The outlook for the remainder of 2019 will continue to depend on supply and demand dynamics, geopolitical and security factors in crude oil-producing nations and the spread between WTI and Brent prices, among other factors.
The US natural gas market remains oversupplied and prices have strategically repositioned our portfoliocontinued to focus capital investment primarily in US onshore plays, including the DJ and Delaware Basins and Eagle Ford Shale, and on our international offshore assetsbe depressed during first quarter 2019. We expect 2019 natural gas prices to be at or near 2018 trading levels.
In addition, price differentials, specifically in the Eastern MediterraneanDelaware Basin, have continued to widen for both crude oil and West Africa. The focus of our capital programsnatural gas due to takeaway capacity constraints. Infrastructure expansion in these areasthe Delaware Basin is expected to positively impactresult in price improvement later in 2019.
Table of Contents

We have entered into crude oil and natural gas price hedging arrangements to mitigate the effect of commodity price volatility and enhance the predictability of our cash flows.
Cost Environment While materials and services costs have begun shifting downward in response to fourth quarter 2018 oil prices and lower activity, pricing for oilfield equipment, services and infrastructure has yet to fully adjust to the current commodity price environment. Internal initiatives to improve capital efficiency have led to improved US onshore productivity, such as increasing completion stages per day which in turn reduces cycle times and lowers well completion costs. While we progress capital efficiency initiatives, we continue to work with our service providers to reduce cost structure.
Colorado Senate Bill 19-181 For some time, initiatives have been underway in the State of Colorado to limit or ban hydraulic fracturing statewide and other facets of crude oil and natural gas exploration, development or operations. During first quarter 2019, Senate Bill 19-181 (SB 181) was passed by the State Legislature. On April 16, 2019, the Governor signed the bill into law. The legislation makes changes in Colorado oil and gas law, including, among other matters, requiring the Colorado Oil and Gas Conservation Commission (Commission) to prioritize public health and environmental concerns in its decisions, instructing the Commission to adopt rules to minimize emissions of methane and other air contaminants, and delegating considerable new authority to local governments to regulate surface impacts. 
Most of our acreage in Colorado is in rural areas of Weld County, and we continue to work closely with local regulators and communities to ensure safe and responsible operations and future planning. At this time, we do not foresee significant changes to our development plans, as we have all necessary State approvals of more than 550 permits to drill wells over the next several years. The approved permits are for wells in multiple Integrated Development Plans (IDPs), many of which are in our Mustang Comprehensive Drilling Plan (CDP). We will continue to work closely with Weld County on the required local permits and agreements for the CDP.  However, if additional regulatory measures are adopted, we could incur additional costs to comply with the requirements or we may experience delays and/or curtailment in the permitting or pursuit of our exploration, development, or production activities. Such compliance costs and delays, curtailments, limitations, or prohibitions could have a material adverse effect on our cash flows, results of operations, financial condition, and margins. Going forward, we are concentrating our exploration capabilities on higher-impact opportunities that can drive substantial long-term value creation.liquidity.
Recent Activities 
During secondfirst quarter 2018,2019, we exited the Gulf of Mexico and continued to progress our US onshore drilling and completions activities, and advanced our Eastern Mediterranean and West Africa regional natural gas developments. Financially, we strengthened our balance sheet through reduction of debt.
Seconddevelopments, and engaged in new US onshore and international exploration opportunities. First quarter 2018 achievements include2019 activities included the following:
Sales Volumes We delivered quarterly sales volumes of 346337 MBoe/d, with approximately 56% of our production mix attributable to crude oil and NGLs. Reported volumes reflect the impact of adoption of ASC 606, Revenue from Contracts with Customers (ASC 606). See Results of Operations – Exploration and Production (E&P) – Results of Operations.
Gulf of Mexico AssetNon-Core Acreage Sale In second quarter 2018, we completed the sale of our Gulf of Mexico assets, including our interestsWe sold approximately 13,000 net acres in six producing fields and all undeveloped leases. We receivednon-core southwestern Reeves County, Texas, receiving cash consideration of $383 million, net of customary price adjustments. We recognized impairment expense of $168 million in first quarter 2018 and an additional loss of $19 million in second quarter 2018. See Item 1. Financial Statements – Note 3. Acquisitions and Divestitures.
Agreement to Progress Alen Natural Gas Development In May 2018, we announced the execution of a Heads of Agreement establishing the framework for development of natural gas from the Alen field, resulting in access to global liquefied natural gas (LNG) markets. Sanction of the project is contingent upon final commercial agreements being executed. See Exploration and Production (E&P) – Development Projects.
Strategic EPIC Pipeline Agreement During second quarter 2018, we finalized a strategic agreement with EPIC Pipeline, LP (EPIC) to transport crude oil from our Delaware Basin acreage position to Corpus Christi, Texas. We have secured firm capacity for 100 MBbl/d, gross, of crude oil for a 10-year period beginning at pipeline start-up. In addition, we secured options for ownership interests in EPIC's crude oil and NGL pipelines. See Exploration and Production (E&P) – Development Projects.
Table of Contents

Delaware Basin Firm Crude Oil Sales Agreement In June 2018, we supplemented our Delaware Basin takeaway position through the execution of a five-year agreement for firm gross sales of at least 10 MBbl/d of crude oil beginning in July 2018, increasing to 20 MBbl/d beginning in October 2018 and for the remainder of the agreement. See Exploration and Production (E&P) – Development Projects.
Hedging Activities We entered into additional strategic crude oil basis swap contracts for 2018-2020 in order to establish a fixed amount for the differential between pricing in Midland, Texas, and Cushing, Oklahoma, thus mitigating the price risk associated with our Delaware Basin production. See Item 1. Financial Statements – Note 4. Derivative Instruments and Hedging Activities.
CNX Midstream Partners Unit Sale During second quarter 2018, we sold 7.5 million CNX Midstream Partners common units, or approximately one-third of our investment, receiving net proceeds of approximately $135 million, net of underwriting fees. We continue to hold 14.2 million common units. See Item 1. Financial Statements – Note 3. Acquisitions and Divestitures.
Senior Note Redemption To further strengthen our balance sheet and reduce nearer-term maturities, we redeemed $379 million of Senior Notes due May 1, 2021, which had been assumed in the 2015 Rosetta Merger, in May 2018 for $395 million and recognized a gain of $5$131 million. See Item 1. Financial Statements – Note 5. Debt4. Acquisitions and Divestitures.
Leviathan Natural Gas Project We progressed the Leviathan natural gas project, offshore Israel, to 81% completion. See Results of Operations – Exploration and Production.
Share RepurchasesAlen Natural Gas Development On April 1, 2019, we announced sanction of the Alen natural gas development, offshore Equatorial Guinea. See Results of Operations – Exploration and Production.
US Onshore Exploration Opportunity We acquired additional US onshore undeveloped acreage. See Results of Operations – Exploration and Production.
Colombia Exploration Opportunity We finalized a strategic farmout arrangement for exploration acreage offshore Colombia. See Results of Operations – Exploration and Production.
EPIC Pipeline Investments Noble Midstream Partners exercised and closed options to acquire a 15% equity interest in EPIC Y-Grade, LP (EPIC Y-Grade) and a 30% equity interest in EPIC Crude Holdings, LP (EPIC Crude Holdings) and secured a $200 million preferred equity commitment from Global Infrastructure Partners Capital Solutions Fund (GIP), of which $100 million was funded during first quarter 2019. See Results of Operations – Midstream.
Financial Initiatives 
Commercial Paper Program In accordance with the $750 million share repurchasefirst quarter 2019, we established a commercial paper program, authorizedwhich allows for a maximum of $4.0 billion of unsecured commercial paper notes to provide for short-term funding needs. The commercial paper program is supported by our Board of Directors earlier this year, we repurchased and retired 1.8 million shares of common stock at an average purchase price of $35.15 per share during second quarter 2018.Noble Energy’s Revolving Credit Facility. See Item 1. Financial Statements – Note 7. Debt.
Financial Flexibility, Liquidity and Balance Sheet Strength As we progress through the remainder of 2018,2019, we believe we are positioned for sustainability, operational efficiency, and long-term success throughout the oil and gas business cycle. We remain committed to maintaining capital discipline and financial strength and will continuouslycontinue to evaluate the commodity prices, along withprice
Table of Contents

environment, well productivity and efficiency gains as we optimizein aligning our activity levels in alignment with commodity price conditions. To this end, our 20182019 capital investment program is responsive to positive or negative commodity price conditions that may develop. See Operating Outlook – 20182019 Capital Investment Program.
If commodity prices decline or operating costs begincontinue to rise, we could experience material asset impairments, as well as material negative impacts on our revenues, profitability, cash flows, liquidity and proved reserves, and, in response, we may consider reductionschanges in our capital program, share repurchase program or dividends, asset sales or operating cost structure. Our productionrevenues and our stock price could decline as a result of these potential developments.
Adoption of ASC 606
As of January 1, 2018, we adopted ASC 606, using the modified retrospective method. ASC 606 adoption did not have an impact on the opening balance of retained earnings, and resulted in de minimis increases of $2 million and $7 million to both revenues and expenses for the second quarter and the first six months of 2018, respectively. ASC 606 adoption did not affect operating or net income or operating cash flows. Comparative information for the prior periods has not been recast and continues to be reported under the accounting standards in effect for those periods. Adoption of the new standard did not impact our financial position and we do not expect that it will going forward. See Exploration and Production (E&P) – Results of Operations.
Recently Issued Accounting Standards
See Item 1. Financial Statements – Note 2. Basis of Presentation.
OPERATING OUTLOOK
2018 Production Our expected crude oil, natural gas and NGL sales forThe current commodity price environment, along with the remainder of 2018 may be impacted by several factors including:
commodity prices which, if subject to a significant decline, could result in certain existing production becoming uneconomic;
overall level and timing of our 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;
Table of Contents

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 participationdevelopment, Leviathan completion, and the Aseng development well, as well as Noble Midstream Partners' investments, is anticipated to result in future, or decline from existing, non-operated wells;
abandonmentcapital expenditures in excess of low-margin US onshore wells;
shut-incash flows in 2019. Although we did not repurchase any shares under our $750 million share repurchase program this quarter, we remain committed to shareholder return initiatives. For example, in April 2019, our Board of US producing properties if storage capacity becomes unavailable; and
potential drilling and/or completion permit delays dueDirectors announced a 9% increase in the quarterly cash dividend. This is our second straight year to future regulatory changes.increase our dividend, reflecting our commitment to return value to shareholders.
20182019 Capital Investment Program 
Our 20182019 organic capital investment program is designed to deliver near and long-term value and is flexible in the current commodity price environment. Excludingrange of $2.4 to $2.6 billion, with approximately 70% being allocated to US onshore development and approximately 20% to complete the Leviathan Phase 1 development project. The remaining portion of the organic capital program is designated for Noble retained midstream activities, drilling of the Aseng development well, and other exploration and corporate activities. Amounts exclude capital funded by Noble Midstream Partners our initial 2018and acquisition capital related to the EMG pipeline. See Results of Operations – Exploration and Production.
Our 2019 organic capital program accommodated an investmentanticipates a lower level of approximately $2.7investment directed to $2.9 billion and was contemplated using a West Texas Intermediate price assumption of $50 per barrel. We have revised our capital program to accommodate an investment level of approximately $3 billion, reflecting increased onshore facility spend from the first half of 2018 and inflation in the US onshore assets, as a result of the higher commodity price environment.
Approximately 95% of the capital program is being allocatedcompared with 2018. We will continue to advance our US onshore development, associatedprogram through investments in liquids-rich and high-return projects, improve execution efficiency, and enhance our midstream infrastructure and the Eastern Mediterranean. In addition, given industry constraints in the Permian Basin, we plan to reallocate some near-term investment to our other US onshore basins. This will ensure that we are optimizing our development plans and timing our Delaware Basin activity to benefit from necessary takeaway infrastructure planned for next year.business value.
The remaining portion of the capital program is designated for other activities, including lease acquisition, seismic and other geological analysis in support of future exploration prospects, as well as other corporate activities.
We will continue to evaluate the level of capital spending throughout the year based on the following factors, among others, and their effect on project financial returns: 
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.
year. See Liquidity and Capital Resources – Financing Activities.
Regulatory Update During the first six months of 2018, the US Administration imposed import tariffs of 25% on steel products and 10% on aluminum products, as well as quantitative restrictions on imports of steel and/or aluminum products from Argentina, Brazil, and South Korea (Australia has been exempted from the imposition of tariffs and implementation of quotas).  Key US trading partners have threatened to retaliate, or already have retaliated, against imports of US-origin goods and have initiated litigation at the World Trade Organization. The US oil and gas industry relies on steel for drilling and completion of new wells, as well as for facility production at refineries, petrochemical plants and pipelines. Much of the steel required is in the form of specialty steel products, manufactured to exact specifications, and may not be available domestically in sufficient quantities.
Table of Contents

