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 September 30, 2017

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

nbllogoupdated9302014a72.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)

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

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.
Yesý☒    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).
Yesý☒    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 filerx
☒
Accelerated filer ☐
Accelerated filer o
Non-accelerated filer o☐
Smaller reporting companyo
☐
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
☒
As of September 30, 2017,2019, there were 486,607,284478,298,006 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 LossIncome (Loss)
3
  
Consolidated Balance Sheets
4
  
Consolidated Statements of Cash Flows
5
  
Consolidated Statements of Equity
6
  
Notes to Consolidated Financial Statements
78
  
Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations
3025
  
Item 3.  Quantitative and Qualitative Disclosures About Market Risk
5439
  
Item 4.  Controls and Procedures
5640
  
Part II. Other Information
5740
  
Item 1.  Legal Proceedings
5740
  
Item 1A.  Risk Factors
5740
  
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
5740
  
Item 3. Defaults Upon Senior Securities
5840
  
Item 4. Mine Safety Disclosures
5840
  
Item 5.  Other Information
5840
  
Item 6.  Exhibits
5941
  
Signatures
6142


Table of Contents


Part I. Financial Information
Item 1. Financial Statements
Noble Energy, Inc.
Consolidated Statements of Operations and Comprehensive LossIncome (Loss)
(millions, except per share amounts)
(unaudited)
 Three Months Ended September 30, Nine Months Ended September 30,
 2019 2018 2019 2018
Revenues       
Oil, NGL and Gas Sales$1,003
 $1,136
 $2,894
 $3,409
Sales of Purchased Oil and Gas87
 72
 264
 191
Other Revenue29
 65
 106
 189
Total1,119
 1,273
 3,264
 3,789
Costs and Expenses 
  
    
Production Expense297
 273
 862
 886
Depreciation, Depletion and Amortization583
 485
 1,619
 1,418
General and Administrative91
 107
 298
 316
Cost of Purchased Oil and Gas96
 76
 296
 204
Other Operating Expense, Net61
 27
 257
 107
Gain on Divestitures, Net—
 (193) —
 (859)
Asset Impairments—
 —
 —
 168
Total1,128
 775
 3,332
 2,240
Operating (Loss) Income(9) 498
 (68) 1,549
Other (Income) Expense 
  
    
(Gain) Loss on Commodity Derivative Instruments(129) 155
 23
 483
Interest, Net of Amount Capitalized67
 70
 196
 216
Other Non-Operating Expense (Income), Net2
 (34) 7
 (10)
Total(60) 191
 226
 689
Income (Loss) Before Income Taxes51
 307
 (294) 860
Income Tax Expense (Benefit)15
 59
 (49) 44
Net Income (Loss) and Comprehensive Income (Loss) Including Noncontrolling Interests36
 248
 (245) 816
Less: Net Income and Comprehensive Income Attributable to Noncontrolling Interests19
 21
 61
 58
Net Income (Loss) and Comprehensive Income (Loss) Attributable to Noble Energy$17
 $227
 $(306) $758
 

 

 

 

Net Income (Loss) Attributable to Noble Energy Common Shareholders per Share       
   Basic$0.04
 $0.47
 $(0.64) $1.57
   Diluted$0.04
 $0.47
 $(0.64) $1.56
Weighted Average Number of Common Shares Outstanding       
   Basic478
 482
 478
 484
   Diluted480
 484
 478
 486

 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
Revenues       
Oil, NGL and Gas Sales$907
 $882
 $2,918
 $2,411
Income from Equity Method Investees and Other53
 28
 137
 70
Total960
 910
 3,055
 2,481
Costs and Expenses 
  
    
Production Expense280
 282
 866
 839
Exploration Expense64
 125
 136
 376
Depreciation, Depletion and Amortization523
 621
 1,554
 1,859
Loss on Marcellus Shale Upstream Divestiture4
 —
 2,326
 —
General and Administrative102
 95
 304
 293
Other Operating (Income) Expense, Net(15) 37
 132
 127
Total958
 1,160
 5,318
 3,494
Operating Income (Loss)2
 (250) (2,263) (1,013)
Other Expense 
  
    
Loss (Gain) on Commodity Derivative Instruments22
 (55) (145) 53
Loss (Gain) on Extinguishment of Debt98
 —
 98
 (80)
Interest, Net of Amount Capitalized88
 86
 271
 242
Other Non-Operating Expense (Income), Net2
 (1) (4) 3
Total210
 30
 220
 218
Loss Before Income Taxes(208) (280) (2,483) (1,231)
Income Tax Benefit(93) (137) (917) (486)
Net Loss and Comprehensive Loss Including Noncontrolling Interests(115) (143) (1,566) (745)
Less: Net Income and Comprehensive Income Attributable to Noncontrolling Interests21
 1
 46
 1
Net Loss and Comprehensive Loss Attributable to Noble Energy$(136) $(144) $(1,612) $(746)
        
Net Loss Attributable to Noble Energy per Common Share       
Basic and Diluted$(0.28) $(0.33) $(3.47) $(1.73)
        
Weighted Average Number of Common Shares Outstanding       
   Basic and Diluted487
 430
 464
 430


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


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

September 30,
2017		 December 31,
2016		September 30, 2019 December 31, 2018
ASSETS      
Current Assets      
Cash and Cash Equivalents$564
 $1,180
$473
 $716
Accounts Receivable, Net675
 615
677
 616
Other Current Assets303
 160
277
 418
Total Current Assets1,542
 1,955
1,427
 1,750
Property, Plant and Equipment 
  
 
  
Oil and Gas Properties (Successful Efforts Method of Accounting)30,583
 30,355
30,445
 29,002
Property, Plant and Equipment, Other928
 909
1,045
 891
Total Property, Plant and Equipment, Gross31,511
 31,264
31,490
 29,893
Accumulated Depreciation, Depletion and Amortization(13,115) (12,716)(12,693) (11,474)
Total Property, Plant and Equipment, Net18,396
 18,548
18,797
 18,419
Goodwill1,295
 —
Other Noncurrent Assets416
 508
1,780
 841
Total Assets$21,649
 $21,011
$22,004
 $21,010
LIABILITIES AND EQUITY   
LIABILITIES, MEZZANINE EQUITY AND SHAREHOLDERS' EQUITY   
Current Liabilities   
   
Accounts Payable - Trade$1,123
 $736
Accounts Payable – Trade$1,395
 $1,207
Other Current Liabilities499
 742
1,190
 519
Total Current Liabilities1,622
 1,478
2,585
 1,726
Long-Term Debt7,487
 7,011
6,941
 6,574
Deferred Income Taxes1,352
 1,819
954
 1,061
Other Noncurrent Liabilities1,245
 1,103
1,338
 1,165
Total Liabilities11,706
 11,411
11,818
 10,526
Commitments and Contingencies
 


 


Mezzanine Equity   
Redeemable Noncontrolling Interest, Net103
 —
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; 529 Million and 471 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 Capital8,415
 6,450
8,258
 8,203
Accumulated Other Comprehensive Loss(29) (31)(30) (32)
Treasury Stock, at Cost; 39 Million and 38 Million Shares, respectively(728) (692)
Treasury Stock, at Cost; 39 Million Shares(735) (730)
Retained Earnings1,803
 3,556
1,506
 1,980
Noble Energy Share of Equity9,466
 9,288
9,004
 9,426
Noncontrolling Interests477
 312
1,079
 1,058
Total Equity9,943
 9,600
Total Liabilities and Equity$21,649
 $21,011
Total Shareholders' Equity10,083
 10,484
Total Liabilities, Mezzanine Equity and Shareholders' Equity$22,004
 $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)
Nine Months Ended September 30,Nine Months Ended September 30,
2017 20162019 2018
Cash Flows From Operating Activities      
Net Loss Including Noncontrolling Interests$(1,566) $(745)
Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities   
Net (Loss) Income Including Noncontrolling Interests$(245) $816
Adjustments to Reconcile Net (Loss) Income to Net Cash Provided by Operating Activities   
Depreciation, Depletion and Amortization1,554
 1,859
1,619
 1,418
Loss on Marcellus Shale Upstream Divestiture2,326
 —
Deferred Income Tax Benefit(988) (699)(110) (150)
Dry Hole Cost2
 105
Undeveloped Leasehold Impairment51
 81
Loss (Gain) on Extinguishment of Debt98
 (80)
(Gain) Loss on Commodity Derivative Instruments(145) 53
Net Cash Received in Settlement of Commodity Derivative Instruments18
 454
Stock Based Compensation83
 61
Loss on Commodity Derivative Instruments23
 483
Net Cash Received (Paid) in Settlement of Commodity Derivative Instruments28
 (160)
Other Adjustments for Noncash Items Included in Income12
 136
115
 45
Gain on Divestitures, Net—
 (859)
Asset Impairments—
 168
Firm Transportation Exit Cost92
 —
Changes in Operating Assets and Liabilities      
(Increase) Decrease in Accounts Receivable(148) 6
(13) 114
Increase (Decrease) in Accounts Payable230
 (124)142
 (91)
(Decrease) Increase in Current Income Taxes Payable(41) 82
Other Current Assets and Liabilities, Net(5) (72)(76) 73
Other Operating Assets and Liabilities, Net(63) (63)(46) (81)
Net Cash Provided by Operating Activities1,418

1,054
1,529

1,776
Cash Flows From Investing Activities      
Additions to Property, Plant and Equipment(1,956) (1,164)(1,998) (2,589)
Proceeds from Marcellus Shale Upstream Divestiture1,028
 —
Clayton Williams Energy Acquisition(616) —
Other Acquisitions(327) —
Acquisitions, Net of Cash Received—
 (653)
Additions to Equity Method Investments(68) (8)(686) —
Proceeds from Divestitures and Other129
 786
Proceeds from Divestitures, Net131
 1,740
Other25
 —
Net Cash Used in Investing Activities(1,810)
(386)(2,528)
(1,502)
Cash Flows From Financing Activities      
Dividends Paid, Common Stock(141) (129)
Proceeds from Revolving Credit Facility50
 1,450
Repayment of Revolving Credit Facility(50) (1,680)
Proceeds from Noble Midstream Services Revolving Credit Facility245
 —
655
 690
Repayment of Noble Midstream Services Revolving Credit Facility(45) —
(665) (725)
Proceeds from Term Loan Facility—
 1,400
Issuance of Noble Midstream Partners Common Units, Net of Offering Costs138
 299
Proceeds from Revolving Credit Facility1,585
 —
Repayment of Revolving Credit Facility(1,310) —
Repayment of Clayton Williams Energy Long-term Debt(595) —
Proceeds from Issuance of Senior Notes, Net1,086
 —
Proceeds from Noble Midstream Services Term Loan Credit Facilities400
 500
Proceeds from Commercial Paper Borrowings, Net511
 —
Dividends Paid, Common Stock(168) (156)
Purchase and Retirement of Common Stock—
 (223)
Contributions from Noncontrolling Interest Owners27
 348
Proceeds from Issuance of Mezzanine Equity, Net of Offering Costs97
 —
Repayment of Senior Notes(1,096) (1,383)(9) (384)
Other(91) (64)(95) (86)
Net Cash (Used in) Provided by Financing Activities(224)
123
(Decrease) Increase in Cash and Cash Equivalents(616)
791
Cash and Cash Equivalents at Beginning of Period1,180
 1,028
Cash and Cash Equivalents at End of Period$564
 $1,819
Net Cash Provided by (Used in) Financing Activities753

(266)
(Decrease) Increase in Cash, Cash Equivalents, and Restricted Cash(246)
8
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period719
 713
Cash, Cash Equivalents, and Restricted Cash at End of Period$473
 $721

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    
 Common 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
Net (Loss) Income—
 —
 —
 —
 (10) 18
 8
Stock-based Compensation—
 21
 —
 —
 —
 —
 21
Dividends (12 cents per share)—
 —
 —
 —
 (58) —
 (58)
Distributions to Noncontrolling Interest Owners—
 —
 —
 —
 —
 (19) (19)
Contributions from Noncontrolling Interest Owners—
 —
 —
 —
 —
 11
 11
Other—
 4
 1
 —
 —
 (7) (2)
June 30, 20195
 8,244
 (31) (735) 1,546
 1,075
 10,104
Net Income—
 —
 —
 —
 17
 19
 36
Stock-based Compensation—
 16
 —
 —
 —
 —
 16
Dividends (12 cents per share)—
 —
 —
 —
 (57) —
 (57)
Distributions to Noncontrolling Interest Owners—
 —
 —
 —
 —
 (19) (19)
Contributions from Noncontrolling Interest Owners—
 —
 —
 —
 —
 6
 6
Other—
 (2) 1
 —
 —
 (2) (3)
September 30, 2019$5
 $8,258
 $(30) $(735) $1,506
 $1,079
 $10,083

 Attributable to Noble Energy    
 
Common
Stock
 
Additional
Paid in
Capital
 
Accumulated Other
Comprehensive
Loss
 
Treasury
Stock at
Cost
 
Retained
Earnings
 
Non-
controlling Interests
 Total Equity
December 31, 2016$5
 $6,450
 $(31) $(692) $3,556
 $312
 $9,600
Net (Loss) Income—
 —
 —
 —
 (1,612) 46
 (1,566)
Clayton Williams Energy Acquisition—
 1,876
 —
 (25) —
 —
 1,851
Stock-based Compensation—
 80
 —
 —
 —
 —
 80
Dividends (30 cents per share)—
 —
 —
 —
 (141) —
 (141)
Issuance of Noble Midstream Partners Common Units, Net of Offering Costs—
 —
 —
 —
 —

138
 138
Distributions to Noncontrolling Interest Owners—
 —
 —
 —
 —
 (19) (19)
Other—
 9
 2
 (11) —
 —
 —
September 30, 2017$5
 $8,415
 $(29) $(728) $1,803
 $477
 $9,943
              
December 31, 2015$5
 $6,360
 $(33) $(688) $4,726
 $—
 $10,370
Net (Loss) Income—
 —
 —
 —
 (746) 1
 (745)
Stock-based Compensation—
 57
 —
 —
 —
 —
 57
Dividends (30 cents per share)—
 —
 —
 —
 (129) —
 (129)
Issuance of Noble Midstream Partners Common Units, Net of Offering Costs—
 —
 —
 —
 —
 299
 299
Other—
 —
 1
 (8) —
 —
 (7)
September 30, 2016$5
 $6,417
 $(32) $(696) $3,851
 $300
 $9,845

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    
 Common Stock Additional Paid in Capital Accumulated Other Comprehensive Loss Treasury Stock at Cost Retained Earnings Non-controlling Interests Total Equity
December 31, 2017$5
 $8,438
 $(30) $(725) $2,248
 $683
 $10,619
Net Income—
 —
 —
 —
 554
 20
 574
Stock-based Compensation—
 17
 —
 —
 —
 —
 17
Dividends (10 cents per share)—
 —
 —
 —
 (48) —
 (48)
Purchase and Retirement of Common Stock—
 (67) —
 —
 —
 —
 (67)
Clayton Williams Energy Acquisition—
 (25) —
 —
 —
 —
 (25)
Distributions to Noncontrolling Interest Owners—
 —
 —
 —
 —
 (11) (11)
Contributions from Noncontrolling Interest Owners—
 —
 —
 —
 —
 331
 331
Other—
 —
 1
 (6) —
 2
 (3)
March 31, 2018$5
 $8,363
 $(29) $(731) $2,754
 $1,025
 $11,387
Net (Loss) Income—
 —
 —
 —
 (23) 17
 (6)
Stock-based Compensation—
 29
 —
 —
 —
 —
 29
Dividends (11 cents per share)—
 —
 —
 —
 (54) —
 (54)
Purchase and Retirement of Common Stock—
 (63) —
 —
 —
 —
 (63)
Distributions to Noncontrolling Interest Owners—
 —
 —
 —
 —
 (11) (11)
Contributions from Noncontrolling Interest Owners—
 —
 —
 —
 —
 —
 —
Other—
 —
 1
 —
 —
 (2) (1)
June 30, 2018$5
 $8,329
 $(28) $(731) $2,677
 $1,029
 $11,281
Net Income—
 —
 —
 —
 227
 21
 248
Stock-based Compensation—
 17
 —
 —
 —
 —
 17
Dividends (11 cents per share)—
 —
 —
 —
 (54) —
 (54)
Purchase and Retirement of Common Stock—
 (103) —
 —
 —
 —
 (103)
Distributions to Noncontrolling Interest Owners—
 —
 —
 —
 —
 (13) (13)
Contributions from Noncontrolling Interest Owners—
 —
 —
 —
 —
 17
 17
Other—
 6
 1
 —
 —
 (6) 1
September 30, 2018$5
 $8,249
 $(27) $(731) $2,850
 $1,048
 $11,394