Implementation of these tariffs will likely increase prices for specialty and other products used in various aspects of upstream, midstream and downstream activities. Furthermore, the tariffs and quantitative restrictions may cause disruption in the energy industry’s supply chain, resulting in delay or cessation of drilling efforts or postponement or cancellation of new inter- or intra-state pipeline projects, that the industry is relying on to transport its increasing onshore production to market, as well as endangering US LNG export projects resulting in negative impacts on natural gas production.
In addition, countries subject to the tariffs have threatened to retaliate with tariffs on American products, potentially resulting in escalating trade disputes with certain trade partners. Trade and/or tariff disputes could result in increased costs or shortages of materials and supplies the industry relies on to produce, process and transport its oil and gas production. Moreover, trade and/or tariff disputes, could have negative impacts on the US and global economies overall and could result in less demand for our products.
RESULTS OF OPERATIONS – EXPLORATION AND PRODUCTION (E&P)
We continue to advance our major development projects, which we expect to deliver incremental production and cash flows over the next several years.
Sanctioned Ongoing Development Projects
A "sanctioned"“sanctioned” development project is one for which a final investment decision has been reached. Updates on major development projects are as follows:
US Onshore
During first quarter 2019, our US onshore E&P activities consisted of the following:
LocationAverage Rigs Operated Wells Drilled and Completed Wells Brought Online 
Average Sales Volumes
 (MBoe/d)
DJ Basin2 29 21 144
Delaware Basin4 20 9 59
Eagle Ford Shale— 7 7 50
Total6 56 37 253
DJ Basin   (US Onshore)   During first quarter 2019, we achieved a quarterly average sales volume record of 144 MBoe/d. Our activities during second quarter 2018 were focused primarily in the Wells Ranch and East Pony integratedon progressing development plan (IDP) areas. During the quarter, we operated one to two drilling rigs, completed 31 wells and commenced production on 16 wells. Average sales volumes during second quarter 2018 were 121 MBoe/d, including 10 MBoe/d due to ASC 606 adoption. We have expanded drilling and completion activities intoin the Mustang IDP area, where we have a large contiguous acreage position, and added a drilling rig in this IDP during second quarter 2018. Our development plan in this area includes applying multiple techniqueswhich benefits from our other successful US onshore plays, including utilizing row development concepts, enhanced completion designs, capital-efficient facility designs,approved CDP, and other techniques to optimize project returns.we saw increased capital efficiencies as a result of improved drilling performance.
Delaware Basin (US Onshore) During secondfirst quarter 2018, we operated an average of six drilling rigs, completed 22 wells and commenced production on 23 wells, with the majority2019, much of our activity focused on row development with long laterals and multi-well pads targeting multiple zones within the basin. We averaged 47 MBoe/d of sales volumes during second quarter 2018, with approximately 70%northern portion of our production mix attributableacreage position. We are also focusing on completion operations to crude oil. During second quarter 2018, we commenced operations at two additional central gathering facilities (CGFs).
Also during second quarter 2018, we secured firm capacity with EPIC for transport of 100 MBbl/d, gross, of crude oil from the Delaware Basin to Corpus Christi, Texas, for a 10-year period beginning at pipeline start-up. We have dedicated substantially allbring online our Delaware Basin acreage position in Reeves County, Texas to the EPIC crude oil pipeline, which the operator anticipates will commence operations in the fourth quarter of 2019. This strategic agreement is expected to provide long-term flow assurance for our rapidly growing Delaware Basin crude oil volumes. With this agreement, we have further diversified our US onshore marketing outlets with access to the Texas Gulf Coast and global markets, at an attractive pipeline transport cost.
As part of the EPIC strategic relationship, we secured options to acquire up to 30% ownership interest in the company that owns the EPIC crude oil pipeline. In addition, Noble Midstream Partners secured an option to acquire up to 15% ownership interest in the company that owns the EPIC NGL pipeline. Both options expire in first quarter 2019.
In June 2018, we supplemented our Delaware Basin takeaway position with an additional firm sales agreement, which will result in our crude oil reaching the Gulf Coast. The five-year agreement provides for firm gross sales of at least 10 MBbl/d of crude oil beginning in July 2018, increasing to 20 MBbl/d beginning in October 2018 and for the remainder of the agreement. Crude oil sold under the agreement will initially utilize the buyer's existing firm transport capacity to Corpus Christi. Shortly following commencement of full service of the EPIC crude oil pipeline, it is anticipated that crude oil sales under the agreement will be transported by way of our firm transportation capacity. We previously executed firm sales agreements to the Texas Gulf Coast or Cushing, Oklahoma markets for Delaware Basin crude oil covering gross oil volumes of 10 MBbl/d for the second half of 2018 and 5 MBbl/d for 2019.
Eagle Ford Shale (US Onshore) During second quarter 2018, we operated an average of one drilling rig, completed four wells and commenced production on nine wells, primarily focused within the Upper and Lower Eagle Ford formation zones. In addition, we commenced construction of a central gathering and production facility in the northern area of Gates Ranch. This facility will provide separation and compression capabilities for our upcoming multi-well completion program expected to begin later in 2018. We continue to execute our development plan and averaged sales volumes of 76 MBoe/d during second quarter 2018.drilled but uncompleted wells.
Table of Contents

Tamar Natural Gas Project (Eastern Mediterranean)Eagle Ford Shale In secondDuring first quarter 2018, offshore Israel sales volumes averaged 227 MMcfe/d, net, and2019, we focused on a gross basis, sales volumes reached a cumulative milestone delivering 1.6 Tcf of natural gas to-date. Second quarter gross sales volumes established a quarterly production record of more than 1 Bcf/d, driven by continued coal displacementwell completion activities in power generation and warm seasonal weather.North Gates Ranch.
International
Leviathan Natural Gas Project (Eastern Mediterranean)(Offshore Israel) 2018 represents the peak year for capital investments for the initial phase of Leviathan development, offshore Israel. The project is now nearly 60%81% complete and remains on budget and on schedule. We have commenced constructioninstalled the in-field gathering and pipelines, completed installation of all subsea trees, finished completions on all four wells with successful flowbacks, completed the float of the onshore pipeline,main decks, finished flowline installation, completed drillingjacket and piles installation and commenced yard commissioning of Leviathan 3 and 7 wells, and began completion operations at the Leviathan 4 well. First natural gas sales areplatform modules. Project start-up is anticipated by the end of 2019.
Unsanctioned Development Projects
West AfricaLeviathan and Tamar Natural Gas MonetizationTransportation Agreements (Offshore Israel) We continue efforts to monetizework with our significant natural gas discoveriespartners toward the acquisition of a 39% equity interest in Eastern Mediterranean Gas Company S.A.E., which owns the EMG Pipeline. We will own an effective, indirect interest of approximately 10%, net, in the pipeline. The EMG Pipeline is an approximately 90-kilometer pipeline located primarily offshore, West Africa. A natural gasconnecting the Israel pipeline network from Ashkelon, Israel to the Egyptian pipeline network.
Closing of the agreement to exclusively operate the EMG Pipeline and secure access to its full capacity is subject to fulfillment of certain conditions precedent, which is expected to occur mid-year 2019. The estimated acquisition cost for our interest in the pipeline is approximately $200 million.
Tamar Natural Gas Project (Offshore Israel) In January 2019, the Petroleum Commissioner of Israel approved the development team has been working with local governmentsplan for our 2013 Tamar Southwest discovery, which includes tie-back to evaluate natural gas monetization conceptsthe existing Tamar platform, thus reinforcing the reliable operation of the Tamar project and progress negotiations of required contracts. In May 2018,supporting increased customer demand.
Aseng Development Well (Offshore Equatorial Guinea) During first quarter 2019, we awarded contracts and acquired equipment for a new development well expected to mitigate Aseng field decline. Production is expected to come online in late third quarter to early fourth quarter 2019.
Alen Natural Gas Development (Offshore Equatorial Guinea)   On April 1, 2019, we announced the execution, along withsanction of the GovernmentAlen natural gas development. Natural gas from the Alen field will be processed through the existing Alba Plant LLC liquefied petroleum gas (LPG) processing plant (Alba Plant) and Equatorial Guinea's liquefied natural gas (LNG) production facility (EG LNG) located at Punta Europa, Bioko Island. Definitive agreements in support of the project have been executed between the Alen field partners, the Alba Plant and EG LNG plant owners, as well as the government of the Republic of Equatorial GuineaGuinea.
The Alen natural gas monetization project will utilize three existing high-capacity Alen production wells. Minor platform modifications will be made to deliver sales gas from Alen to the Alba Plant and necessary third-parties,EG LNG facilities. A 24-inch pipeline capable of a Headshandling 950 MMcfe/d will be constructed to transport all natural gas processed through the Alen platform approximately 70 kilometers to the onshore facilities. First production is anticipated in the first half of Agreement establishing the framework for development of2021. At start-up, natural gas sales from the Alen field. The agreement outlines the high-level commercial terms for Alen natural gasfield are anticipated to be processedbetween 200 and 300 MMcfe/d, gross (approximately 75 to 115 MMcfe/d, net). The wet gas stream will be tolled through the Alba Plant LLC’s liquefied petroleumfor additional liquids recovery before the dry gas (LPG) plant and Equatorial Guineais converted into LNG Holdings Limited’s LNG plant. Both plants are located in Punta Europa. The contemplated structure would result in Alen gas being marketed to global LNG markets. Sanction of the project is contingent upon final commercial agreements being executed.
Existing production and processing facilities in place at the Alen platform and in Punta Europa require certain modifications to produce and process the Alen natural gas. The agreement contemplates construction of a 65-kilometer pipeline to transport natural gas from the Alen platform to the facilities in Punta Europa.EG LNG facility.
Unsanctioned Projects
Cyprus Natural Gas Project (Offshore Cyprus) We continue to work with the Government of Cyprus on a plan of development for the Aphrodite field that, as currently planned,contemplated, would deliver natural gas to regional customers. In addition, we are focused on capital cost improvements, as well as natural gas marketing efforts and execution of natural gas sales and purchase agreements, which, once secured, will progress the project to a final investment decision.
Exploration Program Update
We continue to seek and evaluate significant onshore and/or offshore opportunities for future exploration. Through our drilling activities, we do not always encounter hydrocarbons. In addition,hydrocarbons or we may find hydrocarbons but subsequently reach a decision, through additional analysis or appraisal drilling, that a development project is not economically or operationally viable. In the event we conclude that one of our exploratory wells did not encounter hydrocarbons or that a discovery is not economically or operationally viable, the associated capitalized exploratory well costs will be recorded as dry hole expense.
Additionally, we may not be able to conduct exploration activities prior to lease expirations. As a result,expirations or may choose to relinquish or exit licenses. Exploration opportunities in a future period could result in significant dry hole cost and/or leasehold abandonment expense could be significant.expense. See Item 1. Financial Statements – Note 7.5. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
US Onshore Acreage In first quarter 2019, we acquired additional undeveloped acreage increasing our US onshore unconventional exploration position to more than 140,000 acres residing in two plays in Wyoming.
Offshore Colombia During first quarter 2019, we signed an agreement, pending customary approvals, for a 40% operated working interest in more than 2 million gross acres offshore Colombia, located on two offshore blocks. We expect to drill an exploration well in 2020.
Table of Contents

Results of Operations
Highlights for our E&P business were as follows:
SecondFirst Quarter 2018 Significant2019 E&P Operating Highlights Included:
total average dailyconsolidated sales volumes of 346332 MBoe/d, net;
record average daily sales volumes for US onshore crude oil of 105 MBbl/d, net;
record average daily sales volumes of over 1 Bcf/113 MBbl/d, net, for US crude oil; and
average daily sales volumes of 1.1 Bcfe/d, gross, infor offshore Israel natural gas, primarily from the Tamar field;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.
SecondFirst Quarter 20182019 E&P Financial Results Included:
net cash proceeds of $383 million, after closing adjustments, received from the Gulf of Mexico asset sale;
total loss of $249 million on commodity derivative instruments;instruments of $212 million (which is net of cash settlement receipts of $14 million), as compared with a net loss of $79 million for first quarter 2018;
pre-tax incomeloss of $7$168 million, as compared with pre-tax lossincome of $2.1 billion$485 million for secondfirst quarter 2017;2018; and
capital expenditures, excluding acquisitions, of $787$648 million, as compared with $613$667 million for secondfirst quarter 2017.2018.

The following is a summarized statement of operations for our E&P business:
 Three Months Ended March 31,
(millions)2019 2018
Oil, NGL and Gas Sales to Third Parties$937
 $1,173
Sales of Purchased Oil and Gas14
 —
Income from Equity Method Investees15
 35
Total Revenues966
 1,208
Production Expense351
 353
Exploration Expense24
 35
Depreciation, Depletion and Amortization475
 443
Gain on Divestitures, Net—
 (392)
Asset Impairments—
 168
Cost of Purchased Oil and Gas14
 —
Loss on Commodity Derivative Instruments212
 79
(Loss) Income Before Income Taxes$(168) $485

Table of Contents

Following is a summarized statement of operations for our E&P business:
Average Oil, NGL and Gas Sales Volumes and PricesAverage daily sales volumes and realized sales prices were as follows:
 Three Months Ended June 30, Six Months Ended June 30,
(millions)2018 2017 2018 2017
Oil, NGL and Gas Sales to Third Parties (1)
$1,100
 $1,017
 $2,273
 $2,011
Sales of Purchased Gas (2)
24
 —
 55
 —
Income from Equity Method Investees36
 25
 71
 52
Total Revenues1,160
 1,042
 2,399
 2,063
Production Expense (1)
329
 309
 681
 627
Exploration Expense29
 30
 64
 72
Depreciation, Depletion and Amortization435
 486
 880
 999
Purchases 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
 —
 94
Income (Loss) Before Income Taxes7
 (2,145) 493
 (1,917)
 
Average Sales Volumes (1)
 
Average Realized Sales Prices (1)
 
Crude Oil & Condensate
(MBbl/d)
 
NGLs
(MBbl/d)
 
Natural Gas
(MMcf/d)
 
Total
(MBoe/d)
 
Crude Oil & Condensate
(Per Bbl)
 
NGLs
(Per Bbl)
 
Natural Gas
(Per Mcf)
Three Months Ended March 31, 2019
United States113
 59
 483
 253
 $53.46
 $17.86
 $2.49
Eastern Mediterranean—
 —
 233
 39
 —
 —
 5.57
West Africa (2)
12
 —
 168
 40
 61.01
 —
 0.27
Total Consolidated Operations (3)
126
 59
 884
 332
 54.19
 17.86
 2.88
Equity Investees (4)
1
 4
 —
 5
 53.01
 36.81
 —
Total (3)
127
 63
 884
 337
 $54.18
 $19.09
 $2.88
Three Months Ended March 31, 2018
United States (5)
122
 64
 504
 270
 $61.95
 $25.53
 $2.63
Eastern Mediterranean—
 —
 261
 44
 —
 —
 5.48
West Africa (2)
15
 —
 206
 49
 68.14
 —
 0.27
Total Consolidated Operations137
 64
 971
 363
 62.60
 25.53
 2.90
Equity Investees (4)
2
 5
 —
 7
 66.08
 39.90
 —
Total139
 69
 971
 370
 $62.64
 $26.62
 $2.90
(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 million and $7 million for 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. See Item 1. Financial Statements - Note3. Acquisitions and Divestitures.

Table of Contents

Oil, NGL and Gas Sales
Average daily sales volumes and average realized sales prices, which exclude gains and losses related to commodity derivative instruments, were as follows:
 
Sales Volumes (1)
 
Average Realized Sales Prices (1)
 
Crude Oil & Condensate
(MBbl/d)
 
NGLs
(MBbl/d)
 
Natural
Gas
(MMcf/d)
 
Total
(MBoe/d) (2)
 
Crude Oil & Condensate
(Per Bbl)
 
NGLs
(Per Bbl)
 
Natural
Gas
(Per Mcf)
Three Months Ended June 30, 2018
United States (3)
108
 62
 467
 247
 $64.67
 $24.46
 $2.29
Eastern Mediterranean—
 —
 225
 38
 —
 —
 5.46
West Africa (4)
17
 —
 225
 54
 72.79
 —
 0.27
Total Consolidated Operations125
 62
 917
 339
 65.77
 24.46
 2.57
Equity Investees (5)
2
 5
 —
 7
 76.07
 43.36
 —
Total127
 67
 917
 346
 $65.93
 $25.90
 $2.57
Three Months Ended June 30, 2017
United States110
 63
 736
 296
 $45.78
 $18.79
 $3.20
Eastern Mediterranean—
 —
 272
 46
 —
 —
 5.34
West Africa (4)
22
 —
 231
 60
 49.53
 —
 0.27
Total Consolidated Operations132
 63
 1,239
 402
 46.40
 18.79
 3.13
Equity Investees (5)
2
 4
 —
 6
 50.93
 34.46
 —
Total134
 67
 1,239
 408
 $46.49
 $19.84
 $3.13
Six Months Ended June 30, 2018
United States (3)
115
 63
 486
 259
 $63.23
 $25.00
 $2.47
Eastern Mediterranean—
 —
 243
 41
 —
 —
 5.47
West Africa (4)
16
 —
 215
 51
 70.65
 —
 0.27
Total Consolidated Operations131
 63
 944
 351
 64.13
 25.00
 2.74
Equity Investees (5)
2
 5
 —
 7
 71.56
 41.61
 —
Total133
 68
 944
 358
 $64.22
 $26.27
 $2.74
Six Months Ended June 30, 2017
United States105
 56
 733
 283
 $47.31
 $21.04
 $3.32
Eastern Mediterranean—
 —
 272
 46
 —
 —
 5.33
West Africa (4)
20
 —
 237
 59
 51.28
 —
 0.27
Total Consolidated Operations125
 56
 1,242
 388
 47.95
 21.04
 3.18
Equity Investees (5)
2
 5
 —
 7
 51.71
 35.38
 —
Total127
 61
 1,242
 395
 $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 million and $9 million for second quarter 2018 and the first six months of 2018, respectively;
◦decreases in natural gas revenues, and corresponding decreases in production expense, of $2 million for 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.
Table of Contents

(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. See Item Financial Statements – Note 3. Acquisitions and Divestitures.
(4)(2) 
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.method.
(5)(3)
Total includes a small amount of condensate sales from the offshore Israel assets.
(4) 
Volumes represent sales of condensate and LPG from the LPG plant in Equatorial Guinea. See Income from Equity Method Investees,Investees.
(5)
Includes 24 MBoe/d related to Gulf of Mexico assets sold in second quarter 2018. See Item 1. Financial Statements – Note 4. Acquisitions and Divestitures below..
An analysis of revenues from sales of crude oil, NGLs and natural gas and NGLs is as follows:
 Sales Revenues
(millions)Crude Oil & Condensate NGLs 
Natural
Gas
 Total
Three Months Ended June 30, 2017$557
 $108
 $352
 $1,017
Changes due to       
Decrease in Sales Volumes(31) (10) (107) (148)
Increase (Decrease) in Sales Prices (1)
223
 35
 (29) 229
Impact of ASC 606 Adoption—
 4
 (2) 2
Three Months Ended June 30, 2018$749
 $137
 $214
 $1,100
        
Six Months Ended June 30, 2017$1,084
 $213
 $714
 $2,011
Changes due to       
Increase (Decrease) in Sales Volumes49
 1
 (192) (142)
Increase (Decrease) in Sales Prices (1)
389
 60
 (52) 397
Impact of ASC 606 Adoption—
 9
 (2) 7
Six Months Ended June 30, 2018$1,522
 $283
 $468
 $2,273
(millions)Crude Oil & Condensate NGLs Natural Gas Total
Three Months Ended March 31, 2018$773
 $146
 $254
 $1,173
Changes due to       
Decrease in Sales Volumes(77) (7) (27) (111)
(Decrease) Increase in Sales Prices (1)
(84) (43) 2
 (125)
Three Months Ended March 31, 2019$612
 $96
 $229
 $937
(1) Changes exclude gains and losses related to commodity derivate instruments.
(1)
Changes exclude gains and losses related to commodity derivative instruments. See Item 1. Financial Statements – Note 12. Derivative Instruments and Hedging Activities.
Crude Oil and Condensate Sales Revenues Revenues from crude oil and condensate sales increased seconddecreased in first quarter and the first six months of 20182019 as compared with 20172018 due to the following:    
increases of 42% and 34% for second quarter and the first six months of 2018, respectively,
•
decrease of 12% in average realized prices (see Executive Overview – Operational Environment Update – Commodity Prices);
reduction of 19 MBbl/d due to the partial rebalancingsale of global supplyour Gulf of Mexico assets in second quarter 2018; and demand factors;
lower West Africa sales volumes of 3 MBbl/d due to timing of liftings and natural field decline;
partially offset by:
higher US onshore sales volumes of 1710 MBbl/d and 22 MBbl/d for second quarter and the first six months of 2018, respectively, primarily driven bydue to an increase in development activity in the Delaware Basin and DJ Basin and the Clayton Williams Energy acquisition;
partially offset by:
lower Gulf of Mexico sales volumes of 19 MBbl/d and 12 MBbl/d for 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; and
lower offshore Equatorial Guinea sales volumes of 5 MBbl/d and 4 MBbl/d for second quarter and the first six months of 2018, respectively, due to natural field decline.Basins.
NGL Sales Revenues Revenues from NGL sales increased seconddecreased in first quarter and the first six months of 20182019 as compared with 20172018 due to the following:
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 million and $9 million for second quarter and the first six months of 2018, respectively, associated with the adoption of ASC 606;
partially offset by:
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.