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;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 September 30, 20172019 and December 31, 20162018 and for the three and nine months ended September 30, 20172019 and 20162018 contain all normally recurring adjustments considered necessary for a fair presentation of our financial position, results of operations, cash flows and shareholders’ equity for such periods. Certain prior-period amounts have been reclassified to conform to the current period presentation. For the periods presented, activity within other comprehensive income or loss was de minimis; therefore, net income or loss is materially consistent with comprehensive income or loss.
In Note 11. Segment Information, we report a new Midstream segment, established second quarter 2017, and present prior period amounts on a comparable basis. Certain other prior-period amounts have been reclassified to conform to the current period presentation.
Operating results for the three and nine months ended September 30, 20172019 are not necessarily indicative of the results that may be expected for the year ending December 31, 2017.2019.
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, 2016.2018.
ConsolidationOur 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.
Consolidated VIENoble Energy has determined that the partners with equity at risk in Noble Midstream Partners LP (NYSE: NBLX) (Noble Midstream Partners) lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact Noble Midstream Partners' economic performance; therefore, Noble Midstream Partners is considered a VIE. Through Noble Energy's ownership interest in Noble Midstream GP LLC (the General Partner to Noble Midstream Partners), Noble Energy has the authority to direct the activities that most significantly affect economic performance and the obligation to absorb losses or the right to receive benefits that could be potentially significant to Noble Midstream Partners. Therefore, Noble Energy is considered the primary beneficiary and consolidates Noble Midstream Partners.
Goodwill As of September 30, 2017, our consolidated balance sheet includes goodwill of $1.3 billion. This goodwill resulted from the acquisition (Clayton Williams Energy Acquisition) of Clayton Williams Energy, Inc. (Clayton Williams Energy) completed on April 24, 2017, and represents the excess of the consideration paid for Clayton Williams Energy over the net amounts assigned to identifiable assets acquired and liabilities assumed. All of our recorded goodwill is assigned to the Texas reporting unit. See Note 3. Clayton Williams Energy Acquisition.
Goodwill is not amortized to earnings but is qualitatively assessed for impairment. We assess goodwill for impairment annually during the third quarter, or more frequently as circumstances require, at the reporting unit level. If, based on our qualitative procedures, it is more likely than not that the fair value of the reporting unit is less than its carrying amount, we perform the two-step goodwill impairment test. The two-step goodwill impairment test is also performed whenever events or changes in circumstances indicate that the carrying value may not be recoverable. It is possible that goodwill could become impaired in the future if commodity prices or other economic factors decline. See Recently Issued Accounting Standards – Intangibles – Goodwill and Other: Simplifying the Test for Goodwill Impairment, below, for newly issued accounting guidance regarding future goodwill impairment testing.
We conducted a qualitative goodwill impairment assessment as of September 30, 2017 by examining relevant events and circumstances which could have a negative impact on our goodwill such as: macroeconomic conditions as pertinent to current and expected regulations, industry and market conditions, including overall global and regional supply and demand and impact of such on commodity prices; as well as microeconomic factors relevant to the enterprise such as cost factors that have a negative effect on earnings and cash flows, overall financial performance, reporting unit dispositions, acquisitions, portfolio
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)



restructuring and other decisions / circumstances specific to the entity and the reporting unit containing goodwill. Certain negative indicators included the current commodity price environment (driven by several macroeconomic factors) coupled with onshore service cost inflation resulting in pressure on operating margins impacting our financial results associated with the Texas reporting unit and our stock price. However, we in turn also noted positive indicators such as our current and future drilling and development plans for our Texas assets, synergies we expect from the Clayton Williams Energy Acquisition driven by our unconventional expertise and position in the adjacent properties which further increase opportunities to drill longer lateral wells on our combined acreage positions, which would contribute to profitability. Furthermore, we see value creation to be derived from expected midstream build-out opportunities for the gathering, processing and servicing of future production in the Delaware basin. Having assessed the totality of such events and circumstances described above, we determined that while there exist certain negative factors, the overall qualitative assessment did not indicate that it is more likely than not that the fair value of the reporting unit is less than its carrying value. However, regardless of the outcome of the qualitative review, we decided to proceed with the conduct of Step 1 of the impairment test as part of our annual review.
As such, we performed Step 1 of the goodwill impairment test, used to identify potential impairment. The result of the Step 1 test indicated that the fair value of the Texas reporting unit exceeded its carrying value, including goodwill, by approximately 6% and therefore, the Texas reporting unit goodwill was not considered to be impaired as of September 30, 2017.
If, in the future, we dispose of a reporting unit or a portion of a reporting unit that constitutes a business, we will include goodwill associated with that business in the carrying amount of the business in order to determine the gain or loss on disposal. The amount of goodwill allocated to the carrying amount of a business can significantly impact the amount of gain or loss recognized on the sale of that business. The amount of goodwill to be included in that carrying amount will be based on the relative fair value of the business to be disposed of and the portion of the reporting unit that will be retained.
Exit CostsWe recognize the fair value of a liability for an exit cost in the period in which a liability is incurred. Our exit costs in 2017 relate primarily to estimated costs associated with a retained Marcellus Shale firm transportation contract, for which we accrued an exit liability at June 30, 2017.
The recognition and fair value estimation of a liability requires that management take into account certain estimates and assumptions such as: the determination of whether a cease-use date has occurred (defined as the date the entity ceases using the right conveyed by the contract, for example, the right to use a leased property or to receive future goods or services); the amount, if any, of economic benefit that is expected to be obtained from a contract through partial use or release; and our estimate of costs that will continue to be incurred under the contract. We record the liability at estimated fair value, based on expected future cash outflows required to satisfy the obligation, net of estimated recoveries, and discounted. Exit costs, and associated accretion expense, are included in operating expense in our consolidated statements of operations. See Note 4. Acquisitions and Divestitures and Note 12. Commitments and Contingencies.
EstimatesThe 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.
Reserves Estimates Estimated quantitiesLeasesWe determine whether an arrangement contains a lease based on the conveyed rights and obligations at the inception date. If an agreement contains an operating or financing lease, at the commencement date, we record a right-of-use (ROU) asset and a corresponding lease liability based on the present value of crude oil, natural gas and natural gas liquids (NGL) reserves are the minimum lease payments.
As most significant of our estimates. Thereleases 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 certain estimates and judgments regarding the lease term and lease payments, noted below.
Lease Term Leases with an initial term of 12 months or less are numerous uncertainties inherent in estimating quantitiesnot 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 proved crude oil, natural gasour leases include an option for early termination. We include renewal periods and NGL reserves. The accuracyexclude termination periods from our lease term if, at commencement, it is reasonably likely that we will exercise the option.
Lease Payments Certain of any reserves estimate is a function of the quality of available engineering and geoscience information and also interpretation of the provided data. As a result, reserves estimates may be different from the quantities of crude oil, natural gas and NGLsour lease agreements include rental payments that are ultimately recovered.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 contractual standby rate, which is the fixed, minimum monthly payment, as opposed to the operating rate, which varies depending on the asset's use.
During the first nine months of 2017,Additionally, we recorded the following significant changes in our proved reserves estimates:
Leviathan Field In second quarter 2017, we recorded proved undeveloped reserves of 551 MMBoe, net,have lease agreements that include lease and non-lease components, such as equipment maintenance, which are generally accounted for the Leviathan field, offshore Israel, upon approval and sanction of the first phase of development, and are expecting to initiate natural gas production by the end of 2019.
Tamar Field In third quarter 2017, we completed additional reservoir modeling reflecting integration of the Tamar 8 well results into our geologic modeling across the reservoir and, as a result, we added one Tcfe, gross, or 48 MMBoe, net,single lease component. For these leases, lease payments include all fixed payments stated within the contract. For other leases, such as office space, lease and non-lease components are accounted for the Tamar Field, offshore Israel, of proved developed natural gas reserves as of September 30, 2017.
Delaware Basin We recorded net proved reserves of approximately 86 MMBoe, of which approximately 17 MMBoe are proved developed reserves and 69 MMBoe are proved undeveloped reserves as of June 30, 2017 related to the Clayton Williams Energy Acquisition.
separately. Our lease agreements do not contain any material residual value guarantees that would impact our lease payments.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)




Marcellus Shale The Marcellus Shale upstream divestiture resulted in a decrease in net proved reserves of approximately 241 MMBoe as of June 30, 2017, of which approximately 190 MMBoe were proved developed reserves and 51 MMBoe were proved undeveloped reserves.
Recently Issued Accounting Standards
Revenue RecognitionIn May 2014, the FASB issued Accounting Standards Update No. 2014-09 (ASU 2014-09), which creates Topic 606, Revenue from Contracts with Customers. In summary,We recognize revenue recognition would occur upon the transfer of promised goods or services to customers inat an amount that reflects the consideration to which the entity expectswe expect to be entitled to in exchange for thosetransferring goods or services. Additionally, ASU 2014-09 requires enhanced financial statement disclosures over revenue recognition.services to a customer, using a five-step process, in accordance with ASC 606 –Revenue from Contracts with Customers (ASC 606).
We continueUnder ASC 606, remaining performance obligations represent the transaction price of firm sales arrangements for which volumes have not been delivered. In Israel, certain of our Tamar natural gas contracts have fixed annual sales volumes and fixed base pricing with annual index escalations. The following table includes estimated revenues, as of September 30, 2019, for those agreements. Our actual future sales volumes may exceed future minimum volume commitments.
(millions)Remainder of 2019 2020 Total
Natural Gas Revenues (1)
$36
 $199
 $235
(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.
Redeemable Noncontrolling InterestIn March 2019, Noble Midstream Partners secured a $200 million equity commitment (preferred equity) from GIP CAPS Dos Rios Holding Partnership, L.P. (GIP) to evaluate the impactfund capital contributions in connection with Noble Midstream Partners’ 30% equity investment in EPIC Crude Holdings, LP (EPIC Crude Holdings). GIP funded $100 million of the ASU on our accounting policies, internal controls,commitment, with associated offering costs of $3 million, and consolidated financial statementsthe remaining $100 million is available for a one year period, subject to certain conditions precedent. The preferred equity is perpetual and related disclosures. We are performinghas a review of contracts6.5% annual dividend rate, payable quarterly in cash, with the ability to defer payment during the first two years following the closing. Noble Midstream Partners can redeem the preferred equity in whole or in part at any time for each of our revenue streams and developing accounting policies to address the provisionscash at a predetermined redemption price. GIP can request redemption of the ASU. Currently, we dopreferred equity following the later of the sixth anniversary of the preferred equity closing or the fifth anniversary of the EPIC crude oil pipeline completion date at a pre-determined base return.
As GIP’s redemption right is outside of Noble Midstream Partners’ control, the preferred equity is not have any contracts that would requireconsidered to be a change from the entitlements method, historically used for certain domestic natural gas sales, to the sales methodcomponent of accounting. The ASU also includes provisions regarding future revenues and expenses under a gross-versus-net presentation. We are evaluating the impact, if any,equity on the presentationconsolidated balance sheet and, therefore, is reported as mezzanine equity. In addition, because the preferred equity was issued by a subsidiary of our future revenuesNoble Midstream Partners and expenses under this gross-versus-net presentation guidance. Based upon assessments performedis held by a third party, it is considered a redeemable noncontrolling interest. Subsequent to date,issuance, we do not expectaccrete changes in the ASU to have a material effect on the timing of revenue recognition or our financial position. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. We will adopt the new standard on January 1, 2018, using the modified retrospective approach with a cumulative adjustment to retained earnings as necessary.
Compensation – Stock Compensation (Topic 718): Scope of Modification Accounting In May 2017, the FASB issued Accounting Standards Update No. 2017-09 (ASU 2017-09) Compensation – Stock Compensation (Topic 718). The purpose of this update is to provide clarity as to which modifications of awards require modification accounting under Topic 718, whereas previously issued guidance frequently resulted in varying interpretations and a diversity of practice. An entity should employ modification accounting unless the following are met: (1) the fairredemption value of the award ispreferred equity from the same immediately before and afterdate of issuance to the award is modified; (2) the vesting conditions are the same under both the modified award and the original award; and (3) the classificationearliest redemption date of the modified awardpreferred equity. The accretion is the same as the original award, either equity or liability. Regardless of whether modification accounting is utilized, award disclosure requirements under Topic 718 remain unchanged. ASU 2017-09 will be effective for annual or any interim periods beginning after December 15, 2017. We do not believe adoption of ASU 2017-09 will have a material impact on our financial statements. We will adopt the new standard on the effective date of January 1, 2018.offset against additional paid in capital. See Note 4. Acquisitions and Divestitures and Note 13. Fair Value Measurements and Disclosures.
Business Combinations: Clarifying the Definition of a BusinessIn January 2017, the FASB issuedRecently Issued Accounting Standards Update No. 2017-01 (ASU 2017-01): Business Combinations – Clarifying the Definition of a Business, that assists in determining whether certain transactions should be accounted for as acquisitions or dispositions of assets or businesses. The amendment provides a screen to be applied to the fair value of an acquisition or disposal to evaluate whether the assets in question are simply assets or if they meet the requirements of a business. If the screen is not met, no further evaluation is needed. If the screen is met, certain steps are subsequently taken to make the determination. This ASU is designed to reduce the number of transactions to be accounted for as business transactions, which take more time and cost more to analyze than asset transactions. This ASU is effective for annual and interim periods beginning after December 15, 2017 and is required to be applied prospectively. Our current Clayton Williams Energy Acquisition is not impacted by this guidance and we will apply the new guidance to applicable and qualifying transactions after our adoption on January 1, 2018.
Statement of Cash Flows: Restricted CashFinancial Instruments: Credit Losses In November 2016, the FASB issued Accounting Standards Update No. 2016-18 (ASU 2016-18): Statement of Cash Flows – Restricted Cash, which requires amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the total beginning and ending amounts for the periods shown on the statement of cash flows. This ASU will be effective for annual and interim periods beginning after December 15, 2017, with earlier application permitted. We do not believe adoption of ASU 2016-18 will have a material impact on our statement of cash flows and related disclosures. We will adopt the new standard on the effective date of January 1, 2018.
Statement of Cash Flows: Classification of Certain Cash Receipts and Cash PaymentsIn August 2016, the FASB issued Accounting Standards Update No. 2016-15 (ASU 2016-15): Statement of Cash Flows – Classification of Certain Cash Receipts and Cash Payments, to clarify how eight specific cash receipt and cash payment transactions should be presented in the statement of cash flows. ASU 2016-15 will be effective for annual and interim periods beginning after December 15, 2017, with earlier application permitted. We do not believe adoption of ASU 2016-15 will have a material impact on our statement of cash flows and related disclosures as this update pertains to classification of items and is not a change in accounting principle. We will adopt the new standard on the effective date of January 1, 2018.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)



LeasesIn FebruaryJune 2016, the Financial 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 current expected credit losses. The standard applies to a broad scope of financial instruments, including financial assets measured at amortized cost and off-balance sheet credit exposures not accounted for as insurance, such as financial guarantees and other unfunded loan commitments. ASU 2016-13 is effective for fiscal years beginning after December 15, 2019, with early adoption permitted.
We are executing an implementation plan, which includes data collection, contract review and assessment, and determination of necessary systems, processes and internal controls. Although we continue to evaluate ASU 2016-03, based on our current credit portfolio, we do not believe adoption of the standard will have a material impact on our financial statements.
Recently Adopted Accounting Standards
LeasesIn February 2016, the FASB issued Accounting Standards Update No. 2016-02 (ASU 2016-02): Leases. , which created Topic 842 – Leases (ASC 842). The guidancestandard requires lessees to recognize assetsa ROU asset and liabilitieslease liability on the balance sheet for the rights and obligations created by leases with terms of more than 12 months. This ASUleases. 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 which those natural resources are contained.
The new standard will be effectiveprovided 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 annualexisting land easements under previous accounting policy; and interim periods beginning after December 15, 2018, with earlier application permitted.
In the normal coursepractical expedient to not separate lease and non-lease components for the majority of business, we enter into capitalour 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 method and recorded ROU assets and lease liabilities of $282 million and $287 million, respectively, primarily related to operating lease agreements to supportleases. The $5 million difference between these amounts was recorded as other operating expense. Our accounting for finance leases remains substantially unchanged. Adoption did not materially impact our exploration and developmentconsolidated statement of operations and lease assets such as drilling rigs, platforms, storage facilities, field servicescomprehensive income and well equipment, pipeline capacity, office space and other assets. At this time, we cannot reasonably estimate the financial impact this ASU will have on our financial statements; however, we believe adoption and implementation of this ASU will have a materialhad no impact on our balance sheet resulting from an increase in both assetsconsolidated statement of cash flows. See Note 8. Leases.
Derivatives and liabilities relatingHedging – Targeted Improvements to our leasing activities. As part of our assessment to date, we have formed an implementation work team, prepared educational and training materials pertinent to this ASU and have begun contract review and documentation. We will adopt the new standard on the effective date of January 1, 2019.
Intangibles – Goodwill and Other: Simplifying the TestAccounting for Goodwill Impairment Hedging Activities In JanuaryAugust 2017, the FASB issued Accounting Standards Update No. 2017-042017-12 (ASU 2017-04)2017-12):Intangibles 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 and makes certain targeted improvements to simplify application of hedge accounting guidance in US GAAP. Adoption of this ASU on January 1, 2019 did not have an impact on our financial statements.
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 guidance, an entity will perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount, with an impairment charge being recognized for the 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 and have not yet determined if we will early adopt.
Financial Instruments: Credit Losses Other—Internal-Use SoftwareIn June 2016,August 2018, the FASB issued Accounting Standards Update No. 2016-132018-15 (ASU 2016-13)2018-15): Financial Instruments – Credit Losses, which replacesIntangibles—Goodwill and Other—Internal-Use Software to align the requirements for capitalizing implementation costs incurred loss impairment methodology in current US GAAPa hosting arrangement that is a service contract with a methodology that reflects expected credit losses. The update is intendedthe requirements for capitalizing implementation costs incurred to provide financial statement users with more useful information about expected credit losses.develop or obtain internal-use software. The amended guidancestandard is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. We are currently evaluatingused the effect, if any, that the guidance willprospective method to early adopt this ASU in second quarter 2019, which did not have a material impact on our consolidated financial statements.
Statements of Operations InformationOther statements and related disclosures. We will adopt the new standard on the effective date of January 1, 2020.operations information is as follows:
 Three Months Ended September 30, Nine Months Ended September 30,
(millions)2019 2018 2019 2018
Other Revenue 
  
    
Income from Equity Method Investments and Other$10
 $44
 $43
 $140
Midstream Services Revenues – Third Party19
 21
 63
 49
Total$29
 $65
 $106
 $189
Production Expense 
  
    
Lease Operating Expense$132
 $124
 $405
 $411
Production and Ad Valorem Taxes52
 47
 142
 151
Gathering, Transportation and Processing Expense108
 97
 306
 292
Other Royalty Expense5
 5
 9
 32
Total$297
 $273
 $862
 $886
Other Operating Expense, Net       
Exploration Expense$25
 $25
 $82
 $89
Marketing Expense7
 11
 26
 21
Firm Transportation Exit Cost—
 —
 92
 —
Other, Net29
 (9) 57
 (3)
Total$61
 $27
 $257
 $107


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




Statements of OperationsBalance Sheet InformationOther statements of operationsbalance sheet information is as follows:
 Three Months Ended September 30, Nine Months Ended September 30,
(millions)2017 2016 2017 2016
Production Expense 
  