•
decrease of 30% in average realized prices (see Executive Overview – Operational Environment Update – Commodity Prices); and
lower Eagle Ford Shale sales volumes of 15 MBbl/d due to reduced activity and natural field decline;
partially offset by:
higher sales volumes in the DJ and Delaware Basins of 12 MBbl/d due to an increase in development activities.
Natural Gas Sales Revenues Revenues from natural gas sales decreased secondin first quarter and the first six months of 20182019 as compared with 20172018 due to the following:
lower Eagle Ford Shale sales volumes of 33180 MMcf/d due to reduced activity and 350natural field decline;
lower Alba field sales volumes of 38 MMcf/d for second quarter and the first six months of 2018, respectively, due to natural field decline and planned maintenance at the divestitureonshore facilities, which required field shut-in for a portion of the Marcellus Shale upstream assets in second quarter 2017;period;
lower Israel sales volumes in Israelof 28 MMcf/d primarily due to the sale of a 7.5% interest in the Tamar field;field in March 2018;
lower Gulfreduction of Mexico sales volume of 1422 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 asresulting from 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;assets; 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;
•
continued oversupply and reduced take away capacity in the Delaware Basin, resulting in high differentials which depressed our sales prices for the area (see Executive Overview – Operational Environment Update – Commodity Prices);
partially offset by:
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 areaDelaware Basins of Gates Ranch in the Eagle Ford Shale; and
higher sales volumes in Israel81 MMcf/d due to increased demand.an increase in development activities.
Sales and Cost of Purchased Oil and Gas, NetBeginning in first quarter 2018, we entered into purchase transactions and separate sale transactions withIn first quarter 2019, we engaged in third parties at prevailing market prices to mitigate unutilized pipeline transportation commitments, primarily related to retained Marcellus Shale natural gas firm transportation agreements. Revenues and expenses from theparty 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. Transportation costs incurred related to utilization of the retained Marcellus Shale firm transportation agreements are recorded within purchases ofoil and gas in our consolidated statements of operations. For second quarter and the first six months of 2018, the net effect of third party purchases and sales of natural gas were losses of $7 million and $12 million, respectively.DJ Basin.
Income from Equity Method Investees  Equity method investments are included in other noncurrent assets in our consolidated balance sheets, and our share of earnings is reported as income from equity method investees in our consolidated statements of operations. Within our consolidated statements of cash flows, activity is reflected within cash flows provided by operating activities and cash flows provided by (used in) investing activities.
Income from equity method investees increased during thedecreased in first six months of 2018quarter 2019 as compared with 2017.2018. The increasedecrease includes a $6$10 million increasedecrease from Atlantic Methanol Production Company, LLC (AMPCO), our methanol investee, and a $12$10 million increasedecrease from Alba Plant, our LPG investee, all primarily driven by rising commodity prices.

Production Expense   Components of production expense from our E&P operations were as follows:
(millions, except unit rate)
Total per BOE (1) (2)
 Total 
United
States (2)
 Eastern
Mediter- ranean		 West Africa
Total per BOE (1)(2)
 Total 
United States (2)
 Eastern Mediterranean West Africa
Three Months Ended June 30, 2018         
Three Months Ended March 31, 2019         
Lease Operating Expense (3)
$5.32
 $159
 $125
 $10
 $24
Production and Ad Valorem Taxes1.57
 47
 47
 —
 —
Gathering, Transportation and Processing4.75
 142
 142
 —
 —
Other Royalty Expense0.10
 3
 3
 —
 —
Total Production Expense$11.74
 $351
 $317
 $10
 $24
Total Production Expense per BOE  $11.74
 $13.91
 $2.84
 $6.67
Three Months Ended March 31, 2018 
  
  
  
  
Lease Operating Expense (3)
$4.47
 $138
 $114
 $5
 $19
$4.75
 $155
 $126
 $7
 $22
Production and Ad Valorem Taxes1.56
 48
 48
 —
 —
1.62
 53
 53
 —
 —
Gathering, Transportation and Processing (4)
4.31
 133
 133
 —
 —
3.92
 128
 128
 —
 —
Other Royalty Expense0.33
 10
 10
 —
 —
0.52
 17
 17
 —
 —
Total Production Expense$10.67
 $329
 $305
 $5
 $19
$10.81
 $353
 $324
 $7
 $22
Total Production Expense per BOE  $10.67
 $13.55
 $1.47
 $3.84
  $10.81
 $13.31
 $1.79
 $5.01
Three Months Ended June 30, 2017 
  
  
  
  
Lease Operating Expense (3)
$3.54
 $129
 $105
 $6
 $18
Production and Ad Valorem Taxes0.89
 32
 32
 —
 —
Gathering, Transportation and Processing (4)
3.89
 142
 142
 —
 —
Other Royalty Expense0.16
 6
 6
 —
 —
Total Production Expense$8.48
 $309
 $285
 $6
 $18
Total Production Expense per BOE  $8.48
 $10.60
 $1.46
 $3.28
Six Months Ended June 30, 2018         
Lease Operating Expense (3)
$4.62
 $293
 $240
 $12
 $41
Production and Ad Valorem Taxes1.59
 101
 101
 —
 —
Gathering, Transportation and Processing (4)
4.10
 260
 260
 —
 —
Other Royalty Expense0.43
 27
 27
 —
 —
Total Production Expense$10.74
 $681
 $628
 $12
 $41
Total Production Expense per BOE  $10.74
 $13.42
 $1.64
 $4.39
Six Months Ended June 30, 2017 
  
  
  
  
Lease Operating Expense (3)
$3.78
 $265
 $211
 $14
 $40
Production and Ad Valorem Taxes1.03
 72
 72
 —
 —
Gathering, Transportation and Processing (4)
3.99
 280
 280
 —
 —
Other Royalty Expense0.14
 10
 10
 —
 —
Total Production Expense$8.94
 $627
 $573
 $14
 $40
Total 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&PUS production expense includes charges from our midstream operations that are eliminated on a consolidated basis. See Item 1. Financial Statements – Note 11. 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
Production expense 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 million and $7 million to gathering, transportation and processing expense related to US operations for second 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 the second 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.
For second quarter and the first six months of 2018, total production expense increased2019 remained relatively flat as compared with 20172018, primarily due to the following:
an increasedecrease of $25 million in lease operating expense and $6 million in gathering, transportation and processing (GTP) expense due to the sale of our Gulf of Mexico assets;
decrease in US production and ad valorem taxes and other royalty expense due to lower commodity prices;
partially offset by:
increase of $24 million in lease operating expense and $20 million in GTP expense, primarily due to increased development activities resulting in added production in across each of our onshore US basins;DJ and Delaware Basins; and
an increase in US production and ad valorem taxesWest Africa lease operating expense due to higher commodity prices;timing of planned maintenance activities.
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

an increase in US other royalty expense due toThe unit rate per BOE increased commodity market prices;
partially offset by:
a decrease infor 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.
Production expense on a per BOE basis increased for the second quarter and the first six months of 2018,2019 as compared with 2017 primarily2018, due to the decrease in total sales volumes driven byresulting from the divestituresales of the Marcellus Shale upstreamGulf of Mexico assets in second quarter 2017,2018 and the 7.5% interest in Tamar in March 2018, coupled with an increase in certain production expenses noted above. Specifically, the divestiture of the Marcellus Shale upstreamGulf of Mexico assets removed lower-cost, natural gas-focused sales volumes from our portfolio, while an increase in volumes from the Delaware Basin and Eagle Ford Shale contributed higher-cost, crude oil-focused sales volumes, thereby increasingwhich partially offset the increase in our average production expense per BOE.
Exploration Expense Exploration expense for the first six monthsquarter 2019 totaled $24 million, including $12 million of staff expense. Exploration expense for first quarter 2018 totaled $64$35 million, including $24$13 million of lease rental expense, primarily in the Delaware Basin, and $27$22 million of staff expense.
Exploration expense for the first six months of 2017 totaled $72 million, including $18 million of undeveloped leasehold impairment expense related to the impairment of leases in deepwater Gulf of Mexico and $29 million of staff expense.other.
Depreciation, Depletion and Amortization (DD&A) Expense DD&A expense for our E&P operations was as follows:
(millions, except unit rate)Total United States Eastern Mediterranean West Africa
Three Months Ended March 31, 2019       
DD&A Expense$475
 $439
 $16
 $20
Unit Rate per BOE (1)
$15.89
 $19.27
 $4.55
 $5.56
Three Months Ended March 31, 2018       
DD&A Expense$443
 $404
 $13
 $26
Unit Rate per BOE (1)
$13.57
 $16.60
 $3.32
 $5.92
(millions, except unit rate)Total United
States		 Eastern
Mediter- ranean		 
West
Africa
 Other Int'l
Three Months Ended June 30, 2018         
DD&A Expense$435
 $394
 $15
 $26
 $—
Unit Rate per BOE (1)
$14.10
 $17.51
 $4.41
 $5.25
 $—
Three Months Ended June 30, 2017         
DD&A Expense$486
 $427
 $19
 $39
 $1
Unit Rate per BOE (1)
$13.32
 $15.89
 $4.62
 $7.11
 $—
Six Months Ended June 30, 2018         
DD&A Expense$880
 $800
 $28
 $52
 $—
Unit Rate per BOE (1)
$13.87
 $17.10
 $3.82
 $5.56
 $—
Six Months Ended June 30, 2017         
DD&A Expense$999
 $886
 $37
 $74
 $2
Unit Rate per BOE (1)
$14.25
 $17.32
 $4.52
 $6.88
 $—