    
Lease Operating Expense$151
 $131
 $414
 $412
Production and Ad Valorem Taxes36
 30
 119
 73
Gathering, Transportation and Processing Expense (1)
93
 121
 333
 354
Total$280
 $282
 $866
 $839
Exploration Expense       
Leasehold Impairment and Amortization (2)
$33
 $96
 $51
 $127
Dry Hole Cost (3)
2
 5
 2
 105
Seismic, Geological and Geophysical7
 15
 20
 47
Staff Expense11
 15
 40
 53
Other11
 (6) 23
 44
Total$64
 $125
 $136
 $376
Loss on Marcellus Shale Upstream Divestiture (4)
       
Loss on Sale$—
 $—
 $2,270
 $—
Firm Transportation Commitment (5)
—
 —
 41
 —
Other (6)
4
 —
 15
 —
Total$4
 $—
 $2,326
 $—
Other Operating Expense, Net (7)
       
Marketing Expense (1) (8)
$6
 $12
 $39
 $39
Clayton Williams Energy Acquisition Expenses (9)
4
 —
 98
 —
Loss on Asset Due to Terminated Contract (10)
—
 —
 —
 47
North Sea Remediation Project Revision (11)
(42) —
 (42) —
Other, Net17
 25
 37
 41
Total$(15) $37
 $132
 $127
(millions)September 30,
2019		 December 31,
2018
Accounts Receivable, Net   
Commodity Sales$405
 $383
Joint Interest Billings177
 137
Other103
 111
Allowance for Doubtful Accounts(8) (15)
Total$677
 $616
Other Current Assets 
  
Commodity Derivative Assets$90
 $180
Inventories, Materials and Supplies74
 55
Assets Held for Sale (1)
—
 133
Prepaid Expenses and Other Current Assets113
 50
Total$277
 $418
Other Noncurrent Assets 
  
Equity Method Investments (2)
$959
 $286
Operating Lease Right-of-Use Assets (3)
275
 —
Customer-Related Intangible Assets, Net (4)
286
 310
Goodwill (4)
110
 110
Other Assets, Noncurrent150
 135
Total$1,780
 $841
Other Current Liabilities 
  
Production and Ad Valorem Taxes$147
 $103
Asset Retirement Obligations89
 118
Interest Payable87
 66
Operating Lease Liabilities (3)
97
 —
Commercial Paper Borrowings511
 —
Other Liabilities, Current259
 232
Total$1,190
 $519
Other Noncurrent Liabilities 
  
Deferred Compensation Liabilities$148
 $147
Asset Retirement Obligations699
 762
Operating Lease Liabilities (3)
209
 —
Firm Transportation Exit Cost Accrual (5)
133
 67
Other Liabilities, Noncurrent149
 189
Total$1,338
 $1,165
(1) 
Certain of our gathering and processing expenses were historically presented as components of other operating expense, net, in our consolidated statements of operations. Beginning in 2017, we have changed our presentation to reflect these as components of production expense. These costs are now included within gathering, transportation and processing expense. For the three and nine months ended September 30, 2017, these costs totaled $12 million and $17 million, respectively. For the three and nine months ended September 30, 2016, these costs totaled $8 million and $19 million, respectively, and have been reclassified from marketing expense to conform
Assets held for sale at December 31, 2018 related to the current presentation.
(2)
first quarter 2019 divestiture of non-core acreage in Reeves County, Texas. See Note 8. Capitalized Exploratory Well Costs4. Acquisitions and Undeveloped Leasehold CostsDivestitures.
(3)(2) 
For the nine months ended September 30, 2016, amount related primarily to the Silvergate exploratory well, Gulf of Mexico, and the Dolphin 1 natural gas discovery, offshore Israel.
(4)
SeeNote 4. Acquisitions and Divestitures.
(5)(3) 
Amount represents expense relatedAmounts relate to an unutilized firm transportation commitment associated withassets and liabilities recorded as a Marcellus Shale firm transportation contract.result of ASC 842 adoption in first quarter 2019. See Note 12. Commitments and Contingencies8. Leases.
(6)(4) 
Amount includes costs for legal and advisory services and employee severance charges.
(7)
(Gain)/Loss on debt extinguishment was historically presented as a component of other operating expense, net in our consolidated statements of operations. Beginning with third quarter 2017, we have changed our presentation to reflect these as a separate line item within other expense (income) below operating loss. The prior periods have been reclassified to conform to that presentation. 
(8)
Amounts represent expense for unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments.
(9)
Amounts relate to assets acquired in the first quarter 2018 Saddle Butte acquisition. Intangible asset balances at September 30, 2019 and December 31, 2018 are net of accumulated amortization of $54 million and $30 million, respectively. See Note 3. Clayton Williams Energy Acquisition4. Acquisitions and Divestitures.
(10)(5) 
Amounts relate to the termination and final settlement of a rig contract for offshore Falkland Islands as a result of a supplier's non-performance.
(11)
See Note 9. Asset Retirement ObligationsExit Cost – Transportation Commitments.


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



Balance Sheet InformationOther balance sheet information is as follows:
(millions)September 30,
2017		 December 31,
2016
Accounts Receivable, Net   
Commodity Sales$403
 $403
Joint Interest Billings183
 106
Proceeds Receivable (1)
—
 40
Other106
 86
Allowance for Doubtful Accounts(17) (20)
Total$675
 $615
Other Current Assets 
  
Inventories, Materials and Supplies$61
 $71
Inventories, Crude Oil17
 18
Assets Held for Sale (2)
180
 18
Restricted Cash (3)
—
 30
Prepaid Expenses and Other Current Assets45
 23
Total$303
 $160
Other Noncurrent Assets 
  
Equity Method Investments$286
 $400
Mutual Fund Investments70
 71
Other Assets, Noncurrent60
 37
Total$416
 $508
Other Current Liabilities 
  
Production and Ad Valorem Taxes$118
 $115
Commodity Derivative Liabilities4
 102
Income Taxes Payable13
 53
Asset Retirement Obligations (4)
50
 160
Interest Payable82
 76
Current Portion of Capital Lease Obligations65
 63
Foreign Sales Tax Payable29
 14
Compensation and Benefits Payable87
 110
Theoretical Withdrawal Premium25
 18
Other Liabilities, Current (5)
26
 31
Total$499
 $742
Other Noncurrent Liabilities 
  
Deferred Compensation Liabilities$216
 $218
Asset Retirement Obligations (4)
894
 775
Marcellus Shale Firm Transportation Commitment (6)
31
 —
Production and Ad Valorem Taxes49
 47
Other Liabilities, Noncurrent55
 63
Total$1,245
 $1,103
(1)
Balance at December 31, 2016 related to the farm-out of a 35% interest in Block 12 offshore Cyprus; proceeds were received in January 2017. See Note 4. Acquisitions and Divestitures.
(2)
Balance at September 30, 2017 primarily includes our equity investment in CONE Gathering, LLC. See Note 4. Acquisitions and Divestitures.
(3)
Balance at December 31, 2016 represented amount held in escrow for the purchase of certain Delaware Basin properties. The transaction closed in first quarter 2017. See Note 4. Acquisitions and Divestitures.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)




(4)
Reclassification from current to noncurrent is driven primarily by a change in expected timing of abandonment activities in the Gulf of Mexico. See Note 9. Asset Retirement Obligations.
(5)
Balance at September 30, 2017 includes $8 million associated with the current portion of the Marcellus Shale firm transportation commitment. See Note 12. Commitments and Contingencies.
(6)
See Note 12. Commitments and Contingencies.


Note 3. Clayton Williams Energy Acquisition
In January 2017, we announced the Clayton Williams Energy Acquisition, which was approved by Clayton Williams Energy stockholdersReconciliation of Total Cash We define total cash as cash, cash equivalents and closed on April 24, 2017. Acquired assets include 71,000 highly contiguous net acres in the core of the Delaware Basin adjacent to our Reeves County holdings in Texas, and an additional 100,000 net acres in other areas of the Permian and Midland Basins. In total, the acquisition increased our Delaware Basin position to approximately 118,000 net acres.
We recorded net proved reserves of approximately 86 MMBoe, of which approximately 17 MMBoe are proved developed reserves and 69 MMBoe are proved undeveloped reserves, as of June 30, 2017. In addition, upon closing of the acquisition, approximately 64,000 net acres in Reeves County, Texas were dedicated to Noble Midstream Partners for infield crude oil, natural gas and produced water gathering.
The acquisition was effected through the issuance of approximately 56 million shares of Noble Energy common stock with a fair value of approximately $1.9 billion and cash consideration of $637 million, for total consideration of approximately $2.5 billion, in exchange for all outstanding Clayton Williams Energy shares, including stock options, restricted stock awards and warrants. The closing price of our stock on the New York Stock Exchange (NYSE) was $34.17 on April 24, 2017. In connection with the transaction, we borrowed $1.3 billion under our Revolving Credit Facility (defined below) to fund the cash portion of the acquisition consideration, redeem outstanding Clayton Williams Energy debt, pay associated make-whole premiums and pay related fees and expenses. See Note 6. Debt.
In connection with the Clayton Williams Energy Acquisition, we have incurred acquisition-related costs of $98 million to date, including $64 million of severance, consulting, investment, advisory, legal and other merger-related fees, and $34 million of noncash share-based compensation expense, all of which were expensed and are included in other operating expense, net in our consolidated statements of operations. In addition, we received approximately 720,000 shares of common stock from Clayton Williams Energy shareholders for the payment of withholding taxes due on the vesting of their restricted shares and options pursuant to the purchase and sale agreement, resulting in a $25 million increase in our treasury stock balance.
Purchase Price Allocation The transaction has been accounted for as a business combination, using the acquisition method.cash. The following table represents the preliminary allocationprovides a reconciliation of the total purchase price of Clayton Williams Energy to the identifiable assets acquired and the liabilities assumed based on the fair values at the acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill. Any value assigned to goodwill is not expected to be deductible for income tax purposes.cash:
 Nine Months Ended September 30,
(millions)2019 2018
Cash and Cash Equivalents at Beginning of Period$716
 $675
Restricted Cash at Beginning of Period3
 38
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period$719
 $713
Cash and Cash Equivalents at End of Period$473
 $720
Restricted Cash at End of Period—
 1
Cash, Cash Equivalents, and Restricted Cash at End of Period$473
 $721
Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, valuation of pre-merger contingencies, final tax returns that provide the underlying tax basis of Clayton Williams Energy's assets and liabilities, and 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.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)



The following table sets forth our preliminary purchase price allocation:
(millions, except per share amounts) 
Fair Value of Common Stock Issued$1,876
Plus: Cash Consideration Paid to Clayton Williams Energy Stockholders637
Total Purchase Price$2,513
Plus Liabilities Assumed by Noble Energy: 
Accounts Payable67
Other Current Liabilities38
Long-Term Deferred Tax Liability520
Long-Term Debt595
Asset Retirement Obligations58
Total Purchase Price Plus Liabilities Assumed$3,791

The fair value of Clayton Williams Energy's identifiable assets is as follows:
(millions) 
Cash and Cash Equivalents$21
Other Current Assets63
Oil and Gas Properties: 
Proved Reserves722
Undeveloped Leasehold Cost1,571
Gathering and Processing Assets48
Asset Retirement Costs58
Other Noncurrent Assets13
Implied Goodwill1,295
Total Asset Value$3,791
In connection with the acquisition, we assumed, and then subsequently retired, $595 million of Clayton Williams Energy long-term debt. 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 are 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 are the most sensitive and may be subject to change.
Based upon the preliminary purchase price allocation, we have recognized $1.3 billion of goodwill, all of which is assigned to the Texas reporting unit. As a result of the acquisition, we expect to realize certain synergies which may result from our control of the combined assets as well as future midstream opportunities. The oil-rich geology of these assets, coupled with our unconventional expertise and position in the adjacent properties, significantly enhances our crude oil focus and growth outlook. The acquisition provides for synergies related to administrative and capital efficiencies, and increased opportunities to drill longer lateral wells on our combined acreage positions, enhances our crude oil production base and future crude oil growth potential. It also adds to our midstream assets and provides future midstream build-out opportunities for the gathering, processing and servicing of future production in the basin.
The results of operations attributable to Clayton Williams Energy are included in our consolidated statements of operations beginning on April 24, 2017. We generated revenues of $56 million and a pre-tax loss of $14 million from the Clayton Williams Energy assets during the period April 24, 2017 to September 30, 2017.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)



Pro Forma Financial InformationThe 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, 2016. 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.
Additionally, pro forma earnings for the three and nine months ended September 30, 2017 were adjusted to exclude acquisition-related costs of $4 million and $98 million, respectively, incurred by Noble Energy and $23 million, incurred by Clayton Williams Energy in second quarter 2017. 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 Acquisition taken place on January 1, 2016; furthermore, the financial information is not intended to be a projection of future results.
 Three Months Ended September 30, Nine Months Ended September 30,
(millions, except per share amounts)
2017 (1)
 2016 2017 2016
Revenues$960
 $964
 $3,102
 $2,605
Net Loss and Comprehensive Loss Attributable to Noble Energy(133) (193) (1,561) (860)
        
Net Loss Attributable to Noble Energy per Common Share       
Basic and Diluted$(0.27) $(0.40) $(3.21) $(1.77)
(1)
Adjusted for $4 million acquisition-related costs, net of 35% tax, incurred during third quarter 2017.



Note 3. Segment Information
We 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 (Canada, New Ventures and 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 assess the performance of Noble Energy's reportable segments as management believes this measure provides useful information in assessing our operating and financial performance across periods.
Expenses related to debt, such as interest and other debt-related costs, headquarters depreciation, corporate general and administrative expenses, exit costs and certain costs associated with mitigating the effects of our retained Marcellus Shale transportation agreements, 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 September 30, 2019              
Crude Oil Sales$724
 $645
 $1
 $78
 $—
 $—
 $—
 $—
NGL Sales78
 78
 —
 —
 —
 —
 —
 —
Natural Gas Sales201
 79
 118
 4
 —
 —
 —
 —
Total Crude Oil, NGL and Natural Gas Sales1,003
 802
 119
 82
 —
 —
 —
 —
Sales of Purchased Oil and Gas87
 22
 —
 —
 —
 47
 —
 18
Income (Loss) from Equity Method Investments and Other10
 1
 —
 14
 —
 (5) —
 —
Midstream Services Revenues – Third Party
19
 —
 —
 —
 —
 19
 —
 —
Intersegment Revenues—
 —
 —
 —
 —
 125
 (125) —
Total Revenues1,119
 825
 119
 96
 —
 186
 (125) 18
Lease Operating Expense132
 111
 7
 22
 —
 1
 (9) —
Production and Ad Valorem Taxes52
 51
 —
 —
 —
 1
 —
 —
Gathering, Transportation and Processing Expense108
 173
 1
 —
 —
 5
 (71) —
Other Royalty Expense5
 5
 —
 —
 —
 —
 —
 —
Total Production Expense297
 340
 8
 22
 —
 7
 (80) —

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

   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
Depreciation, Depletion and Amortization583
 505
 17
 21
 1
 26
 (8) 21
Cost of Purchased Oil and Gas96
 17
 —
 —
 —
 46
 —
 33
Gain on Commodity Derivative Instruments(129) (123) —
 (6) —
 —
 —
 —
Income (Loss) Before Income Taxes51
 92
 74
 56
 (17) 83
 (23) (214)
Additions to Long-Lived Assets, Excluding Acquisitions595
 377
 129
 46
 2
 56
 (26) 11
Additions to Equity Method Investments271
 —
 185
 —
 —
 86
 —
 —
Three Months Ended September 30, 2018              
Crude Oil Sales$744
 $655
 $2
 $87
 $—
 $—
 $—
 $—
NGL Sales166
 166
 —
 —
 —
 —
 —
 —
Natural Gas Sales226
 98
 122
 6
 —
 —
 —
 —
Total Crude Oil, NGL and Natural Gas Sales1,136
 919
 124
 93
 —
 —
 —
 —
Sales of Purchased Oil and Gas72
 —
 —
 —
 —
 46
 —
 26
Income from Equity Method Investments and Other44
 —
 —
 34
 —
 10
 —
 —
Midstream Services Revenues – Third Party21
 —
 —
 —
 —
 21
 —
 —
Intersegment Revenues—
 —
 —
 —
 —
 91
 (91) —
Total Revenues1,273
 919
 124
 127
 —
 168
 (91) 26
Lease Operating Expense124
 114
 7
 15
 —
 —
 (12) —
Production and Ad Valorem Taxes47
 46
 —
 —
 —
 1
 —
 —
Gathering, Transportation and Processing Expense97
 129
 —
 —
 —
 28
 (60) —
Other Royalty Expense5
 5
 —
 —
 —
 —
 —
 —
Total Production Expense273
 294
 7
 15
 —
 29
 (72) —
Depreciation, Depletion and Amortization485
 414
 16
 25
 1
 24
 (5) 10
(Gain) Loss on Divestitures, Net(193) 5
 —
 —
 —
 (198) —
 —
Cost of Purchased Oil and Gas76
 —
 —
 —
 —
 44
 —
 32
Loss on Commodity Derivative Instruments155
 140
 —
 15
 —
 —
 —
 —
Income (Loss) Before Income Taxes307
 31
 143
 68
 (17) 268
 (16) (170)
Additions to Long-Lived Assets, Excluding Acquisitions768
 535
 170
 4
 1
 82
 (22) (2)
Nine Months Ended September 30, 2019              
Crude Oil Sales$2,024
 $1,807
 $4
 $213
 $—
 $—
 $—
 $—
NGL Sales258
 258
 —
 —
 —
 —
 —
 —
Natural Gas Sales612
 259
 340
 13
 —
 —
 —
 —
Total Crude Oil, NGL and Natural Gas Sales2,894
 2,324
 344
 226
 —
 —
 —
 —