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

Total DD&A expense for secondfirst quarter and the first six months of 2018 decreased2019 increased 7% as compared with 20172018, primarily due to the following:
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 a 7.5% 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;
partially offset by:
higher sales volumes in the DJ and Delaware Basin, which more than doubled,Basins due to increasedrecent development activities subsequentactivities; and
increase in Eastern Mediterranean due to the Clayton Williams Energy Acquisitionimpact of the sale of our 7.5% interest in Tamar;
partially offset by:
decrease of $27 million resulting from the sale of our Gulf of Mexico assets in second quarter 2017;
increased development activities in the southern area of Gates Ranch in the Eagle Ford Shale;2018; and
higherdecrease in West Africa due to reduced sales volumes from the Tamar field, offshore Israel, due to higher domestic demand.as noted above.
The unit rate per BOE for secondfirst quarter 2018,2019 increased 17% as compared with 2017, increased2018, primarily due to the increase in total DD&A expense resulting from increased development activity and capital program in the DJ and Delaware BasinBasins, resulting in a higher depletable basis.basis, combined with the sale of lower-cost Tamar reserves. The unit rate per BOE for the first six months of 2018, as compared with 2017, decreased due toincrease is partially offset by the sale of higher-cost production from the Gulf of Mexico assets. This decrease is partially offset by the sale of lower-cost production from the sale of 7.5% Tamar interestassets in second quarter 2018 and the sale of the Marcellus Shale upstream assetsa reduction in 2017. In addition, an increaserate in reserves as of December 31, 2017 in Equatorial Guinea also contributed to a decline in unit rate per BOE.
Other Operating Expense, Net See Item 1. Financial Statements – Note 2. Basis of Presentation and Item 1. Financial Statements – Note 11. Segment Information for discussion of other operating expense items for second quarter and the first six months of 2018 as compared with 2017.West Africa driven by lower sales volumes.
Loss (Gain) on Commodity Derivative Instruments  Loss (gain) on commodity derivative instruments includes (i) cash settlements (received) or paid relating to our crude oil and natural gas commodity derivative contracts; and (ii) non-cash (increases) or decreases in the fair values of our crude oil and natural gas commodity derivative contracts.for first quarter 2019 increased, as compared with 2018.
For the first six months of 2018,quarter 2019, loss on commodity derivative instruments included:
net cash settlement paymentreceipts of $93$14 million; and
net non-cash increasedecrease of $235$226 million in the fair value of our net commodity derivative liability, primarily driven by increaseschanges in the forward commodity price curve for both crude oil.oil and natural gas.     
For the first six months of 2017, gainquarter 2018, loss on commodity derivative instruments included:
net cash settlement receiptpayments of $14$28 million; and
net non-cash increase of $153$51 million in the fair value of our net commodity derivative asset,liability, primarily driven by changes in the forward commodity price curves for both crude oil and natural gas.
See Item 1. Financial Statements – Note 4.12. Derivative Instruments and Hedging Activities andNote 6. Fair Value Measurements and Disclosures.Activities.
RESULTS OF OPERATIONS – MIDSTREAM
The Midstream segment develops, owns operates, develops and acquiresoperates domestic midstream infrastructure assets, as well as invests in other financially attractive midstream projects, with current focus areas beingin the DJ and Delaware Basins.
Results of Operations
Highlights for our Midstream segment were as follows:
Second Quarter 2018 Significant Midstream Operating Highlights Included:
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;

securedRecent Transactions
EPIC Pipelines In first quarter 2019, Noble Midstream Partners exercised and closed its options to acquire equity interests in EPIC Y-Grade and EPIC Crude Holdings. The assets provide attractive economics and long-term dedications,growth potential for Noble Midstream Partners and will provide near-term flow assurance and long-term out-of-basin takeaway capacity for our E&P volumes. The EPIC crude oil pipeline will provide Noble Energy with firm transport of up to 100 MBbl/d from existing and newthe Delaware Basin to Corpus Christi, Texas. In-service is expected in first quarter 2020; however, EPIC announced it will provide early access to crude oil transportation through the EPIC Y-grade pipeline in third party customers, forquarter 2019. The EPIC Y-Grade pipeline, also running from the Black Diamond system,Delaware Basin to Corpus Christi, Texas, will have an NGL throughput capacity of approximately 440 MBbl/d with multiple origin points. 
Delaware Crossing Joint Venture In February 2019, Noble Midstream Partners executed definitive agreements with Salt Creek Midstream LLC (Salt Creek) to form a large, integrated gathering50/50 joint venture, Delaware Crossing LLC (Delaware Crossing), to construct a 160 MBbl/d day crude oil pipeline system in the DJ Basin acquiredDelaware Basin. The 95-mile pipeline system will originate in the Saddle Butte acquisition;Pecos County, Texas, with additional connections in Reeves and
received Winkler Counties, Texas. The project footprint will be served by a third party producer's activity setcombination of in-field crude oil gathering lines and development plan for Delaware Basin acreage, witha trunkline to a hub in Wink, Texas. The project is underpinned by approximately 192,000 dedicated gross acres and nearly 100 miles of gathering servicespipeline in Pecos, Reeves, Ward and Winkler Counties, Texas. The pipeline is expected to commencebe operational in late 2018.third quarter 2019.
SecondResults of Operations
First Quarter 20182019 Significant Midstream Operating Highlights and Financial Results Included:
net proceedstotal revenues of approximately $135$165 million, received, and gain of $109as compared with $128 million recognized, on the sale of a portion of our investment in CNX Midstream Partners common units;for first quarter 2018;
pre-tax income of $175$73 million, as compared with pre-tax income of $58$247 million for secondfirst quarter 2017; and2018;
capital expenditures, excluding acquisitions, of $157$66 million, as compared with $88$253 million for secondfirst quarter 2017.2018; and
investments in equity method investees of $271 million, primarily related to investments in EPIC Y-Grade and EPIC Crude Holdings, as compared with zero for first quarter 2018.

FollowingThe following is a summarized statement of operations for our Midstream segment:
Three Months Ended June 30, Six Months Ended June 30,Three Months Ended March 31,
(millions)2018 2017 2018 20172019 2018
Midstream Services Revenues – Third Party$15
 $4
 $28
 $4
$24
 $13
Sales of Purchased Oil42
 —
 64
 —
33
 22
Income from Equity Method Investees13
 13
 25
 28
2
 12
Intersegment Revenues85
 69
 166
 127
106
 81
Total Revenues155
 86
 283
 159
165
 128
Operating Costs and Expenses27
 23
 61
 42
36
 39
Depreciation and Amortization22
 5
 38
 10
Gain on Divestitures(109) —
 (305) —
Purchased Oil40
 —
 61
 —
Total (Income) Expense(20) 28
 (145) 52
Depreciation, Depletion and Amortization25
 17
Gain on Divestitures, Net—
 (196)
Cost of Purchased Oil31
 21
Total Expense (Income)92
 (119)
Income Before Income Taxes$175
 $58
 $428
 $107
$73
 $247
Revenues The amount of revenue generated by the midstream businessMidstream segment depends primarily on the volumes of crude oil, natural gas and water for which services are provided to thededicated acreage for our E&P business and third partyto third-party customers. These volumes are primarily affected by the level of drilling and completion activity in the areas of E&P operations and by changes in the supply of, and demand for, crude oil, NGLs and natural gas and NGLs in the markets served directly or indirectly by our midstream assets.
Total revenues for secondfirst quarter and the first six months of2019 increased as compared with 2018, increased from 2017 primarily due to an increaseincreases in crude oil, natural gas and produced water gathering services revenue and fresh water delivery revenuedelivery. This increase was due primarily to thean increase in Delaware Basin throughput volumes, commencement of services in the Greeley CrescentMustang IDP areain 2018, and Delaware Basin subsequent to second quarter 2017. In addition, fresh water delivery revenue increased dueservices related to the timing of well completion activityBlack Diamond system, which was acquired during first quarter 2018 in the Mustang IDP area, and salesSaddle Butte Acquisition.
Sales of purchased crude oil commenced in firstalso increased due to a full quarter 2018 as a result of the Saddle Butte acquisition.
As part of the Saddle Butte acquisition in first quarter 2018, we acquired a large-scale integrated gathering system (Black Diamond gathering system) 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 transferredservices related to the customer. The purchases and sales of crude oil are at the prevailing market prices. For second quarter and the first six months of 2018, the net effect of third party purchases and sales of crude oil was de minimis.Black Diamond system.
Operating Costs and Expenses Total operatingOperating costs and expenses for secondfirst quarter and the first six months of2019 increased as compared with 2018, increased from 2017 primarily due to an increase in gathering systems and facilities operating expense associated with the the Billy Miner CGF and Jesse James CGF, which commenced operations in the second half of 2017, along with the addition ofDelaware Basin central gathering facilities (CGF) that were completed during 2018, additional expenses associated with the Black Diamond system and expenses associated with the commencement of gathering system, acquiredservices in the Saddle Butte acquisitionMustang IDP in first quarter 2018.
Depreciation and amortization expense for second quarter and the first six months of 2018 increased from 2017 due to assets placed in service subsequent to first quarter 2017, including expense related to tangible and intangible assets acquired in the Saddle Butte acquisition during first quarter 2018.
Gain on Divestitures Gain on divestitures relates to sales of our interest in CONE Gathering and a portion of our investment in CNX Midstream Partners common units. See Item 1. Financial Statements – Note 3. Acquisitions and Divestitures.

DD&A Expense DD&A expense for first quarter 2019 increased as compared with 2018, primarily due to certain assets being placed in service subsequent to first quarter 2018, including the Mustang IDP gathering system, the Delaware Basin CGFs, and additional Black Diamond assets. In addition, DD&A expense includes a full quarter of amortization related to intangible assets acquired in the Saddle Butte Acquisition.
Cost of Purchased Oil Cost of purchased crude oil for first quarter 2019 increased as compared with 2018 due to a full quarter of services related to the Black Diamond system.
RESULTS OF OPERATIONS – CORPORATE
ResultsOur Corporate costs include exit costs, certain costs associated with mitigating the effects of Operationsour retained Marcellus Shale firm transportation agreements and expenses related to debt, headquarters depreciation, and corporate general and administrative expenses.
Firm Transportation Exit Cost Revenues and expenses associated with retained Marcellus Shale firm transportation contracts were as follows:
 Three Months Ended March 31,
(millions)2019 2018
Sales of Purchased Gas (1)
$27
 $31
Cost of Purchased Gas (1)
42
 36
Firm Transportation Exit Cost (2)
92
 —
(1)
Relates to third party mitigation activities which we engage in to utilize a portion of our Marcellus Shale firm commitment.
(2)
Represents exit costs related to future commitments to a third party resulting from a permanent pipeline capacity assignment. See Item 1. Financial Statements – Note 9. Exit Cost – Transportation Commitments.
General and Administrative (G&A) Expense   General and administrativeG&A expense (G&A) was as follows:
Three Months Ended June 30, Six Months Ended June 30,Three Months Ended March 31,
(millions, except unit rate)2018 2017 2018 20172019 2018
G&A Expense$105
 $103
 $209
 $202
$102
 $104
Unit Rate per BOE (1)
$3.40
 $2.82
 $3.29
 $2.88
$3.41
 $3.18
(1) 
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
G&A expense for secondfirst quarter and the first six months of 2018 increased2019 remained relatively flat as compared with 2017. This increase was driven by increased employee costs and2018 primarily due to decreases in third party transaction-related fees, in support of our development projects, partially offset by a decreaseincreases in contractor expenses.employee costs. The increase in the unit rate per BOE for the first six months of 2018quarter 2019 as compared with 20172018 was due primarily to the increase in total G&A expense combined with thenet decrease in total sales volumes due to the divestitureprimarily as a result of the Marcellus Shale upstreamsale of our Gulf of Mexico assets and sale of 7.5% interest in second quarter 2017.
Other Operating Expense, Net the Tamar field. See Item 1. Financial StatementsResults of Operations – Note Exploration & Production2. Basis of Presentation and Item 1. Financial Statements – Note 11. Segment Information for discussion of other operating expense items for second quarter and the first six months of 2018 as compared with 2017..
Interest Expense and Capitalized Interest   Interest expense and capitalized interest were as follows:
Three Months Ended June 30, Six Months Ended June 30,Three Months Ended March 31,
(millions, except unit rate)2018 2017 2018 20172019 2018
Interest Expense, Gross$91
 $107
 $181
 $206
$87
 $90
Capitalized Interest(18) (11) (35) (23)(21) (17)
Interest Expense, Net$73
 $96
 $146
 $183
$66
 $73
Unit Rate per BOE (1)
$2.37
 $2.63
 $2.30
 $2.61
$2.21
 $2.24
(1) 
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
Interest expense, gross, for secondfirst quarter and the first six months of 2018 decreased2019 remained flat as compared with 2017 primarily due2018. Lower interest rates applicable to a decrease in the overall debt balance. Specifically, subsequent to second quarter 2017, we repaid $550 million on our Term LoanNoble Midstream Partners Revolving Credit Facility due January 6, 2019 and during the first six months of 2018, we repaid $379 million of Senior Notes due May 1, 2021. In addition, in second quarter 2017, we conducted a tender offer and subsequent redemption of our 8.25% Senior Notes, resulting in a lower interest rate and lowerwere offset by interest expense gross. These were partially offset by an increase of $445 million inrelated to the amount outstanding under our Noble Midstream Services RevolvingTerm Loan Credit Facility.Facility which commenced in third quarter 2018. See Item 1. Financial Statements -– Note 5. Debt.7. Debt.
Capitalized interest for secondfirst quarter and the first six months of 20182019 increased as compared with 20172018, primarily due to higher work in progress amounts related to the Leviathan development. See
Item 1. Financial Statements - Note Table of Contents7. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.