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

   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
Sales of Purchased Oil and Gas264
 64
 —
 —
 —
 132
 —
 68
Income (Loss) from Equity Method Investments and Other43
 2
 —
 46
 —
 (5) —
 —
Midstream Services Revenues – Third Party
63
 —
 —
 —
 —
 63
 —
 —
Intersegment Revenues—
 —
 —
 —
 —
 322
 (322) —
Total Revenues3,264
 2,390
 344
 272
 —
 512
 (322) 68
Lease Operating Expense405
 350
 26
 56
 —
 3
 (30) —
Production and Ad Valorem Taxes142
 138
 —
 —
 —
 4
 —
 —
Gathering, Transportation and Processing Expense306
 439
 1
 —
 —
 65
 (199) —
Other Royalty Expense9
 9
 —
 —
 —
 —
 —
 —
Total Production Expense862
 936
 27
 56
 —
 72
 (229) —
Depreciation, Depletion and Amortization1,619
 1,401
 50
 60
 1
 77
 (21) 51
Cost of Purchased Oil and Gas296
 59
 —
 —
 —
 125
 —
 112
Firm Transportation Exit Cost92
 —
 —
 —
 —
 —
 —
 92
Loss on Commodity Derivative Instruments23
 7
 —
 16
 —
 —
 —
 —
(Loss) Income Before Income Taxes(294) (85) 223
 126
 (48) 202
 (52) (660)
Additions to Long-Lived Assets, Excluding Acquisitions1,954
 1,367
 380
 64
 14
 174
 (74) 29
Additions to Equity Method Investments686
 —
 185
 —
 —
 501
 —
 —
Nine Months Ended September 30, 2018              
Crude Oil Sales$2,266
 $1,972
 $6
 $288
 $—
 $—
 $—
 $—
NGL Sales449
 449
 —
 —
 —
 —
 —
 —
Natural Gas Sales694
 316
 362
 16
 —
 —
 —
 —
Total Crude Oil, NGL and Natural Gas Sales3,409
 2,737
 368
 304
 —
 —
 —
 —
Sales of Purchased Oil and Gas191
 —
 —
 —
 —
 110
 —
 81
Income from Equity Method Investments and Other140
 —
 —
 105
 —
 35
 —
 —
Midstream Services Revenues – Third Party
49
 —
 —
 —
 —
 49
 —
 —
Intersegment Revenues—
 —
 —
 —
 —
 257
 (257) —
Total Revenues3,789
 2,737
 368
 409
 —
 451
 (257) 81
Lease Operating Expense411
 354
 19
 56
 —
 —
 (18) —
Production and Ad Valorem Taxes151
 147
 —
 —
 —
 4
 —
 —
Gathering, Transportation and Processing Expense292
 389
 —
 —
 —
 71
 (168) —
Other Royalty Expense32
 32
 —
 —
 —
 —
 —
 —
Total Production Expense886
 922
 19
 56
 —
 75
 (186) —
Depreciation, Depletion and Amortization1,418
 1,214
 44
 77
 1
 62
 (13) 33

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

   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
(Gain) Loss on Divestitures, Net(859) 20
 (376) —
 —
 (503) —
 —
Asset Impairments168
 168
 —
 —
 —
 —
 —
 —
Cost of Purchased Oil and Gas204
 —
 —
 —
 —
 106
 —
 98
Loss on Commodity Derivative Instruments483
 400
 —
 83
 —
 —
 —
 —
Income (Loss) Before Income Taxes860
 (94) 678
 180
 (44) 690
 (52) (498)
Additions to Long-Lived Assets, Excluding Acquisitions2,608
 1,630
 533
 9
 3
 479
 (72) 26
September 30, 2019 
  
  
  
        
Property, Plant and Equipment, Net$18,797
 $13,170
 $3,001
 $801
 $39
 $1,682
 $(198) $302
December 31, 2018   
  
  
        
Property, Plant and Equipment, Net$18,419
 $13,044
 $2,630
 $805
 $37
 $1,742
 $(145) $306

(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.
Note 4. Acquisitions and Divestitures
2017We maintain an ongoing portfolio management program and have engaged in various transactions over recent years.
2019 Asset Transactions
Eastern Mediterranean Investment During third quarter 2019, we invested $185 million for a 25% equity interest in Eastern Mediterranean Pipeline B.V. (EMED Pipeline B.V.) in support of its planned acquisition of an approximate 39% equity interest in East Mediterranean Gas Company S.A.E. (EMG), which owns the EMG Pipeline. Upon closing of EMED Pipeline B.V.'s planned equity acquisition of EMG, which is anticipated in fourth quarter 2019, we will own an effective, indirect interest of approximately 10%, net, in EMG. The EMG Pipeline is expected to provide future connection from the Israel pipeline network to Egyptian customers and support delivery of natural gas from our producing fields offshore Israel into Egypt.
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 Reeves County, Texas. We received cash consideration of approximately $131 million, recognizing no gain or loss on the sale.
EPIC Pipeline Investments In first quarter 2019, Noble Midstream Partners exercised and closed options with EPIC Midstream Holdings, LP (EPIC) to acquire a 15% equity interest in EPIC Y-Grade, LP (EPIC Y-Grade), which is constructing the EPIC Y-Grade pipeline, and a 30% equity interest in EPIC Crude Holdings, which is constructing the EPIC crude oil pipeline. Both pipelines will transport production from the Delaware Basin to Corpus Christi, Texas. Cash consideration totaled $227 million and Noble Midstream Partners has since made additional capital contributions of $46 million and $168 million to EPIC Y-Grade and EPIC Crude Holdings, respectively, to fund its share of pipeline construction costs. These investments are accounted for using the equity method.
Delaware Crossing Joint Venture In February 2019, Noble Midstream Partners executed definitive agreements with Salt Creek Midstream LLC 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. For the first nine months of 2017,2019, Noble Midstream Partners has made capital contributions of $53 million for construction of the pipeline. This investment is accounted for using the equity method.
2018 Asset Transactions
Divestiture of Gulf of Mexico Assets  In February 2018, we engaged inannounced plans to sell our Gulf of Mexico assets for cash consideration of $480 million, along with the following asset transactions.
Marcellus Shale Upstream Divestiture On June 28, 2017, we closedassumption, by the salepurchaser, of all abandonment obligations associated with the properties. As of our Marcellus Shale upstream assets, which are primarily natural gas properties. The sales price totaled $1.2 billion, andMarch 31, 2018, we received $1.0 billion of net cash proceeds, after consideration of customary adjustments, at closing. The sales 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 shouldreduced 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. To date, conditions for the recognition of the contingent consideration are not probable and therefore, 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 6. 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 priorGulf of Mexico assets 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 where the pipeline project is currently in service. We no longer have production to satisfy this commitment and do not plan to utilize this capacity in the future. As such, we recorded a charge in accordance with accounting for exit or disposal activities under ASC 420 - Exit or Disposal Cost Obligations.$480 million. In addition, we have retained other Marcellus Shale firm transportation contracts, relating to pipeline projectscertain transaction related obligations approximating $92 million which are not yet commercially available to us. These projects are either under construction or have not yet been approved by the Federal Energy Regulatory Commission (FERC). As these projects become commercially available to us, we will assess, basedwere subsequently settled upon the facts and circumstances, the recognition of any potential exit cost liabilities. It is likely we will incur additional firm transportation, as well as other restructuring or office closure costs, associated with this exit activity in the future. See Note 2. Basis of Presentation and Note 12. Commitments and Contingencies.
For the nine months ended September 30, 2017, our consolidated statements of operations include a pre-tax loss of $2.3 billion associated with the divested Marcellus Shale upstream assets, driven by the loss on sale. For the three and nine months ended September 30, 2016, our consolidated statements of operations include a pre-tax loss of $70 million and $237 million, respectively, associated with the divested Marcellus Shale upstream assets.closing.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)




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. We received net proceeds of $383 million and recorded a loss of $24 million.
ProductionDivestiture of 7.5% Interest in Tamar Field In March 2018, we closed the sale of a 7.5% 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 $484 million and 38.5 million shares of Tamar Petroleum that had a publicly traded value of $224 million. Total consideration received from the Marcellus Shale upstream assets averaged 393 MMcfe/dsale was applied to the field's basis and 413 MMcfe/dresulted in the recognition of a pre-tax gain of $376 million and tax expense of $86 million.
In October 2018, we sold our shares in Tamar Petroleum for pre-tax proceeds of $163 million, net of transaction expenses. The sale was in accordance with the threeIsrael Natural Gas Framework and six months ended June 30, 2017. Withcompleted our obligation to reduce ownership interest in the closingTamar field from 32.5% to 25% by year end-2021.
Divestiture of Southwest Royalties In January 2018, we closed the sale we recorded a decreaseof our investment in net proved reservesSouthwest Royalties, Inc. We received proceeds of approximately 241 MMBoe,$60 million, recognizing no gain or loss on the sale.
Divestiture of which approximately 190 MMBoe were proved developed reserves and 51 MMBoe were proved undeveloped reserves as of June 30, 2017.
Marcellus Shale CONE Gathering Divestiture On May 18, 2017,In January 2018, we announcedclosed the signingsale of a definitive agreement to divest an affiliate that holds theour 50% interest in CONE Gathering LLC (CONE Gathering) and 21.7 million common and subordinated limited partnership units in CONE Midstream Partners LP (NYSE:CNNX) (CONE Midstream), for total cash consideration of $765 million.to CNX Resources Corporation. CONE Gathering owns the general partner of CONECNX 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 held 21.7 million common units, representing a 34.1% limited partnership units represent a 33.5% ownershippartner interest in CONE Midstream. CONECNX Midstream constructs, ownsPartners. During second quarter 2018, we sold 7.5 million common units, receiving net proceeds of $135 million, net of underwriting fees, and operates natural gas gatheringrecognized a gain of $109 million. During third quarter 2018, we sold the remaining 14.2 million common units, representing a 22.3% limited partner interest, in CNX Midstream Partners, receiving proceeds net of underwriting fees of approximately $248 million, and other midstream energyrecognized a gain of $198 million.
Divestiture of Greeley Crescent Assets In September 2018, we closed the sale of assets in support of Marcellus Shale activities.
In connection with the executionGreeley Crescent area of the definitive agreement to divestDJ Basin, receiving proceeds of $64 million, resulting in no gain or loss on the affiliate noted above, the other 50% owner of CONE Gathering filed suit to enjoin the transaction. A bench trial was concluded on October 20, 2017 and we are awaiting a decision from the court. We believe that the court will decide in our favor. However, given the pendency of the matter and the possibility of appeal, our ability to close the transaction as originally contemplated is uncertain at this time.sale.
We are committed to exiting the Marcellus Shale play, and going forward, our midstream efforts are primarily focused on Noble Midstream Partners supporting our DJ Basin and Delaware Basin growth areas. We believe that classification of our investment in CONE Gathering as assets held for sale as of September 30, 2017 remains appropriate.
Assets Held for Sale At September 30, 2017, assets held for sale was primarily related to $173 million for our investment in CONE Gathering.
Other US Onshore Properties We conducted the following transactions:
Onshore US Divestitures Saddle Butte Acquisition In third quarter 2017, we received proceeds of $24 million resulting from the sale of certain other onshore US properties and the remaining consideration associated with the Greeley Crescent divestiture (defined below) in the DJ Basin.
Delaware Basin Acquisition In first quarter 2017, we closed a bolt-on acquisition in the Delaware Basin for $301 million, approximately $246 million of which was allocated to undeveloped leasehold cost. The acquisition included seven producing wells, of which four are operated by us.
Noble Midstream Partners
Asset Contribution On June 26, 2017,January 2018, Noble Midstream Partners acquired an additional 15% limited partnera 54.4% interest in Blanco River DevCo LP (Blanco River DevCo)Black Diamond Gathering LLC (Black Diamond), increasing its ownership to 40%an entity formed by Black Diamond Gathering Holdings LLC, a wholly-owned subsidiary of the Blanco River DevCo LP, and acquired the remaining 20% limited partner interest in Colorado River DevCo LP (Colorado River DevCo) from us for $270 million.
Blanco River DevCo holds Noble Midstream Partners’ Delaware Basin in-fieldPartners, 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 owns a large-scale integrated 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 provides services across our development areassystem, located in the DJ Basin, including crude oilwhich we subsequently renamed the Black Diamond gathering system. Consideration totaled $681 million and natural gas gathering and water services in the Wells Ranch area and crude oil gathering in the East Pony area.Black Diamond is consolidated as a VIE.
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.
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 $67 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 isWe accounted for under the equity methodtransaction as a business combination using the acquisition method. The total purchase price was allocated to assets acquired and is included within our Midstream segment.
Noble Midstream Partners serves asliabilities assumed based on acquisition date fair values, and we recognized goodwill for the operatoramount of the Advantage Pipeline system, which includes a 70-mile crude oil pipeline inpurchase price exceeding the Delaware Basin from Reeves County, Texasfair values of the identifiable net assets acquired. The final purchase price allocation included: $206 million to Crane County, Texas with 150,000 barrels per dayproperty, plant and equipment; $340 million to customer-related intangible assets (acquired customer contracts); and $110 million to implied goodwill.
Note 5. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs
Capitalized Exploratory Well CostsThere were no significant changes to our capitalized exploratory well costs during the period. The following table provides an aging of shipping capacity (expandable to over 200,000 barrels per day) and 490,000 barrels of storage capacity.capitalized exploratory well costs based on the date that drilling commenced:
(millions, except number of projects)September 30,
2019		 December 31,
2018
Exploratory Well Costs Capitalized for a Period of One Year or Less$15
 $6
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling354
 348
Capitalized Exploratory Well Costs, End of Period$369
 $354
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling7
 7

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




Undeveloped Leasehold Costs Changes in undeveloped leasehold costs are as follows:
(millions)Nine Months Ended September 30, 2019
Undeveloped Leasehold Costs, Beginning of Period$2,306
Additions to Undeveloped Leasehold Costs63
Transfers to Proved Properties(20)
Undeveloped Leasehold Costs, End of Period$2,349

2016 Asset Transactions
During the first nine monthsAs of 2016, we engaged in the following asset transactions.
US Onshore Properties We entered into the following transactions:
Bowdoin Divestiture We closed the divestiture of our Bowdoin property in northern Montana, generating proceeds of $43September 30, 2019, undeveloped leasehold costs included $2.1 billion, $100 million, $76 million, and recognized a $23$59 million loss on sale;
Onshore US Divestitures We sold certainattributable to the Delaware Basin, Eagle Ford Shale, other US onshore properties, generating net proceedsand international properties, respectively. Certain of $20 million, which were primarily appliedthese costs pertain to the DJ Basin depletable field, with no recognition of gainacquired leases or loss;
Greeley Crescent Divestiture We entered into a purchase and sale agreement for the divestiture of certain producing and undeveloped interests covering approximately 33,100 net acres in the Greeley Crescent (Greeley Crescent divestiture) area of the DJ Basin for $505 million,licenses that are subject to customary closing adjustments. We received proceeds of $486 million during second quarter 2016, which were primarily appliedexpiration over the next several years unless production is established on the acreage. Other costs pertain to the DJ Basin depletable field, with no recognition of gain or loss. In third quarter 2017, we closed the sale of the remaining properties and received proceeds of $5 million; and
Acreage Exchange Agreement We entered into an acreage exchange agreement receiving approximately 11,700 net acres within our Wells Ranch development area in exchange for approximately 13,500 net acres primarily from our Bronco area, located southwest of Wells Ranch, with no recognition of gain or loss.
Cyprus Project (Offshore Cyprus) In first quarter 2017, we received the remaining $40 million consideration for the farm-out of a 35% interest in Block 12, which includes the Aphrodite natural gas discovery. Proceeds received, including $131 million in first quarter 2016, were applied to the Cyprus project asset with no gain or loss recognized.
Offshore Israel Assets  In first quarter 2016, we closed the divestment of our 47% interest in the Alon A and Alon C licenses, which include the Karish and Tanin fields, for a total sales price of $73 million ($67 million for asset consideration and $6 million for cost adjustments). Proceeds were applied to reduce field basis with no recognition of gain or loss.

that is being held by production.
Note 5. Derivative Instruments and Hedging Activities
Objective and Strategies for Using Derivative Instruments   We are exposed to fluctuations in crude oil, natural gas and NGL pricing. In order to mitigate the effect of commodity price volatility and enhance the predictability of cash flows relating to the marketing of our global crude oil and domestic natural gas, we enter into crude oil and natural gas price hedging arrangements.
While these instruments mitigate the cash flow risk of future decreases in commodity prices, they may also curtail benefits from future increases in commodity prices. See Note 7. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of our derivative instruments.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)



Unsettled Commodity Derivative Instruments   As of September 30, 2017, 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
2H17 (1)
Call Option (2)
NYMEX WTI3,000$—
$—
 $—
$—
$60.12
2H17 (1)
Three-Way CollarsICE Brent5,000—
—
 43.00
50.00
64.00
2017Three-Way CollarsNYMEX WTI24,000—
—
 39.08
47.71
61.20
2017Two-Way CollarsNYMEX WTI10,804—
—
 —
40.80
52.72
2017SwapsNYMEX WTI4,293—
50.84
 —
—
—
2017
Call Option (2)
NYMEX WTI3,000—
—
 —
—
57.00
2017Three-Way CollarsICE Brent2,000—
—
 43.00
50.00
63.15
2017Three-Way CollarsDated Brent2,000—
—
 35.00
45.00
66.33
2018Three-Way CollarsNYMEX WTI10,000—
—
 45.50
52.50
69.09
2018Three-Way CollarsDated Brent3,000—
—
 40.00
50.00
70.41
2018
Swaptions (3)
NYMEX WTI3,000—
56.10
 —
—
—
2018Three-Way CollarsICE Brent5,000—
—
 43.00
50.00
59.50
2018Two-Way CollarsICE Brent2,000—
—
 —
50.00
55.25
2018Basis Swap
(4) 
8,000(0.78)—
 —
—
—
2019Three-Way CollarsICE Brent3,000—
—
 43.00
50.00
64.07
2019Basis Swap
(4) 
12,000(1.01)—
 —
—
—
(1)
We have entered into contracts for portions of 2017 resulting in the difference in hedged volumes for the full year.
(2)
We have entered into crude oil derivative enhanced swaps with strike prices that are above the market value as of trade commencement. To effect the enhanced swap structure, we sold call options to the applicable counterparty to receive the above market terms.
(3)
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.
(4)
We have entered into crude oil basis swap contracts in order to fix 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.