The unit rate of interest expense, net, per BOE for secondfirst quarter and the first six months of 20182019 decreased as compared with 20172018, primarily due to the changesreduction in net interest expense, noted above, partially offset by the net decrease in total sales volumes. See Results of Operations – Exploration & Production.
LIQUIDITY AND CAPITAL RESOURCES
Capital Structure/Financing Strategy
In seeking to effectively fund and monetize our discovered hydrocarbons, we employ a capital structure and financing strategy designed to provide sufficient liquidity throughout the commodity price cycle,cycles, including a sustained period of low prices. Specifically, we strive to retain the ability to fund long cycle, multi-year, capital intensive development projects throughout a range of scenarios, while also funding a continuing exploration program and maintaining capacity to capitalize on financially attractive merger and acquisition opportunities. We endeavor to maintain a strong balance sheet and an investment grade debt rating in service of these objectives.
We strive to maintain a minimum liquidity level to address volatility and risk. Traditional sources of our liquidity are cash flows from operations, cash on hand, proceeds from divestitures of properties and other investments, and available borrowing capacity under our $4.0 billion unsecured revolving credit facility (RevolvingRevolving Credit Facility) and proceeds from divestitures of properties.Facility. We occasionally access the capital markets to ensure adequate liquidity exists in the form of unutilized capacity under our Revolving Credit Facility or to refinance scheduled debt
Table of Contents

maturities. In first quarter 2019, we established a $4.0 billion commercial paper program, which can be accessed as needed to supplement operating cash flows for short-term funding needs. We also evaluate potential strategic farm-out arrangements of our working interests for reimbursement of our capital spending. We periodically consider repatriations of foreign cash to increase our financial flexibility and fund our capital investment program. See Operating Outlook – ImpactWe also enter into crude oil and natural gas price hedging arrangements in an effort to mitigate the effects of Recent Changes in US Tax Law.
Our portfolio transformation strategy, primarily executed during 2017, has continued into 2018, withcommodity price volatility and enhance the salespredictability of Gulfcash flows relating to the marketing of Mexico assets, a 7.5% working interest in Tamar, our 50% interest in CONE Gathering LLC and a portion of our investmentcrude oil and natural gas production.
Thus far in CNX Midstream Partners common units. As a result, our divestitures2019, we have generated cash proceeds of approximately $3.5 billion during 2017-2018 and were used to improve our capital structure and strengthen our liquidity profile.
We strive to fundfunded our capital program through organicwith cash flows from operations, cash on hand, and when needed, utilize borrowingsproceeds from divestments of non-strategic assets. We did not repurchase any shares of Noble Energy common stock under our Revolving Credit Facility.the Board of Directors-authorized $750 million share repurchase program during first quarter 2019.
As of June 30, 2018,March 31, 2019, our consolidated outstanding debt (excluding capitalfinance lease obligations) totaled $6.4$6.6 billion. We may periodically seek to access the capital markets to refinance a portion of our outstanding indebtedness. In addition, we may from time to time seek to retire or purchase our outstanding senior notes through cash purchases in the open market, purchases, privately negotiated transactions or otherwise. Such repurchases, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be significant.
SecondFirst Quarter and Year-to-Date 20182019 Highlights
During secondfirst quarter 2018, we continued to focus efforts on shareholder return initiatives, including share repurchases and dividend growth, as well as debt reduction with the following actions completed:
redemption of $379 million in outstanding senior notes;
acquisition of 1.8 million shares of Noble Energy stock, for $63 million, resulting in year to date repurchases of 4.0 million shares for $130 million, pursuant to the Board of Directors' authorized $750 million 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.
In addition, during the first six months of 2018,2019, we completed the following financing activities:
repaid all amounts outstanding under theestablished a $4.0 billion commercial paper program, supported by Noble Energy’s Revolving Credit Facility; and
extendedsecured the Revolving Credit Facility maturity date by two and a half years to March 2023;
amended the$200 million GIP preferred equity commitment for Noble Midstream Services Revolving Credit Facility to increase the capacity from $350Partners, with $100 million to $800 million; and
extended the maturity date of the Noble Midstream Services Revolving Credit Facility by one and a half years to March 2023.
Also,funded during the first six months of 2018, we repatriated $404 million in payments from foreign operations on an outstanding note payable. This payment eliminates the balance on the note payablequarter.
Available Liquidity
The following table summarizes our cash, debt and has no US tax impact.
Available Liquidity
Information regarding cash and debt balances is shown in the table below:available liquidity:
 June 30, December 31,
(millions, except percentages)2018 2017
Total Cash (1)
$621
 $713
Amount Available to be Borrowed Under Revolving Credit Facility (2)
4,000
 3,770
Total Liquidity$4,621
 $4,483
Total Debt (3)
$6,663
 $6,859
Noble Energy Share of Equity10,252
 9,936
Ratio of Debt-to-Book Capital (4)
39% 41%
Table of Contents

(millions, except percentages)March 31, 2019 December 31, 2018
Total Cash (1)
$530
 $719
Amount Available to be Borrowed Under Revolving Credit Facility (2)
4,000
 4,000
Total Liquidity$4,530
 $4,719
Total Debt (3)
$6,837
 $6,675
Noble Energy Share of Equity9,071
 9,426
Ratio of Debt-to-Book Capital (4)
43% 41%
(1) 
As of June 30, 2018,March 31, 2019, total cash includedincludes cash and cash equivalents of $15$10 million related to Noble Midstream Partners.Partners and $2 million of restricted cash. As of December 31, 2017,2018, total cash included $18includes cash and cash equivalents of $11 million cash ofrelated to Noble Midstream Partners and $38$3 million of restricted cash related to the Saddle Butte acquisition that closed first quarter 2018.cash.
(2) 
Excludes amounts available to be borrowed under the Noble Midstream Services Revolving Credit Facility, and Leviathan Term Loan Facility, which areis not available to Noble Energy for general corporate purposes. See discussion below.
(3) 
Total debt includes capitallong-term finance lease obligations and excludes unamortized debt discount/premium.premium and debt issuance costs. Additionally, it includes Noble Midstream Partners' debt of $730 million and $560 million as of March 31, 2019 and December 31, 2018, respectively. See Item 1. Financial Statements – Note 5. Debt.7. Debt.
Table of Contents

(4) 
We define our ratio of debt-to-book capital as total debt (which includes long-term(long-term debt excluding unamortized discount,discount/premium and issuance costs, 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.
Cash and Cash Equivalents   We had approximately $621$528 million in cash and cash equivalents at June 30, 2018,March 31, 2019, primarily denominated in US dollars and invested in money market funds and short-term deposits with major financial institutions. Approximately $428$361 million of this cash is attributable to our foreign subsidiaries. We do not expect to incur any significant US income tax expense with respect to future repatriation of foreign cash.
Revolving Credit Facilities Noble Energy's Revolving Credit Facility of $4.0 billion matures in 2023. Theand the Noble Midstream Services Revolving Credit Facility of $800 million also maturesboth mature in 2023. These facilities are used to fund capital investment programs and acquisitions and may periodically provide amounts for working capital purposes. At June 30, 2018,March 31, 2019, no amounts were outstanding under the Noble Energy Revolving Credit Facility and $530$230 million was outstanding under the Noble Midstream Services Revolving Credit Facility, leaving $4.0 billion and $270$570 million in remaining availability under the respective credit facilities. See Item 1. Financial Statements – Note 6. Debt.
Leviathan Term Loan FacilityCommercial Paper Program In first quarter 2019, we established a commercial paper program to provide for short-term funding needs. The Leviathan Term Loan Facility providesprogram allows for a limited recourse secured term loan facility with an aggregate principal borrowing amountmaximum of up to $1.0$4.0 billion of which $625 millionunsecured commercial paper notes and is initially committed. Any amounts borrowed under the Leviathan Term Loan Facility will be available to fund a portion of our share of costs for the initial phase of development of the Leviathan field, offshore Israel. To support the Leviathan development program and to bring first production onlinesupported by the end of 2019, we may borrow amounts under this facility in the near-term.Revolving Credit Facility. As of June 30, 2018,March 31, 2019, no amounts were drawn under this facility.
Legacy Rosetta Note Redemption In May 2018, we redeemed $379 million of Senior Notes due May 1, 2021, that we had assumed in the Rosetta Merger, for $395 million, including $11 million of accrued interest and $5 million of call premium. We fully amortized $10 million of remaining premium, and recognized a gain of $5 million for the unamortized premium.
Interest Rate Risk Certain of our borrowings subject us to interest rate risk.commercial paper was outstanding. See Item 1. Financial Statements – Note 5.7. Debt andItem 3. Quantitative and Qualitative Disclosures About Market Risk..
Subsequent Event - Noble Midstream Services Term Credit AgreementGIP Preferred Equity Commitment On July 31, 2018, Noble Midstream Services, LLC entered into a three year senior unsecured term loan credit facility (Noble Midstream Services Term Credit Agreement) of up to $500 million. Proceeds from the Noble Midstream Services Term Credit Agreement will be used to repay a portion of the outstanding borrowings under the Noble Midstream Services Revolving Credit Facility, pay fees and expenses in connection with the Noble Midstream Services Term Credit Agreement transactions and for working capital, capital expenditures, acquisitions and other purposes as necessary ofMarch 25, 2019, Noble Midstream Partners and its subsidiaries.secured a $200 million preferred equity commitment from GIP to fund capital contributions to Dos Rios Crude Intermediate LLC, a newly-formed subsidiary holding Noble Midstream Partners’ 30% equity interest in EPIC Crude Holdings. Of the $200 million total commitment, $100 million was funded, with the remaining $100 million available for a one-year period, subject to certain conditions precedent. See Item 1. Financial Statements – Note5. Debt.4. Acquisitions and Divestitures.
Contractual Obligations
Exploration Commitments The terms of some of our production sharing contracts, licenses or concession agreements may require us to conduct certain exploration activities, including drilling one or more exploratory wells or acquiring seismic data, within specific time periods. These obligations can extend over periods of several years, and failure to conduct such exploration activities within the prescribed periods could lead to loss of leases or exploration rights and/or penalty payments.
Leviathan Development Obligations The initial development of our Leviathan field requires substantial infrastructure and capital, and we have executed major equipment and installation contracts in support of our development activities. As of June 30, 2018, we had entered into approximately $235 million, net, of contracts to support the remaining development activities and bring first production online by the end of 2019.
Continuous Development ObligationsAlthough the majority of our assets are held by production, certain of our US onshore assets, such as our Eagle Ford Shale and Delaware Basin properties, are held through continuous development obligations. Therefore, we are contractually obligated to fund a level of development activity in these areas, the amount of which could be substantial, or exercise options with land owners to extend leases. Failure to meet continuous development obligations or to exercise lease extensions may result in loss of leases.
EPIC Firm Transportation Agreement During second quarter 2018, we dedicated acreage to, and secured firm capacity with, EPIC for transport of 100 MBbl/d of crude oil from the Delaware Basin to Corpus Christi, Texas, for a 10-year period beginning at pipeline start-up.
Table of Contents