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



As of September 30, 2017, 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
2017Three-Way CollarsNYMEX HH110,000$—
 $2.58
$2.93
$3.65
2017Two-Way CollarsNYMEX HH70,000—
 —
2.93
3.32
2018Three-Way CollarsNYMEX HH120,000—
 2.50
2.88
3.65
2018
Swaptions(1)
NYMEX HH30,0003.36
 —
—
—
(1)
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.
Fair Value Amounts and (Gain) Loss 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
 September 30,
2017		 December 31,
2016		 September 30,
2017		 December 31,
2016
(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 $7
 Current Assets $—
 Current Liabilities $4
 Current Liabilities $102
 Noncurrent Assets 5
 Noncurrent Assets —
 Noncurrent Liabilities 2
 Noncurrent Liabilities 14
Total  $12
   $—
   $6
   $116

The effect of commodity derivative instruments on our consolidated statements of operations was as follows:
 Three Months Ended September 30, Nine Months Ended September 30,
(millions)2017 2016 2017 2016
Cash (Received) Paid in Settlement of Commodity Derivative Instruments       
Crude Oil$(4) $(119) $(20) $(395)
Natural Gas—
 (13) 2
 (59)
Total Cash Received in Settlement of Commodity Derivative Instruments(4) (132) (18) (454)
Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments       
Crude Oil27
 80
 (64) 441
Natural Gas(1) (3) (63) 66
Total Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments26
 77
 (127) 507
Loss (Gain) on Commodity Derivative Instruments       
Crude Oil23
 (39) (84) 46
Natural Gas(1) (16) (61) 7
Total Loss (Gain) on Commodity Derivative Instruments$22
 $(55) $(145) $53
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)



Note 6. Debt
Debt consists of the following:
 September 30,
2017		 December 31,
2016
(millions, except percentages)Debt Interest Rate
 Debt Interest Rate
Revolving Credit Facility, due August 27, 2020$275
 2.27% $—
 —%
Noble Midstream Services Revolving Credit Facility, due September 20, 2021200
 2.45% —
 —%
Term Loan Facility, due January 6, 2019550
 2.45% 550
 2.01%
Leviathan Term Loan Facility, due February 23, 2025—
 —% —
 —%
Senior Notes, due March 1, 2019 (1) 
—
 —% 1,000
 8.25%
Senior Notes, due May 1, 2021379
 5.625% 379
 5.625%
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, 2028 (1) 
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, 2047 (1) 
500
 4.95% —
 —%
Other Senior Notes and Debentures (2) 

110
 6.93% 110
 6.93%
Capital Lease and Other Obligations (3) 
290
 —% 375
 —%
Total7,604
   7,114
  
Unamortized Discount(25)   (23)  
Unamortized Premium14
   17
  
Unamortized Debt Issuance Costs(41)   (34)  
Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs7,552
   7,074
  
Less Amounts Due Within One Year       
Capital Lease Obligations(65)   (63)  
Long-Term Debt Due After One Year$7,487
   $7,011
  
(1) In third quarter 2017, we redeemed all our Senior Notes due March 1, 2019 and issued Senior Notes due January 15, 2028 and August 15, 2047.
(2) Includes $18 million of Senior Notes due June 1, 2022, $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 6.93%.
(3) The reduction includes $41 million related to other obligations for drilling commitments assumed by the acquirer of the Marcellus Shale upstream assets and $44 million of capital lease principal payments. See Note 4. Acquisitions and Divestitures and Note 12. Commitments and Contingencies.
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.
During second quarter 2017, we borrowed $1.3 billion to fund the cash portion of the Clayton Williams Energy Acquisition consideration, redeem assumed Clayton Williams Energy long-term debt, pay associated make-whole premiums, pay related fees and expenses associated with the transaction and to fund other general corporate expenditures. We repaid all of the respective outstanding borrowings associated with the transaction during second quarter 2017 with proceeds received from the Marcellus Shale upstream divestiture, cash on hand, and cash generated by the Noble Midstream Partners private placement of limited partner units and Noble Midstream Services borrowings. As of September 30, 2017, $275 million was outstanding under our Revolving Credit Facility, which was utilized for general corporate purposes and for funding of our capital development program.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)



Noble Midstream Services Revolving Credit FacilityIn 2016, Noble Midstream Services, LLC, a subsidiary of Noble Midstream Partners, entered into a credit agreement for a $350 million revolving credit facility (Noble Midstream Services Revolving Credit Facility) which is available to fund working capital and to finance acquisitions and other capital expenditures of Noble Midstream Partners.
Borrowings by Noble Midstream Partners under the Noble Midstream Services Revolving Credit Facility bear interest at a rate equal 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 rate 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 September 30, 2017, $200 million was outstanding under the Noble Midstream Services Revolving Credit Facility which was used to partially fund second quarter 2017 acquisitions. See Note 4. Acquisitions and Divestitures.
Senior Notes Issuance and Completed Tender Offer On August 15, 2017, we issued $600 million of 3.85% senior unsecured notes that will mature on January 15, 2028 and $500 million of 4.95% senior unsecured notes that will mature on August 15, 2047. Interest on the 3.85% senior notes and 4.95% senior notes is payable semi-annually beginning January 15, 2018 and February 15, 2018, respectively. We may redeem some or all of the senior notes at any time at the applicable redemption price, plus accrued interest, if any. The senior notes were issued at a discount of $4 million and debt issuance costs incurred totaled $11 million, both of which are reflected as a reduction of long-term debt and are amortized over the life of the facility. Proceeds of $1.1 billion from the issuance of senior notes were used solely to fund the tender offer and the redemption of $1.0 billion of our 8.25% senior notes due March 1, 2019. As a result, we paid a premium of $96 million to the holders of the 8.25% senior notes and recognized a loss of $98 million in third quarter 2017, which is reflected in other non-operating (income) expense in our consolidated statements of operations.
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, of which $625 million 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 be 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.
Term Loan Agreement and Completed Tender OffersIn 2016, we entered into a term loan agreement (Term Loan Facility) which provides for a three-year term loan facility for a principal amount of $1.4 billion. The Term Loan Facility accrues interest, at our option, at either (a) a base rate equal to the highest of (i) the rate announced by Citibank, N.A., as its prime rate, (ii) the Federal Funds Rate plus 0.5%, and (iii) LIBOR plus 1.0%, plus a margin that ranges from 10 basis points to 75 basis points depending upon our credit rating, or (b) LIBOR plus a margin that ranges from 100 basis points to 175 basis points depending upon our credit rating.
Borrowings under the Term Loan Facility were used solely to fund tender offers for approximately $1.38 billion of notes assumed in our merger with Rosetta Resources Inc. in 2015. As a result, we recognized a gain of $80 million in first quarter 2016 which is reflected in other non-operating (income) expense in our consolidated statements of operations. In fourth quarter 2016, we prepaid $850 million of long-term debt outstanding under the Term Loan Facility from cash on hand. As of September 30, 2017, $550 million was outstanding under the facility.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)



See Note 7. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of debt.
Annual Debt Maturities Annual maturities of outstanding debt, excluding capital lease payments and outstanding balances under the revolving credit facilities, are as follows:
(millions)
Debt
Principal
Payments
October - December 2017

$—
2018—
2019550
2020—
20211,379
Thereafter4,910
Total$6,839

Note 7. Fair Value Measurements6. Asset Retirement Obligations
Asset retirement obligations (ARO) consist primarily of estimated costs of dismantlement, removal, site reclamation 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 5. Derivative Instruments and Hedging Activities. 
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 liabilitysimilar activities associated with our phantom unit plan is dependent uponoil and gas properties. Changes in ARO are as follows:
 Nine Months Ended September 30,
(millions)2019 2018
Asset Retirement Obligations, Beginning Balance$880
 $875
Liabilities Incurred17
 16
Liabilities Settled(82) (309)
Revisions of Estimates(60) 67
Accretion Expense33
 25
Asset Retirement Obligations, Ending Balance$788
 $674

Nine Months Ended September 30, 2019 Liabilities settled relate primarily to abandonment of US onshore properties, principally in the fair valueDJ 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. Revisions of Noble Energy common stockestimates relate primarily to a decrease of $73 million in the DJ Basin as a result of improved cycle times and cost reductions for vertical wells, partially offset by acceleration of timing estimates of $13 million for wells offshore Israel.
Nine Months Ended September 30, 2018 Liabilities settled include $216 million and $24 million of liabilities assumed by the purchasers of the endGulf of each reporting period.Mexico properties and Greeley Crescent assets, respectively, and $69 million related to abandonment of US onshore properties, primarily in the DJ Basin. Revisions of estimates relate primarily to increases in cost and timing of estimates of $84 million for US onshore, primarily in the DJ Basin, partially offset by decreases in cost and timing estimates of $11 million associated with the North Sea abandonment project and $6 million for Eastern Mediterranean.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)




Note 7. Debt
Measurement information for assets and liabilities that are measured at fair value on a recurring basis was as follows: Debt consists of the following:
 September 30, 2019 December 31, 2018
(millions, except percentages)Debt Interest Rate
 Debt Interest Rate
Noble Energy, Excluding Noble Midstream Partners       
  Revolving Credit Facility, due March 9, 2023$—
 —% $—
 —%
  Commercial Paper Borrowings511
 
(1 
) 
 —
 —%
  Senior Notes and Debentures5,884
 
(2 
) 
 5,892
 
(2 
) 
  Finance Lease Obligations206
 —% 223
 —%
Total Noble Energy Debt, Excluding Noble Midstream Partners Debt6,601
   6,115
  
Noble Midstream Partners       
Noble Midstream Services Revolving Credit Facility, due March 9, 2023 (3)
50
 3.45% 60
 3.67%
Noble Midstream Services Term Loan Credit Facility, due July 31, 2021500
 3.17% 500
 3.42%
Noble Midstream Services Term Loan Credit Facility, due August 23, 2022400
 3.05% —
 —%
Total Noble Midstream Partners Debt950
   560
  
Total Debt7,551
   6,675
  
Net Unamortized Discounts and Debt Issuance Costs(57)   (60)  
Total Debt, Net of Unamortized Discounts and Debt Issuance Costs7,494
   6,615
  
Less Amounts Due Within One Year       
  Commercial Paper Borrowings(511)   —
  
Finance Lease Obligations(42)   (41)  
Long-Term Debt Due After One Year$6,941
   $6,574
  
 Fair Value Measurements Using    
 
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
(millions)         
September 30, 2017         
Financial Assets         
Mutual Fund Investments$70
 $—
 $—
 $—
 $70
Commodity Derivative Instruments—
 16
 —
 (4) 12
Financial Liabilities         
Commodity Derivative Instruments—
 (10) —
 4
 (6)
Portion of Deferred Compensation Liability Measured at Fair Value(89) —
 —
 —
 (89)
Stock Based Compensation Liability Measured at Fair Value(11) —
 —
 —
—
(11)
December 31, 2016         
Financial Assets         
Mutual Fund Investments$71
 $—
 $—
 $—
 $71
Commodity Derivative Instruments—
 5
 —
 (5) —
Financial Liabilities         
Commodity Derivative Instruments—
 (121) —
 5
 (116)
Portion of Deferred Compensation Liability Measured at Fair Value(88) —
 —
 —
 (88)
Stock Based Compensation Liability Measured at Fair Value(9) —
 —
 —
 (9)

(1) 
Level 1 measurements are fair value measurements which use quoted market prices (unadjusted) in active marketsAs of September 30, 2019, the weighted average interest rate 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.outstanding commercial paper was 2.63%.
(2) 
Level 2 measurements are fair value measurements which use inputs, other than quoted prices included within Level 1, which are observable forAs of September 30, 2019 and December 31, 2018, the asset or liability, either directly or indirectly.senior notes and debentures had weighted average interest rates of 5.00% and 5.01%, respectively.
(3) 
Level 3 measurements are fair value measurementsAs of September 30, 2019 and December 31, 2018, the Noble Midstream Services Revolving Credit Facility had $800 million of capacity, of which use unobservable inputs.
(4)
Amount represents the impact of netting provisions within our master agreements that allow us to net cash settle asset$750 million and liability positions with the same counterparty.$740 million were available for borrowing, respectively.
AssetsCommercial Paper Program In first quarter 2019, we established a commercial paper program to provide for short-term funding needs. The program allows for a maximum of $4.0 billion of unsecured commercial paper notes and Liabilities Measuredis supported by Noble Energy’s $4.0 billion Revolving Credit Facility. Our commercial paper notes, which generally have a maturity of less than 30 days, are sold under customary terms in the commercial paper market and are either issued at Fair Valuea discounted price relative to the principal face value or bear interest at varying interest rates on a Nonrecurring Basis
Certain assetsfixed or floating basis. Such discount prices or interest rates are dependent on market conditions and liabilities such as inventory, oil and gas properties and assets held for sale are measuredratings assigned to the commercial paper program by credit agencies at fair value on a nonrecurring basis in our consolidated balance sheets. For the nine months endedtime of commercial paper issuance. At September 30, 2017 and 2016, we had no adjustments in fair value related to these items. Other items measured at fair value on a nonrecurring basis are discussed below.2019, outstanding commercial paper borrowings totaled $511 million, leaving approximately $3.5 billion available for borrowing under our $4.0 billion Revolving Credit Facility.
Marcellus Shale Firm Transportation Liability As of September 30, 2017, we had a $39 million liability representing the discounted present value of our remaining obligation under a firm transportation contract. See Note 12. Commitments and Contingencies.
Additional Fair Value Disclosures
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.
OurNoble Midstream Services 2019 Term Loan Facility and Revolving Credit Facility along withOn August 23, 2019, Noble Midstream Services LLC (Noble Midstream Services), a subsidiary of Noble Midstream Partners, entered into a term loan agreement, which provides for a three-year senior unsecured term loan credit facility, due August 23, 2022 (2019 Term Loan Credit Facility), that permits aggregate borrowings of up to $400 million. Proceeds from the term loan were primarily used to repay a portion of the outstanding borrowings under the Noble Midstream Services Revolving Credit Facility, are variable-rate, non-public debt. The fair value is estimated based on significant other observable inputs. As such,Facility.
Subsequent Event On October 1, 2019, we consider the fair valueissued $500 million of these facilities to be a Level 2 measurement3.25% notes due October 15, 2029 and $500 million of 4.20% notes due October 15, 2049. Interest on the fair value hierarchy. notes is payable semi-annually beginning April 15, 2020. We may redeem some or all of the notes at any time at the applicable redemption price, plus accrued interest, if any. Proceeds from the issuance of the notes were used to fund the tender offer and redemption of our $1.0 billion 4.15% notes due December 15, 2021. In connection with the tender and redemption, in fourth quarter 2019, we will record early debt extinguishment fees of approximately $44 million in our consolidated statements of operations.
Fair Value of Debt See Note 6. Debt13. Fair Value Measurements and Disclosures.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)




Note 8. Leases
Fair value information regardingIn the normal course of business, we enter into operating and finance lease agreements to support our debtoperations. Operating leases primarily include 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:
September 30, 2017 December 31, 2016
(millions)Carrying Amount Fair Value Carrying Amount Fair ValueBalance Sheet LocationSeptember 30, 2019
Long-Term Debt, Net (1)
$7,314
 $7,715
 $6,739
 $7,112
ROU Assets  
Operating Leases (1)
Other Noncurrent Assets$275
Finance Leases (2)
Total Property, Plant and Equipment, Net172
Total ROU Assets $447
Lease Liabilities  
Current Liabilities  
Operating LeasesOther Current Liabilities$97
Finance LeasesOther Current Liabilities42
Noncurrent Liabilities  
Operating LeasesOther Noncurrent Liabilities209
Finance LeasesLong-Term Debt164
Total Lease Liabilities $512
(1) 
Excludes unamortized discount, premium, debt issuance costsOperating lease ROU assets primarily include office space of $117 million, compressors of $93 million, and capitaldrilling rigs of $29 million.
(2)
Finance lease obligations.ROU assets primarily include office space of $92 million and a trunkline of $32 million, both net of accumulated amortization.


Note 8. 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 statusStatement of suspended exploratory well costs and assess the developmentOperations Information The components 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 costslease cost are as follows and exclude amounts that were capitalized and subsequently expensed in the same period:follows:
(millions)Nine Months Ended September 30, 2017
Capitalized Exploratory Well Costs, December 31, 2016$768
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves10
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves (1)
(203)
Capitalized Exploratory Well Costs, September 30, 2017$575
(millions)Statement of Operations LocationThree Months Ended September 30, 2019 Nine Months Ended September 30, 2019
Operating Lease Cost
(1) 
$30
 $81
Finance Lease Cost    
Amortization ExpenseDepreciation, Depletion and Amortization10
 27
Interest ExpenseInterest, Net of Amount Capitalized3
 10
Short-term Lease Cost (2)
(1) 
88
 357
Sublease IncomeGeneral and Administrative(1) (3)
Total Lease Cost $130
 $472
(1) 
Amount relates toCost classifications vary depending on the approvalleased asset. Costs are primarily included within production expense and sanctiongeneral and administrative expense. In addition, in accordance with the successful efforts method of the first phaseaccounting, certain lease costs may be capitalized when incurred and, therefore, are included as part of development of the Leviathan field, offshore Israel. During second quarter 2017, we recorded Leviathan field proved undeveloped reserves of 551 MMBoe, net.oil and gas properties on our consolidated balance sheets.