Marcellus Shale Firm Transportation Agreements We have remaining financial commitments of approximately $1.4$1.1 billion, undiscounted, associated with Marcellus Shale firm transportation contracts. We have engaged in actions to commercialize a substantial portion of these commitments, which provide for the transportation of approximately 450,000 MMBtu/d of natural gas. Actions include the permanent assignment of capacity, negotiation of capacity release, utilization of capacity through purchase of third party natural gas, and other potential arrangements.
We expect these actions, some of which may require pipeline and/or FERC approval, to continue to reduce our financial commitment associated with these contracts. For pipelines currently under construction and targeted for in-service late 2018, we will evaluate our position at the date each pipeline is placed in service and our commitment begins. If we determine that we will not utilize a portion, or all, of the contracted pipeline capacity, we will accrue a liability at fair value for the net amount of the estimated remaining financial commitment. These contracts represent approximately $890 million, undiscounted, of the total $1.4 billion commitment noted above. See Item 1. Financial Statements – Note 12.9. Exit Cost – Transportation Commitments and Contingencies.
Credit Rating Events We do not have any triggering events on our consolidated debt that would cause a default in case of a downgrade of our credit rating. In addition, there are no existing ratings triggers in any of our commodity hedging agreements that would require the posting of collateral. However, a series of downgrades or other negative rating actions could increase our cost of financing and may increase our requirements to post collateral as financial assurance of performance under certain other contractual arrangements, such as pipeline transportation contracts, crude oil and natural gas sales contracts, work commitments and certain abandonment obligations. A requirement to post collateral could have a negative impact on our liquidity.
Letters of CreditIn the ordinary course of business, we maintain letters of credit and bank guarantees with a variety of banks in support of certain performance obligations of our subsidiaries. Outstanding letters of credit and bank guarantees, including those of Noble Midstream Partners, totaled approximately $100 million at March 31, 2019.
Cash Flows
SummaryThe following table summarizes our total cash flow information is as follows:provided by (used in) operating, investing and financing activities:
Six Months Ended June 30,Three Months Ended March 31,
(millions)2018 20172019 2018
Total Cash Provided By (Used in)   
Operating Activities$1,079
 $877
$528
 $583
Investing Activities(1,050) (1,121)(911) (572)
Financing Activities(121) (426)194
 298
Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash$(92) $(670)
(Decrease) Increase in Cash, Cash Equivalents and Restricted Cash$(189) $309
Operating Activities   Cash provided by operating activities increased for the first six months of 2018quarter 2019 decreased $55 million as compared with 2017 by approximately $202 million. The increase is2018, primarily due to higher realized crude oil prices and an increase in crude oil production in the DJ and Delaware basins. In addition, changes in working capital included a significant increase in the balance of the current portion of the commodity derivatives liability.
These increases were partially offset by lower realized natural gas prices, a decrease in natural gas production attributable to our exit from the Marcellus Shale in second quarter 2017,net revenues driven by declining crude oil and NGL sales prices, partially offset by higher production costs attributable to increased operational activity and rising costs in US onshore activity.onshore. In addition, we received cash in settlements for commodity derivatives of $14 million, as compared with cash payments of $28 million in the prior year.
Investing Activities   OurCash used in investing activities includeincreased $339 million for first quarter 2019 as compared with 2018, primarily due to a decrease in net proceeds provided by divestitures, partially offset by a decrease in capital spending on a cash basis for oil and gas properties and investments in unconsolidated subsidiaries accounted for by the equity method. These investing activities may be offset by proceeds from property sales or dispositions, including farm-out arrangements, which may result in reimbursement for capital spending that occurred in prior periods.
Total additions to property, plant and equipment increased $567 million during theequipment. In addition, in first six months of 2018 as compared with 2017 primarily due to increases in spending related to development costs in the Delaware Basin, construction of midstream infrastructure and Leviathan development costs, partially offset by decreases in development costs primarily in the Marcellus Shale and Eagle Ford Shale. See Operating Outlook – 2018 Capital Investment Program, above.
During the first six months of 2018, we completed certain portfolio activities including the Saddle Butte acquisition for $650 million, net. Also during the first six months of 2018, we received net proceeds of $1.4 billion from asset sales, including the sale of our Gulf of Mexico assets, a 7.5% interest in the Tamar field, our 50% interest in CONE Gathering LLC and a portion of our CNX Midstream Partners common units.
In comparison, during the first six months of 2017, we used $637 million of cash to fund a portion of the consideration paid in the Clayton Williams Energy Acquisition and acquired Delaware Basin assets for $301 million. We received net cash proceeds of $1.0 billion from the Marcellus Shale upstream divestiture, and other investing activities provided net cash of $33 million.
Financing Activities  Our financing activities, in general, include debt transactions, the issuance and repurchase of Noble Energy common stock andquarter 2019, Noble Midstream Partners common units, payment of cash dividends to Noble Energy shareholders, and payment of cash distributions to, and receipt of cash contributions from, Noble Midstream Partners noncontrolling interest owners.Partners' invested $271 million on equity
Table of Contents

method investees compared to none in prior year. Finally, there were no acquisitions in first quarter 2019 compared to $650 million in prior year. See Operating Outlook – 2019 Capital Investment Program.
Financing Activities  Our primary financing activities during the first six monthsquarter 2019 include net borrowings of 2018 included a $230$170 million net, Revolving Credit Facility repayment and $445 million, net,on the Noble Midstream Services Revolving Credit Facility borrowings used primarily to fund an acquisition. We also used $384and the receipt of $99 million of cash to redeem senior notes which had accrued interestGIP preferred equity, net of $11 million and is reflected within operating activities.
offering costs. In addition, during the first six months of 2018,quarter 2019, we made common stock repurchases totaling $130 million pursuant to our stock repurchase program, paid $102$53 million of cash dividends to Noble Energy shareholders and $22 million of cash distributions to Noble Midstream Partners noncontrolling interest owners. We also received $331 million of contributions from noncontrolling interest owners. Othershareholders.
Our financing activities usedduring first quarter 2018 included a net cashrepayment of $29 million.
In comparison, during$230 million on the first six months of 2017, we borrowed and repaid $1.3 billion under our Revolving Credit Facility and borrowed a net $190borrowings of $350 million underon the Noble Midstream Services Revolving Credit Facility. We also repaid $595Facility used primarily to fund the Saddle Butte acquisition. In addition, we made common stock repurchases totaling $67 million pursuant to our share repurchase program and paid $48 million of assumed Clayton Williamscash dividends to Noble Energy debt. We used cash of $92 million to pay dividends on our common stock and $12 million to pay distributions to noncontrolling interest owners. We received $138 million of net cash from the issuance of Noble Midstream Partners common units.shareholders.
See Item 1. Financial Statements – Consolidated Statements of Cash Flows.
DividendsCapital Expenditure Activities
Our capital expenditures (on an accrual basis) were as follows:
 Three Months Ended March 31,
(millions)2019 2018
Unproved Property Acquisition (1)
$35
 $4
Proved Property Acquisition (1)
4
 —
Exploration and Development628
 652
Midstream (2)
66
 459
Corporate and Other18
 11
Total$751
 $1,126
Other   
Investment in Equity Method Investees (3)
$271
 $—
Increase in Finance Lease Obligations2
 —
(1)
Costs for first quarter 2019 relate to US onshore leasehold activity.
(2)
Midstream expenditures for first quarter 2018 include $206 million related to the Saddle Butte Acquisition.
(3)
Costs include primarily Noble Midstream Partners' $227 million investment in EPIC Y-Grade and EPIC Crude Holdings and $38 million investment in Delaware Crossing. See Item 1. Financial Statements – Note4. Acquisitions and Divestitures.
Exploration and development costs for first quarter 2019 decreased as compared with 2018, due to our focus on US onshore capital efficiencies and the near-term completion of Leviathan development activities. Exploration and development costs include approximately $487 million for US onshore and $132 million for Eastern Mediterranean, primarily related to Leviathan.
Midstream capital spending, excluding acquisitions, for first quarter 2019 decreased as compared with 2018. First quarter 2019 activities focused primarily on well connections in the Mustang IDP and Black Diamond system while 2018 activities included construction of the Mustang IDP gathering and fresh water systems, Delaware Basin CGFs, and connecting the Black Diamond system to a major crude oil takeaway outlet in the DJ Basin.
Dividends
On July 24, 2018,April 22, 2019, our Board of Directors declared a quarterly cash dividend of 1112 cents per Noble Energy common share, which will be paid on AugustMay 20, 20182019 to shareholders of record on AugustMay 6, 2018.2019. The amount of future dividends will be determined on a quarterly basis at the discretion of our Board of Directors and will depend on earnings, financial condition, capital requirements and other factors.
Capital Expenditure Activities The following presents our capital expenditures (on an accrual basis) for the second quarter and the first six months of 2018 and 2017:
 Three Months Ended June 30, Six Months Ended June 30,
(millions)2018 2017 2018 2017
Acquisition, Capital and Exploration Expenditures 
  
  
  
Unproved Property Acquisition (1)
$—
 $1,581
 $—
 $1,826
Proved Property Acquisition (2)
—
 782
 —
 840
Exploration and Development771
 605
 1,427
 1,199
Midstream (3)
157
 152
 616
 245
Corporate and Other16
 10
 27
 15
Total$944
 $3,130
 $2,070
 $4,125
Investment in Equity Method Investee (4)
$—
 $67
 $—
 $67
(1) 2017 acquisition costs include $1.6 billion related to the Clayton Williams Energy Acquisition and $246 million related to the Delaware Basin acquisition.
(2) 2017 acquisition costs include $724 million of proved properties and $59 million of asset retirement obligations acquired in the Clayton Williams Energy Acquisition and $58 million related to the Delaware Basin asset acquisition.
(3) Midstream expenditures for the six months ended June 30, 2018 include $206 million related to the Saddle Butte acquisition. Midstream expenditures for the first six months of 2017 include $67 million related to the Clayton Williams Energy Acquisition.
(4) 2017 costs represent our contribution to the Advantage Joint Venture, in which Noble Midstream Partners owns a 50% interest.
Development costs for second quarter and the first six months of 2018 increased as compared with second quarter and the first six months of 2017 due to increased US onshore activity and Leviathan development activities. Year to date development costs include approximately $1.1 billion for US onshore E&P operations and approximately $350 million for Leviathan. The increase in development costs was partially offset by a decrease due to the 2017 Marcellus Shale divestiture. In addition, midstream capital spending, exclusive of acquisitions, increased due to the construction of gathering systems in the DJ and Delaware Basins.
Table of Contents

Item 3.    Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
We are exposed to market risk in the normal course of business operations, and the volatility of crude oil and natural gas prices continues to impact the oil and gas industry. See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - E&P– Results of Operations – Exploration & Production, above..
Derivative Instruments Held for Non-Trading Purposes   Due to the volatility of crude oil and natural gas prices, we continue to use derivative instruments as a means of managingAt March 31, 2019, our exposure to price changes.
Table of Contents