The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced:
(millions)September 30,
2017		 December 31,
2016
Exploratory Well Costs Capitalized for a Period of One Year or Less$11
 $69
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling (1)
564
 699
Balance at September 30, 2017$575
 $768
(1)(2) 
The decrease from December 31, 2016 is attributableShort-term lease costs relate primarily to the reclassificationhydraulic fracturing services, well-to-well drilling rig contracts and other miscellaneous lease agreements. Amount excludes costs for leases with an initial term of the Leviathan field to development work in process, partially offset by the capitalization of interest during the period on remaining exploratory wells.one month or less.
Undeveloped Leasehold Costs We reclassify undeveloped leasehold costs to proved property costs when proved reserves, including proved undeveloped reserves, become attributable to the property as a result of our exploration and development activities. 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 will record impairment expense related to the respective leases or licenses.
As of September 30, 2017, we had remaining undeveloped leasehold costs, to which proved reserves had not been attributed, of $3 billion, including $1.6 billion related to Delaware Basin assets acquired in the Clayton Williams Energy Acquisition in 2017, and $1.1 billion and $149 million attributable to Delaware Basin and Eagle Ford Shale assets, respectively, acquired in the Rosetta Resources Inc. acquisition 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 September 30, 2017 included $56 million related to Gulf of Mexico unproved properties and $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 nine months of 2017, we completed geological evaluations of certain Gulf of Mexico leases and licenses associated with other international unproved properties and determined that several should be relinquished or exited. As a result, we recognized $33 million and $51 million of undeveloped leasehold impairment expense for the three and nine months ended September 30, 2017, respectively. Of these amounts, $31 million and $49 million for the respective periods are attributable to our Gulf of Mexico leases. These expenses are recorded in exploration expense in the consolidated statements of operations.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)



Cash Flow Information Supplemental cash flow information is as follows:

 Nine Months Ended September 30, 2019
(millions)Operating Leases Finance Leases
Cash Paid for Amounts Included in the Measurement of Lease Liabilities   
Operating Cash Flows$50
 $9
Investing Cash Flows27
 —
Financing Cash Flows—
 31
Non-Cash Activities   
ROU Assets Obtained in Exchange for Lease Liabilities (1)
93
 15
(1)
Amounts exclude the impact of adopting ASC 842 on January 1, 2019. See Note 2. Basis of Presentation.

Maturity of Lease Liabilities Maturities of lease liabilities as of September 30, 2019 are as follows:
(millions)Operating Leases Finance Leases Total
Remainder of 2019$28
 $13
 $41
2020100
 49
 149
202161
 35
 96
202244
 25
 69
202329
 22
 51
2024 and Thereafter85
 106
 191
Total Lease Liabilities, Undiscounted347
 250
 597
Less: Imputed Interest41
 44
 85
Total Lease Liabilities (1)
$306
 $206
 $512
(1)
Includes the current portions of $97 million and $42 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 as of September 30, 2019 is as follows:
 Operating Leases Finance Leases
Weighted-Average Remaining Lease Term5.7 years
 7.7 years
Weighted-Average Discount Rate4.40% 5.02%


Note 9. Exit Cost – Transportation Commitments
In connection with the divestiture of Marcellus Shale upstream assets in 2017, we retained certain long-term financial commitments to pay transportation fees on certain pipelines in the Marcellus Basin. As of September 30, 2019, our undiscounted financial commitment for the remaining obligations under these agreements was approximately $1.0 billion, which excludes the impact of future mitigation activities. Our efforts to mitigate and thereby reduce these obligations primarily include permanent assignment of capacity, negotiation of capacity releases and utilization of capacity through purchase and
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)

transport of third-party natural gas. Revenues and expenses associated with mitigation activities are recorded in sales of purchased oil and gas and cost of purchased oil and gas, respectively, in our consolidated statements of operations.
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 remaining component of these transportation agreements through 2020.
Exit Costs Reconciliation of accrued costs at September 30, 2019 is as follows:
 Nine Months Ended September 30,
(millions)2019 2018
Balance at Beginning of Period (1)
$80
 $90
Firm Transportation Exit Cost Accrual92
 —
Payments, Net of Accretion(6) (9)
Balance at End of Period166

81
Less: Current Portion Included in Other Current Liabilities33
 12
Long-term Portion Included in Other Noncurrent Liabilities$133
 $69
(1)
Amounts include the current portion of $13 million which is included in other current liabilities in our consolidated balance sheets.

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 Clean Water Act Referral Notice In September 2018, we received a letter from the Department of Justice (DOJ) requesting an opportunity to discuss settlement of alleged Clean Water Act violations at an upstream production facility and a midstream gathering facility in Weld County, Colorado. In April 2019, we met with the DOJ and Environmental Protection Agency enforcement personnel to discuss potential settlement of the alleged violations. Given the ongoing status of settlement discussions, we are currently unable to predict the ultimate outcome of this action, but believe the resolution will not have a material adverse effect on our financial position, results of operations or cash flows.
Note 11. Income Taxes
Income tax expense (benefit) consists of the following:
 Three Months Ended September 30, Nine Months Ended September 30,
(millions, except percentages)2019 2018 2019 2018
Current$24
 $45
 $61
 $194
Deferred(9) 14
 (110) (150)
Total Income Tax Expense (Benefit)$15
 $59
 $(49) $44
Effective Tax Rate29.4% 19.2% 16.7% 5.1%

Effective Tax Rate (ETR) At the end of each interim period, we apply a forecasted annualized ETR to current period earnings or loss before tax, which can produce interim ETR fluctuations. The ETR for the nine months ended September 30, 2019 varied as compared with 2018, primarily due to a $145 million discrete tax benefit recorded in 2018 as a result of the intent of the US Department of the Treasury and Internal Revenue Service to issue additional regulatory guidance associated with the Tax Cuts and Jobs Act and the transition tax. In addition, current tax expense for the nine months ended September 30, 2018 includes foreign taxes related to a gain on the 2018 divestiture of a 7.5% interest in the Tamar field.
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 9. Asset Retirement Obligations12. Derivative Instruments and Hedging Activities
Asset retirement obligations (ARO) consist primarily of estimated costs of dismantlement, removal, site reclamationObjective and similar activities associated with ourStrategies for Using Derivative Instruments   We enter into crude oil and natural gas properties. Changesprice hedging arrangements to mitigate effects of commodity price volatility and enhance the predictability of cash flows for a portion of our crude oil and natural gas production. While these instruments mitigate the cash flow risk of future decreases in ARO are as follows:
commodity prices, they may also curtail benefits from future increases in commodity prices. 
 Nine Months Ended September 30,
(millions)2017 2016
Asset Retirement Obligations, Beginning Balance$935
 $989
Liabilities Incurred83
 5
Liabilities Settled(53) (87)
Revision of Estimate(56) 4
Accretion Expense (1)
35
 37
Asset Retirement Obligations, Ending Balance$944
 $948
Unsettled Commodity Derivative Instruments   As of September 30, 2019, the following crude oil derivative contracts were outstanding:
    Swaps Collars
Settlement PeriodType of ContractIndexBbls Per DayWeighted Average DifferentialWeighted Average Fixed Price Weighted Average Short Put PriceWeighted Average Floor PriceWeighted Average Ceiling Price
2019SwapsNYMEX WTI35,000$—
$59.04
 $—
$—
$—
2019Three-Way CollarsNYMEX WTI33,000—
—
 49.35
59.35
72.25
2019
Sold Calls (1)
NYMEX WTI4,000—
60.00
 —
—
—
2019SwapsICE Brent5,000—
57.00
 —
—
—
2019Three-Way CollarsICE Brent3,000—
—
 43.00
50.00
64.07
2019Basis Swaps
(2) 
27,000(3.23)—
 —
—
—
2020SwaptionNYMEX WTI12,000—
59.73
 —
—
—
2020
Sold Calls (1)
NYMEX WTI8,000—
65.59
 —
—
—
2020SwapsNYMEX WTI28,000—
58.09
 —
—
—
2020Three-Way CollarsNYMEX WTI30,000—
—
 48.33
57.87
64.27
2020Basis Swaps
(2) 
15,000(5.01)—
 —
—
—

(1) 
We entered into crude oil contracts receiving premiums for establishing a maximum price that would be settled for the notional volumes covered by the respective contracts.
Accretion expense is included(2)
We entered into crude oil basis swap contracts to establish a fixed amount for the differential between pricing in depreciation, depletionMidland, Texas, and amortization (DD&A)expense inCushing, Oklahoma. The weighted average differential represents the consolidated statementsamount ofoperations. reduction to Cushing, Oklahoma prices for the notional volumes covered by the basis swap contracts.
For the Nine Months EndedAs of September 30, 2017 Liabilities incurred include $58 million related2019, 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)
123,500
(0.64)—
 —
—
—
2019Basis Swaps
WAHA (1)
47,500
(1.28)—
 —
—
—
2020SwapsNYMEX HH90,000
—
2.60
 —
—
—
2020
Sold Puts (2)
NYMEX HH90,000
—
—
 2.15
—
—
2020SwaptionNYMEX HH90,000
—
2.60
 —
—
—
2020Basis Swaps
CIG (1)
54,000
(0.61)—
 —
—
—
2020Basis Swaps
WAHA (1)
49,500
(1.05)—
 —
—
—
2021Basis Swaps
WAHA (1)
14,000
(0.60)—
 —
—
—

(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.
(2)
We entered into natural gas contracts receiving premiums for establishing a minimum price that would be settled for the notional volumes covered by the respective contracts.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)

Fair Value AmountsThe fair values of commodity derivative instruments in our consolidated balance sheets were as follows (in millions):
Asset Derivative Instruments Liability Derivative Instruments
Balance Sheet LocationSeptember 30, 2019 December 31, 2018 Balance Sheet LocationSeptember 30, 2019 December 31, 2018
Other Current Assets$90
 $180
 Other Current Liabilities$10
 $1
Other Noncurrent Assets25
 —
 Other Noncurrent Liabilities3
 26
Total$115
 $180
  $13
 $27

See Note 13. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the Clayton Williams Energy Acquisitionfair values of our derivative instruments.
Gains and $25 million primarily for other US onshore wellsLosses on Commodity Derivative Instruments The effect of commodity derivative instruments on our consolidated statements of operations and facilities placed into service. Liabilities settled include $37 million related to abandonment of onshore US properties, $12 million related to properties sold in the Marcellus Shale upstream divestiture and $4 million related to other offshore international and US properties. Revisions of estimates relate to decreases in cost and timing estimates of $42 million associated with the North Sea abandonment project and $29 million for US onshore and Gulf of Mexico, partially offset by an increase of $15 million for West Africa.comprehensive income (loss) was as follows:
 Three Months Ended September 30, Nine Months Ended September 30,
(millions)2019 2018 2019 2018
Cash (Received) Paid in Settlement of Commodity Derivative Instruments       
Crude Oil$(6) $68
 $(8) $164
Natural Gas(7) (1) (20) (4)
Total Cash (Received) Paid in Settlement of Commodity Derivative Instruments(13) 67
 (28) 160
Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments       
Crude Oil(115) 85
 54
 316
Natural Gas(1) 3
 (3) 7
Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments(116) 88
 51
 323
(Gain) Loss on Commodity Derivative Instruments       
Crude Oil(121) 153
 46
 480
Natural Gas(8) 2
 (23) 3
Total (Gain) Loss on Commodity Derivative Instruments$(129) $155
 $23
 $483
For theNine Months Ended September 30, 2016 Liabilities incurred were due to new wells and facilities for onshore US. Liabilities settled primarily related to Gulf of Mexico and onshore US property abandonments.
Note 10. Income Taxes13. Fair Value Measurements and Disclosures
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Cash and Cash Equivalents, Accounts Receivable and Accounts PayableThe income tax provision (benefit) consistscarrying amounts approximate fair value due to the short-term nature or maturity of the following:
instruments. 
 Three Months Ended September 30, Nine Months Ended September 30,
(millions)2017 2016 2017 2016
Current (1)
$22
 $148
 $71
 $213
Deferred(115) (285) (988) (699)
Total Income Tax Benefit$(93) $(137) $(917) $(486)
Effective Tax Rate44.7% 48.9% 36.9% 39.5%
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.
(1) Current income taxes are attributable toCommodity Derivative Instruments   We estimate the fair values of our operationsderivative instruments using published forward commodity price curves as of the date of the estimate. The discount rate used in Israelthe cash flow projections is based on published LIBOR rates, Eurodollar futures rates and Equatorial Guinea.interest swap rates. The fair values of commodity 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 current published credit default swap rates. In addition, for collars, we estimate the values of put options sold and 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. 
Effective Tax Rate (ETR) AtDeferred 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 interim period, we apply a forecasted annualized effective tax rate (ETR) to current year earnings or loss before tax, which can result in significant interim ETR fluctuations. Our ETR for the three and nine months ended September 30, 2017 varied as compared with the three and nine months ended September 30, 2016 primarily due to a smaller prior year increase to the deferred tax liability recorded on unrepatriated earnings combined with a larger prior year discrete tax benefit driven by a tax rate change in a foreign jurisdiction.
In addition, the significant increase in the deferred income tax benefit for the nine months ended September 30, 2017 is primarily due to the loss recorded for the Marcellus Shale upstream divestiture during second quarter 2017.
In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US – 2014, Israel – 2015 and Equatorial Guinea – 2012.
Deferred Tax Assets We currently forecast that our US federal income tax net operating loss (NOL) carryforwards will be substantial at year end 2017. Included in the resulting deferred tax assets are acquired deferred tax assets associated with net operating losses of the Clayton Williams Energy Acquisition in 2017 and with the Rosetta Resources Inc. acquisition in 2015.
In assessing the realizability of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income in the associated tax jurisdictions during the periods in which those temporary differences become deductible. We consider the scheduled reversal of deferred tax liabilities, current financial position, results of operations, projected future taxable income and tax planning strategies, as well as current and forecasted business economics in the oil and gas industry. Based on the level of our historical taxable income and projections for future taxable income, we currently believe it is more likely than not that we will realize the benefits of these NOL carryforwards. However, the amount of the deferred tax assetsreporting 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
September 30, 2019         
Financial Assets:         
Mutual Fund Investments$42
 $—
 $—
 $—
 $42
Commodity Derivative Instruments—
 155
 —
 (40) 115
Financial Liabilities:         
Commodity Derivative Instruments—
 (53) —
 40
 (13)
Portion of Deferred Compensation Liability Measured at Fair Value(48) —
 —
 —
 (48)
Stock Based Compensation Liability Measured at Fair Value(3) —
 —
 —
 (3)
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 settle asset and liability positions with the same counterparty.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
considered realizable could be reducedFirm Transportation Exit Cost Accrual In January 2019, we recorded a firm transportation exit cost liability at fair value of $92 million, representing the discounted present value of our remaining obligation under a permanent pipeline capacity assignment in the future if estimates of future taxable income during the carryforward period are reduced.Marcellus Shale. See Note 9. Exit Cost – Transportation Commitments.
We currently have a valuation allowance on the deferred tax assetsRedeemable Noncontrolling Interest In March 2019, we recorded redeemable noncontrolling interest associated with foreign loss carryforwards forecasted for year end 2017the issuance to GIP of approximately $181 million at September 30, 2017 and $242 million at December 31, 2016. The decrease was attributable to the offset of the valuation allowance against the net operating losspreferred equity in a jurisdiction in which we are no longer active.
Note 11. Segment Information
During second quarter 2017, as a result of the strategic changes in our US onshore portfolio, we established our Midstream business as a new reportable segment. The Midstream segment, which includes the consolidated accounts of Noble Midstream Partners additional US onshore midstream assetsat fair value of $97 million, including issuance date proceeds of $100 million netted with associated issuance costs of $3 million. See Note 2. Basis of Presentation.
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 of this debt to be a Level 1 measurement on the fair value hierarchy.
Our non-public debt, including our Revolving Credit Facility, commercial paper borrowings, Noble Midstream Services Revolving Credit Facility and US onshore equity method investments, was previously reported withinNoble Midstream Services term loans are subject to variable interest rates. The fair value is estimated based on significant other observable inputs; thus, we consider the United States reportable segment. As a result,fair values to be Level 2 measurements on the fair value hierarchy. See Note 7. Debt.
Fair value information regarding our debt is as of June 30, 2017, we now have five reportable segments, United States (US onshore and Gulf of Mexico); Eastern Mediterranean (Israel and Cyprus); West Africa (Equatorial Guinea, Cameroon and Gabon); Other International (Falkland Islands, Suriname, Canada and New Ventures); and Midstream.follows:
 September 30, 2019 December 31, 2018
(millions)Carrying Amount 
Fair Value (1)
 Carrying Amount Fair Value
Debt (2)
$7,345
 $7,963
 $6,452
 $6,121
The geographical reportable segments are in the business of crude oil and natural gas exploration, development, production, and acquisition (Oil and Gas Exploration and Production). The Midstream reportable segment owns, operates, develops and acquires domestic midstream infrastructure assets with current focus areas being the DJ and Delaware Basins. The Corporate reportable segment incurs expenses related to debt, headquarters depreciation and corporate general and administrative cost.
(1)
As of September 30, 2019, the difference between the carrying amount and the fair value is primarily due to low US treasury rates.
(2)
Represents total debt excluding finance lease obligations. See Note 7. Debt.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)




Note 14. Net Income (Loss) Per Share Attributable to Noble Energy Common Shareholders
Prior period amounts are presented on a comparable basis.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:
   Oil and Gas Exploration and Production Midstream  
(In millions)Consolidated United
States		 Eastern
Mediter- ranean		 West
Africa		 
Other Int'l (1)
 United States Intersegment Eliminations and Other Corporate
Three Months Ended September 30, 2017              
Oil, NGL and Gas Sales from Third Parties$907
 $696
 $141
 $70
 $—
 $—
 $—
 $—
Income from Equity Method Investees and Other53
 —
 —
 33
 —
 20
 —
 —
Intersegment Revenues—
 —
 —
 —
 —
 72
 (72) —
Total Revenues960
 696
 141
 103
 —
 92
 (72) —
Lease Operating Expense151
 118
 9
 25
 —
 —
 (1) —
Production and Ad Valorem Taxes36
 35
 —
 —
 —
 1
 —
 —
Gathering, Transportation and Processing Expense93
 129
 —
 —
 —
 20
 (56) —
Total Production Expense280
 282
 9
 25
 —
 21
 (57) —
DD&A523
 442
 18
 41
 1
 10
 (1) 12
Loss on Marcellus Shale Upstream Divestiture4
 4
 —
 —
 —
 —
 —
 —
Clayton Williams Energy Acquisition Expenses4
 4
 —
 —
 —
 —
 —
 —
Loss on Commodity Derivative Instruments22
 16
 —
 6
 —
 —
 —
 —
(Loss) Income Before Income Taxes (2)
(208) (115) 109
 24
 23
 58
 (12) (295)
                
Three Months Ended September 30, 2016  
  
  
        
Oil, NGL and Gas Sales from Third Parties$882
 $638
 $150
 $94
 $—
 $—
 $—
 $—
Income from Equity Method Investees and Other28
 —
 —
 19
 —
 9
 —
 —
Intersegment Revenues—
 —
 —
 —
 —
 57
 (57) 

Total Revenues910
 638
 150
 113
 —
 66
 (57) —
Lease Operating Expense131
 106
 8
 22
 —
 —
 (5) —
Production and Ad Valorem Taxes30
 29
 —
 —
 —
 1
 —
 —
Gathering, Transportation and Processing Expense121
 144
 —
 —
 —
 11
 (34) —
Total Production Expense282
 279
 8
 22
 —
 12
 (39) —
DD&A621
 536
 22
 46
 1
 5
 —
 11
Loss on Commodity Derivative Instruments(55) (48) —
 (7) —
 —
 —
 —
(Loss) Income Before Income Taxes (2)
(280) (255) 135
 48
 (33) 47
 (18) (204)
 Three Months Ended September 30, Nine Months Ended September 30,
(millions, except per share amounts)2019 2018 2019 2018
Net Income (Loss) and Comprehensive Income (Loss) Attributable to Noble Energy$17
 $227
 $(306) $758
Weighted Average Number of Shares Outstanding, Basic (1)
478
 482
 478
 484
Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust2
 2
 —
 2
Weighted Average Number of Shares Outstanding, Diluted480
 484
 478
 486
Income (Loss) Per Share, Basic$0.04
 $0.47
 $(0.64) $1.57
Income (Loss) Per Share, Diluted$0.04
 $0.47
 $(0.64) $1.56
Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above14
 13
 15
 14
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)



   Oil and Gas Exploration and Production Midstream  
(In millions)Consolidated United
States		 Eastern
Mediter- ranean		 West
Africa		 
Other Int'l (1)
 United States Intersegment Eliminations and Other Corporate
Nine Months Ended September 30, 2017  
  
  
        
Oil, NGL and Gas Sales from Third Parties$2,918
 $2,246
 $406
 $266
 $—
 $—
 $—
 $—
Income from Equity Method Investees and Other137
 —
 —
 84
 —
 53
 —
 —
Intersegment Revenues—
 —
 —
 —
 —
 198
 (198) —
Total Revenues3,055
 2,246
 406
 350
 —
 251
 (198) —
Lease Operating Expense414
 332
 23
 65
 —
 —
 (6) —
Production and Ad Valorem Taxes119
 117
 —
 —
 —
 2
 —
 —
Gathering, Transportation and Processing Expense333
 416
 —
 —
 —
 53
 (136) —
Total Production Expense866
 865
 23
 65
 —
 55
 (142) —
DD&A1,554
 1,326
 58
 114
 4
 20
 (2) 34
Loss on Marcellus Shale Upstream Divestiture2,326
 2,326
 —
 —
 —
 —
 —
 —
Clayton Williams Energy Acquisition Expenses98
 98
 —
 —
 —
 —
 —
 —
Gain on Commodity Derivative Instruments(145) (138) —
 (7) —
 —
 —
 —
(Loss) Income Before Income Taxes (2)
(2,483) (2,433) 316
 162
 11
 165
 (47) (657)
                
Nine Months Ended September 30, 2016  
  
  
        
Oil, NGL and Gas Sales from Third Parties$2,411
 $1,705
 $407
 $299
 $—
 $—
 $—
 $—
Income from Equity Method Investees and Other70
 —
 —
 31
 —
 39
 —
 —
Intersegment Revenues—
 —
 —
 —
 —
 143
 (143) —
Total Revenues2,481
 1,705
 407
 330
 —
 182
 (143) —
Lease Operating Expense412
 324
 25
 75
 —
 —
 (12) —
Production and Ad Valorem Taxes73
 70
 —
 —
 —
 3
 —
 —
Gathering, Transportation and Processing Expense354
 417
 —
 —
 —
 31
 (94) —
Total Production Expense839
 811
 25
 75
 —
 34
 (106) —
DD&A1,859
 1,599
 62
 150
 4
 14
 —
 30
Loss on Commodity Derivative Instruments53
 45
 —
 8
 —
 —
 —
 —
(Loss) Income Before Income Taxes (2)
(1,231) (1,076) 290
 74
 (98) 126
 (37) (510)
                
September 30, 2017 
  
  
  
        
Goodwill (3)
$1,295
 $1,295
 $—
 $—
 $—
 $—
 $—
 $—
Total Assets21,649
 16,287
 2,681
 1,265
 108
 1,158
 (142) 292
December 31, 2016   
  
  
        
Total Assets21,011
 16,153
 2,233
 1,479
 89
 851
 (98) 304
(1) Income before income taxes for the three and nine months ended September 30, 2017 primarily relates to the North Sea remediation project revision. See Note 2. Basis of Presentation and Note 9. Asset Retirement Obligations.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)



(2) The intersegment eliminations related to (loss) income before income taxes are the result of midstream expenditures.  These costs are presented as property, plant and equipment within the upstream business on an unconsolidated basis, in accordance with the successful efforts method of accounting, and are eliminated upon consolidation.
(3) Goodwill in our United States reportable segment is associated with our Texas reporting unit. See Note 2. Basis of Presentation.

(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.

Note 12. CommitmentsItem 2.  Management’s Discussion and ContingenciesAnalysis of Financial Condition and Results of Operations
Legal ProceedingsManagement'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 are involved in various legal proceedingsuse 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 ordinary coursefollowing major sections:
•
Executive Overview;
•
Operating Outlook;
•
Results of Operations – Exploration 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 third quarter 2019. This discussion should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2018, which includes disclosures regarding our critical accounting policies as part of business.  These proceedings“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Operational Environment Update
Recent Activities During third quarter 2019, we progressed our US onshore drilling and completions activities, advanced our Eastern Mediterranean and West Africa regional natural gas developments and continued advancement of our US onshore and international exploration opportunities. We continue to execute capital and operating cost reduction efforts and reduce cycle times through operational improvements. During the quarter, we delivered consolidated sales volumes of 379 MBoe/d and achieved quarterly sales volumes records in both the DJ and Delaware Basins. This increased production was achieved with reduced capital investment. We continue to focus on progressing the Leviathan natural gas project, which was over 90% complete at quarter-end. Our focus on cost and capital efficiency and the startup of the Leviathan natural gas project should provide sustainable cash flows beginning in 2020.
Commodity Prices Crude oil prices remained volatile during third quarter 2019, with Brent and WTI averaging approximately $61 and $56 per barrel, respectively. The outlook for fourth quarter 2019 will depend on competing factors for supply and demand. Production cuts by the Organization of Petroleum Exporting Countries and geopolitical factors in critical oil producing regions remain constructive for global oil prices. However, a weakening of crude oil demand amid signs of a potential softening
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in the global economy could result in lower prices. In addition, US and China trade tensions threaten further damage to global trade and economic growth and, consequently, crude oil demand. In the Delaware Basin, new pipeline startups, including interim crude oil service on the EPIC Y-Grade pipeline, have begun to improve basis differentials, while planned expansion of export infrastructure should help alleviate a portion of the discount of WTI to Brent going forward.
The US natural gas market continues to see depressed levels as supply outpaced demand over the past year. Despite record domestic liquefied natural gas (LNG) exports and high natural gas fired electric generation, natural gas inventories are subjectprojected to remain at or slightly above historical five-year averages. Natural gas price differentials increased in the DJ Basin, while differentials in the Delaware Basin continue to be wide despite additional pipeline capacity from the Delaware Basin to Corpus Christi, Texas. Additional Delaware Basin natural gas pipeline expansions are targeted for in-service in late 2020.
NGL prices are also suppressed amid increased production, high inventory levels, and downstream fractionation and export bottlenecks. US NGL prices should strengthen as new processing and export facilities are brought online.
To mitigate the effect of commodity price volatility, we have entered into crude oil and natural gas price hedging arrangements which also serve to enhance the predictability of our cash flows.
Financial Initiatives 
Financial Flexibility, Liquidity and Balance Sheet Strength As we progress through the remainder of 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. See Operating Outlook – 2019 Capital Investment Program.
If commodity prices decline or operating costs 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 changes in our capital program, share repurchase program, dividends policy or operating cost structure, and/or potential asset sales. Our revenues and our stock price could decline as a result of these potential developments.
Recently Issued Accounting Standards
See Item 1. Financial Statements – Note 2. Basis of Presentation.
OPERATING OUTLOOK
2019 Organic Capital Investment Program  Our initial 2019 organic capital program, which excludes capital funded by Noble Midstream Partners and acquisition capital related to the uncertainties inherentEMG Pipeline, ranged from $2.4 to $2.6 billion and was primarily allocated to US onshore development and completion of the Leviathan natural gas project. In second quarter 2019, we lowered our full year organic capital program by $100 million. In third quarter 2019, as a result of US onshore well cost reductions and the Leviathan project spending below budget, we lowered our full year organic capital program by an additional $100 million. Fourth quarter 2019 expected organic capital expenditures range from $425 to $475 million and will primarily be allocated to continued US onshore development and completion of the Leviathan natural gas project. Amounts exclude capital funded by Noble Midstream Partners and acquisition capital related to the EMG Pipeline. See Liquidity and Capital Resources.
Dividends In April, July and October 2019, our Board of Directors approved quarterly cash dividends in any litigation.  We are defending ourselves vigorouslyamounts that represented a 9% increase over the prior year. This is our second straight year to increase our dividend, reflecting our commitment to return value to shareholders.
Colorado Senate Bill 19-181 For some time, initiatives have been underway in allthe State of Colorado to limit or ban 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. The Commission has initiated new rulemakings related to, among other things, incorporating new public health, safety, and environmental priorities into their regulations, updating wellbore integrity and flowline rules, and adopting new alternative location analysis and cumulative impact procedures. In addition, some local communities have adopted further restrictions for oil and gas activities, such mattersas requiring greater setbacks, and other groups have sought a cessation of permit issuances entirely until the Commission publishes new rules in keeping with SB 181.
The majority of our acreage in Colorado is in rural, unincorporated areas of Weld County, and we believe thatcontinue 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 approvals of more than 550 permits to drill wells over the ultimate dispositionnext several years. The approved permits are for wells in multiple Integrated Development Plans (IDPs), many of such proceedingswhich are
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in our Mustang Comprehensive Drilling Plan (CDP). We will notcontinue 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 financial position,cash flows, results of operations, orfinancial condition, and liquidity.
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.flows over the next several years.
MarcellusSanctioned Ongoing Development Projects
A “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 third quarter 2019, our US onshore E&P activities consisted of the following:
LocationAverage Rigs Operated 
Wells Drilled (1)
 Wells Brought Online 
Average Sales Volumes
 (MBoe/d)
DJ Basin2 28 38 158
Delaware Basin3 20 17 70
Eagle Ford Shale— — — 65
Total5 48 55 293
(1)
The number of wells drilled refers to the number of wells completed, regardless of when drilling was initiated.
DJ Basin   During third quarter 2019, we achieved a quarterly average sales volume record of 158 MBoe/d. Our activities were focused primarily on progressing development in the Mustang, which benefits from our approved CDP, Wells Ranch and East Pony areas. We continue to see increased capital efficiencies as a result of improved drilling and completion performance. In the Mustang, we utilized our first electric powered drilling rig, resulting in reduced noise, emissions and fuel costs.
In addition, we submitted an application for approval of the North Wells Ranch CDP. This CDP covers approximately 38,000 net acres and up to 250 potential drilling permits. Final approval is targeted for early 2020.
Delaware Basin During third quarter 2019, we achieved a quarterly average sales volume record of 70 MBoe/d. Our activity focused primarily on drilling and completion optimization, leading to capital and operational cost efficiencies. We brought online our first field power substation, which will provide a reliable power source to support field operations.
Eagle Ford Shale Firm Transportation Contracts During third quarter 2019, we focused on maximizing cash flows from existing production and conducted two well refractures on Gates Ranch. We continue to evaluate and assess our development plan for the area and are incorporating learnings from our refracture results.
International
Leviathan Natural Gas Project (Offshore Israel) As of September 30, 2019, the project was over 90% complete and is ahead of schedule and below budget. During third quarter 2019, the topsides set sail and arrived in Israel, where they were installed, and we completed all subsea construction scope and pre-commissioning activities. The remaining commissioning and operational readiness activities are underway, with first production anticipated in December 2019.
Leviathan and Tamar Gas Sales and Purchase Agreements (Offshore Israel) In connectionOctober 2019, we announced that we and our partners had amended the agreements for the sale of natural gas to Dolphinus Holdings Limited from the Leviathan and Tamar fields. The amended agreements, which are subject to certain regulatory approvals, provide for total combined firm contract quantities of 3.0 trillion cubic feet (Tcf) of natural gas, more than doubling the firm volume commitments previously agreed. In addition, each agreement has been extended by five years to reflect 15-year terms and include take-or-pay commitments. 
During the two-year period ending June 30, 2022, the Leviathan field will backstop any volume commitment that the Tamar field is unable to deliver under the amended agreement.
EMG Pipeline (Offshore Israel) During third quarter 2019, we funded a $185 million investment in EMED Pipeline B.V. in support of its planned acquisition of an approximate 39% equity interest in EMG, which owns the EMG Pipeline. Upon closing of the planned equity transaction, which is anticipated in fourth quarter 2019, we will own an effective, indirect interest of
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approximately 10%, net, in EMG. The EMG Pipeline will support delivery of natural gas from our producing fields offshore Israel into Egypt.
Aseng Development Well (Offshore Equatorial Guinea) During third quarter 2019, the Aseng field surpassed 100 MMBbl of crude oil produced. In addition, we drilled and completed a development well which is expected to mitigate field decline. Production came online in October 2019.
Alen Natural Gas Development (Offshore Equatorial Guinea)   In second quarter 2019, we announced the sanction of the Alen 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 LNG production facility (EG LNG) located at Punta Europa, Bioko Island. Definitive agreements in support of the project have been executed among the Alen field partners, the Alba Plant and EG LNG plant owners, as well as the government of the Republic of Equatorial Guinea.
The Alen natural gas monetization project will produce through three existing high-capacity wells and will require minor platform modifications to deliver sales gas from the Alen field to the Alba Plant and EG LNG facilities. The Alen field partners plan to construct a 24-inch pipeline capable of handling 950 MMcfe/d 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 2021. At start-up, natural gas sales from the Alen field are anticipated to be between 200 and 300 MMcfe/d, gross (approximately 75 to 115 MMcfe/d, net). The wet gas stream will be tolled through the Alba Plant for additional liquids recovery before the dry gas is converted into LNG at the EG LNG facility.
Unsanctioned Projects
Cyprus Natural Gas Project (Offshore Cyprus) We continue to work with the MarcellusGovernment of Cyprus on a plan of development for the Aphrodite field that, as currently 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
US Onshore Acreage Our US onshore unconventional exploration position includes more than 175,000 acres residing in two plays in Wyoming. During third quarter 2019, we progressed activities to obtain required approvals and permits in support of planned future drilling activities.
Offshore Colombia We have signed an agreement for a 40% operated working interest in more than two million gross acres offshore Colombia, located on two blocks. We expect to drill an exploration well in 2020. During third quarter 2019, we continued well planning and permitting activities.
Potential for Future Dry Hole Costs, Lease Abandonment Expense or Property Impairments
Exploration Activities 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 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. Additionally, we may not be able to conduct exploration activities prior to lease expirations or may choose to relinquish or exit licenses or leases. Therefore, future dry hole cost and/or leasehold abandonment expense could be significant. See Item 1. Financial Statements – Note 5. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
Producing Properties A decline in future commodity prices could result in some of our properties becoming uneconomic, resulting in an impairment charge, decrease in proved reserves and/or shut-in of currently producing wells. In addition, in certain US onshore areas, transportation bottlenecks caused by production above transportation capacity and/or lack of infrastructure may reduce the amount of production reaching markets, resulting in lower in-basin pricing (i.e. higher basis differential). An increase in basis differentials could also reduce cash flows and result in property impairment charges.
Results of Operations
Third Quarter 2019 E&P Operating Highlights Included:
total average consolidated sales volumes of 379 MBoe/d, net;
record average daily sales volumes of 127 MBbl/d, net, for US crude oil;
average daily sales volumes of 1.1 Bcfe/d, gross, of natural gas from the Tamar field, offshore Israel;
reached total gross volumes of 2 Tcf of natural gas produced from the Tamar field; and
commencement of crude oil shipments on the EPIC Y-Grade pipeline, which began interim crude service in August.
Third Quarter 2019 E&P Financial Results Included:
additions to equity method investments of $185 million, as compared with zero for third quarter 2018;
capital expenditures, excluding acquisitions, of $540 million, as compared with $696 million for third quarter 2018;
pre-tax income of $205 million, as compared with $225 million for third quarter 2018; and
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net gain on commodity derivative instruments of $129 million, as compared with a net loss of $155 million for third quarter 2018.