At June 30, 2018, we had various open commodity derivative instruments related to crude oil and natural gas. Changes in fair value of commodity derivative instruments are reported in earnings in the period in which they occur. Our open commodity derivative instruments were in a net liability position with a fair value of $306$73 million. Based on the June 30, 2018March 31, 2019 published commodity futures price curves for the underlying commodities, a hypothetical price increase of 10% per Bbl for crude oil and 10% per MMBtu for natural gas would increase the fair value of our net commodity derivative liability by approximately $280$508 million. Our derivative instruments are executed under master agreements which allow us,Even with certain hedging arrangements in place to mitigate the eventrisk of default, to elect early terminationcommodity price volatility, our 2019 revenues and results of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty wouldoperations could be net cash settled at the time of election.adversely affected if commodity prices decline. See Item 1. Financial Statements – Note 4.12. Derivative Instruments and Hedging Activities.Activities.
Interest Rate Risk
Changes in interest rates affect the amount of interest we pay on certain of our borrowingsborrowings. Issuances of commercial paper under our commercial paper program and the amount of interest we earn on our short-term investments.
At June 30, 2018, we had approximately $6.4 billion (excluding capital lease obligations) of long-term debt outstanding, net of unamortized discount and debt issuance costs. Of this amount, $5.8 billion was fixed-rate debt, net of unamortized discount and debt issuance costs, with a weighted average interest rate of 5.06%. Although near term changes in interest rates may affect the fair value of our fixed-rate debt, they do not expose us to interest rate risk or cash flow loss.
However, we are exposed to interest rate risk related to our interest-bearing cash and cash equivalents balances. As of June 30, 2018, our cash and cash equivalents totaled $621 million, approximately 46% of which was invested in money market funds and short-term investments with major financial institutions.
In addition, borrowings under the Revolving Credit Facility, Noble Midstream Services Revolving Credit Facility and LeviathanNoble Midstream Services Term Loan Credit Facility, which as March 31, 2019 total $730 million and have a weighted average interest rate of 3.49%, are subject to variable interest rates which expose us to the risk of earnings or cash flow loss due to potential increases in market interest rates. A change in the interest rate applicable to our variable-rate debt could expose us to additional interest cost. While we currently have no interest rate derivative instruments as of June 30, 2018,March 31, 2019, we may invest in such instruments in the future in order to mitigate interest rate risk.
A change in the interest rate applicable to our short-term investments or amounts, if any, outstanding under the Noble Revolving Credit Facility, Noble Midstream Services Revolving Credit Facilityfacilities or Leviathan Term Loan Facilitycommercial paper issuances mentioned above, would have had a de minimis impact.impact on interest expense for first quarter 2019. See Item 1. Financial Statements – Note 5.7. Debt.
Foreign Currency Risk
The US dollar is considered the functional currency for each of our international operations. Substantially all of our international crude oil, natural gas and NGL production is sold pursuant to US dollar denominated contracts. Transactions, such as operating costs and administrative expenses that are paid in a foreign currency, are remeasured into US dollars and recorded in the financial statements at prevailing currency exchange rates. Certain monetary assets and liabilities, for example certain local working capital items, are denominated in a foreign currency and remeasured into US dollars. A reduction in the value of the US dollar against currencies of other countries in which we have material operations could result in the use of additional cash to settle operating, administrative and tax liabilities. Furthermore, our investment in Tamar Petroleum is denominated and settled in New Israeli Shekels.
Net transaction gains and losses were de minimis for the second quarter and the first six months of 2018.
We currently have no foreign currency derivative instruments outstanding. However, we may enter into foreign currency derivative instruments (such as forward contracts, costless collars or swap agreements) in the future if we determine that it is necessary to invest in such instruments in order to mitigate our foreign currency exchange risk.
Disclosure Regarding Forward-Looking Statements
This quarterly report on Form 10-Q contains forward-looking statements within the meaning of the federal securities laws. Forward-looking statements give our current expectations or forecasts of future events. These forward-looking statements include, among others, the following:
our growth strategies;
our future results of operations;
our liquidity and ability to finance our exploration and development and acquisitions activities;
our ability to satisfy contractual commitments, including utilization or commercialization of firm transportation commitments in the Marcellus Shale;
our ability to make and integrate acquisitions;
our ability to successfully and economically explore for and develop crude oil, NGL and natural gas and NGL resources;
anticipated trends in our business;
Table of Contents

market conditions in the oil and gas industry;
the impact of governmental fiscal regulation, including US federal, state, local, and foreign host government tax regulations, and/orfiscal policies and terms, such as thosewell as that involving the protection of the environment or marketing of production as well asand other regulations;
our ability to make and integrate acquisitions or execute divestitures; and
access to resources.
Any such projections or statements reflect Noble Energy’s views (as of the date such projects were published or such statements were made) about future events and financial performance. No assurances can be given that such events or performance will occur as projected, and actual results may differ materially from those projected. Important factors that could cause the actual results to differ materially from those projected include, without limitation, the volatility in commodity prices for crude oil and natural gas, the presence or recoverability of estimated reserves, the ability to replace reserves, environmental risks, drilling and operating risks, exploration and development risks, information technology and security risks, competition, government regulation or other action, the ability of management to execute its plans to meet its goals and other risks inherent in Noble Energy’s business that are detailed in its Securities and Exchange Commission filings.
Forward-looking statements are typically identified by use of terms such as “may,” “will,” “expect,” “believe,” “anticipate,” “estimate,” “intend,” and similar words, although some forward-looking statements may be expressed differently. These forward-looking statements are made based upon our current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements. You should consider carefully the statements under Item 1A. Risk Factors included in our Annual Report on Form 10-K for the year ended December 31, 20172018 and in this quarterly report on Form 10-Q, which describe factors that could
Table of Contents

cause our actual results to differ from those set forth in the forward-looking statements.  Our Annual Report on Form 10-K for the year ended December 31, 20172018 is available on our website at www.nblenergy.com.
Item 4.     Controls and Procedures
Based on the evaluation of our disclosure controls and procedures by our principal executive officer and our principal financial officer, as of the end of the period covered by this quarterly report, each of them has concluded that our disclosure controls and procedures (as defined in Rule 13a-15(e) and Rule 15d-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act)), are effective. There were no changes in internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f) and 15d-15(f)) that occurred during the quarter covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. These forms can also be obtained from the SEC by calling 1-800-SEC-0330. Alternatively, you may access these reports at the SEC’s website at www.sec.gov.

Part II. Other Information
Item 1.    Legal Proceedings
See discussion of legal proceedings in Part I. Financial Information, Item 1. Financial Statements -– Note 12.10. Commitments and Contingencies of this Form 10-Q, which is incorporated by reference into this Part II. Item 1, as well as discussion in Item 3. Legal Proceedings, of our Annual Report on Form 10-K for the year ended December 31, 2017.2018.
Item 1A.    Risk Factors
There have been no material changes from the risk factors disclosed in Item 1A. Risk Factors of our Annual Report on Form 10-K for the year ended December 31, 2017.2018.
Item 2.    Unregistered Sales of Equity Securities and Use of Proceeds 
Table of Contents

The following table sets forth, for the periods indicated, our share repurchase activity:
Period
Total Number of
Shares
Purchased (1)
 
Average
Price Paid
Per Share
 
Total Number of
Shares Purchased
as Part of Publicly
Announced Plans or
Programs (2)
 
Approximate Dollar
Value of Shares that
May Yet Be
Purchased Under the
Plans or Programs
       (millions)
4/1/2018 - 4/30/2018216
 $31.72
 —
  
5/1/2018 - 5/31/2018837,995
 32.84
 837,418
  
6/1/2018 - 6/30/2018941,779
 35.65
 941,502
  
Total1,779,990
 $34.33
 1,778,920
 $620
Period
Total Number of Shares Purchased (1)
 Average Price Paid Per Share 
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2)
 Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
       (millions)
1/1/2019 - 1/31/2019933
 $20.68
 —
  
2/1/2019 - 2/28/2019217,821
 22.54
 —
  
3/1/2019 - 3/31/2019902
 24.65
 —
  
Total219,656
 $22.54
 —
 $455
 
(1) 
Includes stockStock repurchases of 1,070 during the period relatingrelated 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) 
During secondfirst quarter 2018,2019, we repurchased and retired 1.8 milliondid not repurchase shares of common stock at an average purchase price of $35.15 per share pursuant tounder the $750 million share repurchase program, authorized by ourthe Board of Directors, which expires December 31, 2020.
Table of Contents

Item 3.    Defaults Upon Senior Securities
None. 
Item 4.    Mine Safety Disclosures
Not applicable. 
Item 5.    Other Information
None.
Table of Contents

Item 6.    Exhibits

Exhibit Number Exhibit*
   
2.1 
Agreement 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 (File No. 001-07964) and incorporated herein by reference).
   
2.2
Agreement 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).
2.3 
Exchange 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 (File No. 001-07964) and incorporated herein by reference).
   
3.1 
Restated 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 (File No. 001-07964) and incorporated herein by reference).
   
3.2 
By-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).
3.3
Certificate 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).
3.4
Certificate of Elimination of the Series B Mandatorily Convertible Preferred Stock of Noble Energy, Inc.5, 2019) (filed as Exhibit 3.2 to the Registrant’s CurrentAnnual Report on Form 8-K (Date of Report: July 26, 2016)10-K filed on July 28, 2016February 19, 2019 (File No. 001-07964) and incorporated herein by reference).
   
10.1* 
Noble Energy, Inc. Short-Term2017 Long-Term Incentive Plan (Amended and Restated Effective April 23, 2019), filed herewith.
10.2*
Form of Restricted Stock Notice and Award Agreement (three-year vested one-third per year) under the Noble Energy, Inc. 2017 Long-Term Incentive Plan, filed herewith.
   
12.110.3* 
CalculationForm of ratioOption Award Notice and Agreement under the Noble Energy, Inc. 2017 Long-Term Incentive Plan, filed herewith.
10.4*
Form of earnings to fixed charges,Restricted Stock Notice and Award Agreement (three-year cliff vested) under the Noble Energy, Inc. 2017 Long-Term Incentive Plan, filed herewith.
10.5*
Form of Restricted Stock Notice and Award Agreement (three-year vested 20/30/50) under the Noble Energy, Inc. 2017 Long-Term Incentive Plan, filed herewith.
   
31.1 
Certification of the Company’s Chief Executive Officer Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241), filed herewith.
   
31.2 
Certification of the Company’s Chief Financial Officer Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241), filed herewith.
   
32.1 
Certification of the Company’s Chief Executive Officer Pursuant To Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), furnished herewith.
   
32.2 
Certification of the Company’s Chief Financial Officer Pursuant To Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), furnished herewith.
   
101.INS Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
   
101.SCH XBRL Schema Document
   
101.CAL XBRL Calculation Linkbase Document
   
101.LAB XBRL Label Linkbase Document
   
101.PRE XBRL Presentation Linkbase Document
   
101.DEF XBRL Definition Linkbase Document
Table of Contents

*
* 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.



Table of Contents

Signatures
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
    NOBLE ENERGY, INC.
    (Registrant)
     
Date AugustMay 3, 20182019 /s/By: /s/ Kenneth M. Fisher
    
Kenneth M. Fisher
Executive Vice President, Chief Financial Officer


5338