The following is a summarized statement of operations for our E&P business:
 Three Months Ended September 30, Nine Months Ended September 30,
(millions)2019 2018 2019 2018
Oil, NGL and Gas Sales to Third Parties$1,003
 $1,136
 $2,894
 $3,409
Sales of Purchased Oil and Gas22
 —
 64
 —
Income from Equity Method Investments and Other15
 34
 48
 105
Total Revenues1,040

1,170

3,006

3,514
Production Expense370
 316
 1,019
 997
Exploration Expense25
 25
 82
 89
Depreciation, Depletion and Amortization544
 456
 1,512
 1,336
Loss (Gain) on Divestitures, Net—
 5
 —
 (356)
Asset Impairments—
 —
 —
 168
Cost of Purchased Oil and Gas17
 —
 59
 —
(Gain) Loss on Commodity Derivative Instruments(129) 155
 23
 483
Income Before Income Taxes205
 225
 216
 720

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Average Oil, NGL and Gas Sales Volumes and PricesAverage daily sales volumes from our share of production and realized sales prices were as follows:
 
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 September 30, 2019
United States 
127
 76
 542
 293
 $55.13
 $11.18
 $1.57
Eastern Mediterranean—
 —
 231
 39
 —
 —
 5.55
West Africa (2)
15
 —
 190
 47
 58.62
 —
 0.27
Total Consolidated Operations (3)
142
 76
 963
 379
 55.48
 11.18
 2.27
Equity Investments (4)
1
 5
 —
 6
 57.44
 25.85
 —
Total (3)
143
 81
 963
 385
 $55.50
 $12.06
 $2.27
Three Months Ended September 30, 2018
United States (5)
109
 63
 464
 249
 $65.54
 $28.58
 $2.31
Eastern Mediterranean—
 —
 241
 41
 —
 —
 5.49
West Africa (2)
13
 —
 217
 49
 73.70
 —
 0.27
Total Consolidated Operations122
 63
 922
 339
 66.41
 28.58
 2.66
Equity Investments (4)
1
 5
 —
 6
 74.88
 48.27
 —
Total123
 68
 922
 345
 $66.50
 $29.92
 $2.66
Nine Months Ended September 30, 2019
United States119
 67
 507
 270
 $55.59
 $14.22
 $1.87
Eastern Mediterranean—
 —
 224
 38
 —
 —
 5.55
West Africa (2)
13
 —
 186
 44
 61.75
 —
 0.27
Total Consolidated Operations (3)
132
 67
 917
 352
 56.18
 14.22
 2.45
Equity Investments (4)
1
 4
 —
 5
 59.81
 30.94
 —
Total (3)
133
 71
 917
 357
 $56.22
 $15.23
 $2.45
Nine Months Ended September 30, 2018
United States (5)
113
 63
 479
 255
 $63.98
 $26.22
 $2.42
Eastern Mediterranean—
 —
 242
 41
 —
 —
 5.48
West Africa (2)
15
 —
 216
 51
 71.55
 —
 0.27
Total Consolidated Operations128
 63
 937
 347
 64.86
 26.22
 2.71
Equity Investments (4)
2
 5
 —
 7
 72.46
 43.70
 —
Total130
 68
 937
 354
 $64.95
 $27.50
 $2.71
(1)
Natural gas is converted on the basis of six Mcf of gas per one barrel of crude oil equivalent (BOE). 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.
(2)
Natural gas from the Alba field 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.
(3)
Includes a small amount of condensate sales from offshore Israel assets.
(4)
Volumes represent sales of condensate and LPG from the LPG plant in Equatorial Guinea. See Income from Equity Method Investments.
(5)
Includes 9 MBoe/d for first nine months of 2018 related to Gulf of Mexico assets sold in second quarter 2018. See Item 1. Financial Statements – Note 4. Acquisitions and Divestitures.
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An analysis of revenues from sales of crude oil, NGLs and natural gas is as follows:
(millions)Crude Oil & Condensate NGLs Natural Gas Total
Three Months Ended September 30, 2018$744
 $166
 $226
 $1,136
Changes due to       
Increase in Sales Volumes123
 30
 7
 160
Decrease in Sales Prices (1)
(143) (118) (32) (293)
Three Months Ended September 30, 2019$724
 $78
 $201
 $1,003
        
Nine Months Ended September 30, 2018$2,266
 $449
 $694
 $3,409
Changes due to       
Increase (Decrease) in Sales Volumes123
 22
 (30) 115
Decrease in Sales Prices (1)
(365) (213) (52) (630)
Nine Months Ended September 30, 2019$2,024
 $258
 $612
 $2,894
(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 SalesRevenues Revenues from crude oil and condensate sales decreased in third quarter and the first nine months of 2019 as compared with 2018 primarily due to the following:    
•
decreases in average realized prices for third quarter and the first nine months of 2019 (see Executive Overview – Operational Environment Update – Commodity Prices);
reduction in sales volumes of 7 MBbl/d for the first nine months of 2019 due to the sale of our Gulf of Mexico assets in second quarter 2018; and
lower West Africa sales volumes of 2 MBbl/d for the first nine months of 2019 due to timing of liftings and natural field decline;
partially offset by:
higher US onshore sales volumes of 18 MBbl/d and 13 MBbl/d for third quarter and the first nine months of 2019, respectively, primarily due to an increase in development activity in the DJ and Delaware Basins.
NGL SalesRevenues Revenuesfrom NGL sales decreased in third quarter and the first nine months of 2019 as compared with 2018 primarily due to the following:
•
decreases in average realized prices for third quarter and the first nine months of 2019 (see Executive Overview – Operational Environment Update – Commodity Prices); and
lower Eagle Ford Shale upstream divestiture,sales volumes of 8 MBbl/d for the first nine months of 2019 due to reduced activity and natural field decline;
partially offset by:
higher sales volumes in the DJ and Delaware Basins of 12 MBbl/d and 12 MBbl/d for third quarter and the first nine months of 2019, respectively, due to an increase in development activities.
Natural Gas SalesRevenuesRevenues from natural gas sales decreased in third quarter and the first nine months of 2019 as compared with 2018 primarily due to the following:
•
decreases in average realized prices for third quarter and the first nine months of 2019 (see Executive Overview – Operational Environment Update – Commodity Prices);
lower Eagle Ford Shale sales volumes of 10 MMcf/d and 51 MMcf/d for third quarter and the first nine months of 2019, respectively, due to reduced activity and natural field decline;
lower West Africa sales volumes of 27 MMcf/d and 30 MMcf/d for third quarter and the first nine months of 2019, respectively, due to natural field decline and planned maintenance at onshore facilities during first quarter 2019, which required field shut-in for a portion of the period; and
lower Israel sales volumes of 10 MMcf/d and 18 MMcf/d for third quarter and the first nine months of 2019, respectively, primarily due to planned maintenance and the sale of a 7.5% interest in the Tamar field in March 2018;
partially offset by:
higher sales volumes in the DJ and Delaware Basins of 88 MMcf/d and 87 MMcf/d for third quarter and the first nine months of 2019, respectively, due to an increase in development activities.
Sales and Cost of Purchased Oil and GasIn third quarter and the first nine months of 2019, we reducedengaged in third party sales and purchases of crude oil in the DJ Basin for flow assurance on pipelines used to deliver our firmproduction to market.
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Income from Equity Method Investments and OtherIncome from equity method investments and other decreased in the first nine months of 2019 as compared with 2018. The decrease includes a $34 million decrease from Atlantic Methanol Production Company, LLC (AMPCO), our methanol investment, and a $24 million decrease from Alba Plant, our LPG investment, primarily due to decreases in average realized methanol and LPG prices and plant downtime due to planned maintenance activities.
Production Expense Components of production expense were as follows:
(millions, except unit rate)
Total per BOE (1)(2)
 Total 
United States (2)
 Eastern Mediterranean West Africa
Three Months Ended September 30, 2019         
Lease Operating Expense (3)
$4.02
 $140
 $111
 $7
 $22
Production and Ad Valorem Taxes1.47
 51
 51
 —
 —
Gathering, Transportation and Processing5.00
 174
 173
 1
 —
Other Royalty Expense0.14
 5
 5
 —
 —
Total Production Expense$10.64
 $370
 $340
 $8
 $22
Total Production Expense per BOE  $10.64
 $12.61
 $2.24
 $5.17
Three Months Ended September 30, 2018 
  
  
  
  
Lease Operating Expense (3)
$4.37
 $136
 $114
 $7
 $15
Production and Ad Valorem Taxes1.48
 46
 46
 —
 —
Gathering, Transportation and Processing4.14
 129
 129
 —
 —
Other Royalty Expense0.16
 5
 5
 —
 —
Total Production Expense$10.15
 $316
 $294
 $7
 $15
Total Production Expense per BOE  $10.15
 $12.82
 $1.90
 $3.32
Nine Months Ended September 30, 2019         
Lease Operating Expense (3)
$4.50
 $432
 $350
 $26
 $56
Production and Ad Valorem Taxes1.44
 138
 138
 —
 —
Gathering, Transportation and Processing4.59
 440
 439
 1
 —
Other Royalty Expense0.09
 9
 9
 —
 —
Total Production Expense$10.63
 $1,019
 $936
 $27
 $56
Total Production Expense per BOE  $10.63
 $12.70
 $2.63
 $4.70
Nine Months Ended September 30, 2018 
  
  
  
  
Lease Operating Expense (3)
$4.54
 $429
 $354
 $19
 $56
Production and Ad Valorem Taxes1.55
 147
 147
 —
 —
Gathering, Transportation and Processing4.11
 389
 389
 —
 —
Other Royalty Expense0.34
 32
 32
 —
 —
Total Production Expense$10.54
 $997
 $922
 $19
 $56
Total Production Expense per BOE  $10.54
 $13.22
 $1.73
 $4.04
(1)
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investments.
(2)
US production expense includes charges from our midstream operations that are eliminated on a consolidated basis.
(3)
Lease operating expense includes oil and gas operating costs (labor, fuel, repairs, replacements, saltwater disposal and other related lifting costs) and workover expense.
Production expense for third quarter and the first nine months of 2019 increased as compared with 2018, primarily due to the following:
increase in US gathering, transportation commitment through transferand processing (GTP) expense primarily due to increased development activities in our DJ and Delaware Basins and higher rates in our DJ Basin;
increase in Eastern Mediterranean lease operating expense due to planned maintenance activities; and
increase in West Africa lease operating expense due to increase in volumes lifted from the higher-cost Alen field;
partially offset by:
decrease in US lease operating expense primarily due to the sale of our Gulf of Mexico assets and cost reduction efforts in our US onshore basins; and
decrease in US other royalty expense due to lower commodity prices.
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The unit rate per BOE increased for third quarter and the first nine months of 2019 as compared with 2018 primarily due to an increase in GTP expense, as noted above, and an increase in volumes from higher-cost areas within US onshore and West Africa, partially offset by cost reduction efforts in our US onshore basins.
Exploration Expense Exploration expense for third quarter and the first nine months of 2019 totaled $25 million and $82 million, respectively, including staff expense of $10 million and $34 million, respectively. Exploration expense for third quarter and the first nine months of 2018 totaled $25 million and $89 million, respectively, including staff expense of $14 million and $41 million, respectively.
Depreciation, Depletion and Amortization (DD&A) Expense DD&A expense was as follows:
(millions, except unit rate)Total United States Eastern Mediterranean West Africa Other Int'l
Three Months Ended September 30, 2019         
DD&A Expense$544
 $505
 $17
 $21
 $1
Unit Rate per BOE (1)
$15.64
 $18.73
 $4.76
 $4.94
 $—
Three Months Ended September 30, 2018         
DD&A Expense$456
 $414
 $16
 $25
 $1
Unit Rate per BOE (1)
$14.64
 $18.05
 $4.34
 $5.53
 $—
Nine Months Ended September 30, 2019         
DD&A Expense$1,512
 $1,401
 $50
 $60
 $1
Unit Rate per BOE (1)
$15.77
 $19.01
 $4.86
 $5.04
 $—
Nine Months Ended September 30, 2018         
DD&A Expense$1,336
 $1,214
 $44
 $77
 $1
Unit Rate per BOE (1)
$14.12
 $17.41
 $4.00
 $5.55
 $—
(1)
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investments.
DD&A expense for third quarter and the first nine months of 2019 increased as compared with 2018, primarily due to the following:
capital investment and development activities in the DJ and Delaware Basins resulting in higher sales volumes; and
increase in Eastern Mediterranean due to the retirement of certain contractscapital assets resulting in accelerated depreciation;
partially offset by:
decrease resulting from the sale of our Gulf of Mexico assets in second quarter 2018; and
reduced sales volumes in West Africa, as noted above, and reserves additions subsequent to third quarter 2018.
The unit rate per BOE for third quarter and the first nine months of 2019 increased as compared with 2018, primarily due to the acquirer.increase in total DD&A expense, as noted above. Specifically, development activity increased in the higher-cost Delaware Basin and the 2018 sale of lower-cost Tamar reserves increased the overall unit rate per BOE. The rate was also impacted by year-end 2018 update to proved reserves quantities used to calculate DD&A, which reflected negative non-price reserves revisions recorded for the Delaware Basin attributable to changes in expected recoveries and higher operating and capital costs. The increase in the unit rate is partially offset by the sale of higher-cost production from the Gulf of Mexico assets.
We retainedLoss on Commodity Derivative Instruments  Loss on commodity derivative instruments for the first nine months of 2019 decreased as compared with 2018.
For the first nine months of 2019, loss on commodity derivative instruments included:
net cash receipts of $28 million; and
net non-cash decrease of $51 million in the fair value of our net commodity derivative asset, primarily driven by changes in the forward commodity price curves for crude oil.     
For the first nine months of 2018, loss on commodity derivative instruments included:
net cash payments of $160 million; and
net non-cash decrease of $323 million in the fair value of our net commodity derivative liability, primarily driven by changes in the forward commodity price curves for crude oil.
See Item 1. Financial Statements – Note 12. Derivative Instruments and Hedging Activities.
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RESULTS OF OPERATIONS – MIDSTREAM
The Midstream segment develops, owns and operates domestic midstream infrastructure assets, as well as invests in other midstream projects, with current focus in the DJ and Delaware Basins.
Results of Operations
Third Quarter 2019 Midstream Operating Highlights and Financial Results Included:
entered into a strategic relationship with Saddlehorn Pipeline Company, LLC (Saddlehorn);
total revenues of $186 million, as compared with $168 million for third quarter 2018;
pre-tax income of $83 million, as compared with pre-tax income of $268 million for third quarter 2018; and
��additions to equity method investments of $86 million, as compared with zero for third quarter 2018.
The following is a summarized statement of operations for our Midstream segment:
 Three Months Ended September 30, Nine Months Ended September 30,
(millions)2019 2018 2019 2018
Midstream Services Revenues – Third Party$19
 $21
 $63
 $49
Sales of Purchased Oil and Gas47
 46
 132
 110
(Loss) Income from Equity Method Investments(5) 10
 (5) 35
Intersegment Revenues125
 91
 322
 257
Total Revenues186
 168
 512
 451
Operating Costs and Expenses31
 30
 108
 96
Depreciation, Depletion and Amortization26
 24
 77
 62
Gain on Divestitures, Net—
 (198) —
 (503)
Cost of Purchased Oil and Gas46
 44
 125
 106
Total Expense (Income)103
 (100) 310
 (239)
Income Before Income Taxes$83
 $268
 $202
 $690
Midstream Services Revenues – Third Party The amount of revenue generated by the Midstream segment depends primarily on the volumes of crude oil, natural gas and water for which services are provided to dedicated acreage for our E&P business and to third-party customers. These volumes are affected by the level of drilling and completion activity and by changes in the supply of, and demand for, crude oil, NGLs and natural gas in the markets served directly or indirectly by our midstream assets.
Midstream services revenues for the first nine months of 2019 increased as compared with 2018, primarily due to increases in crude oil, natural gas and produced water gathering services and fresh water delivery. The increases were due primarily to higher Delaware Basin throughput volumes, commencement of services in the Mustang IDP in 2018, and services related to the Black Diamond system, which was acquired during first quarter 2018 in the Saddle Butte acquisition.
Sales and Costs of Purchased Oil and Gas Sales and costs of purchased oil for third quarter and the first nine months of 2019 increased as compared with 2018 due to a full nine months of services related to the Black Diamond system.
(Loss) Income from Equity Method Investments Income from equity method investments decreased for third quarter and the first nine months of 2019 as compared with 2018, primarily due to the sale of our investment in CNX Midstream Partners in second quarter 2018 and operating losses associated with EPIC Y-Grade, EPIC Crude Holdings and Delaware Crossing. Operating losses were primarily due to expenses incurred for the formation of the joint ventures and general and administrative expenses incurred prior to service commencement.
Operating Costs and Expenses Operating costs and expenses for third quarter and the first nine months of 2019 increased as compared with 2018, primarily due to an increase in gathering systems operating expense associated with the Delaware 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 services in the Mustang IDP in 2018.
DD&A Expense DD&A expense for third quarter and the first nine months of 2019 increased as compared with 2018, primarily due to certain other firm transportation contracts representing a total financial commitment of approximately $1.6 billion, undiscounted, primarily with remaining contract terms of 15 years. Of this amount, approximately $627 million, undiscounted, relates to two pipeline projects which are currently under construction and targeted to beassets being placed in service mid-to-late fourthsubsequent to third quarter 2017.2018, including the Mustang IDP gathering system, the Delaware Basin CGFs, and additional Black Diamond assets. In addition, DD&A expense includes a full nine months of amortization related to intangible assets acquired in the Saddle Butte acquisition.
Gain on Divestitures, Net Gain on divestitures, net relates to 2018 sales of our interest in CONE Gathering and our investment in CNX Midstream Partners. See Item 1. Financial Statements - Note 4. Acquisitions and Divestitures.
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Saddlehorn In third quarter 2019, Noble Midstream Partners entered into a strategic relationship with Saddlehorn, resulting in new long-term firm transportation commitments and an option to acquire up to a 20% ownership interest in Saddlehorn, which transports crude oil and condensate from the DJ and Powder River Basins to storage facilities in Cushing, Oklahoma. The investment option expires in April 2020.
RESULTS OF OPERATIONS – CORPORATE
Expenses related to debt, such as interest and other debt-related costs, headquarters depreciation, corporate general and administrative (G&A) expenses, exit costs and certain costs associated with mitigating the effects of our retained Marcellus Shale transportation agreements, are recorded at the Corporate level.
Transportation Exit Cost Revenues and expenses associated with retained Marcellus Shale transportation contracts were as follows:
 Three Months Ended September 30, Nine Months Ended September 30,
(millions)2019 2018 2019 2018
Sales of Purchased Gas (1)
$18
 $26
 $68
 $81
Cost of Purchased Gas (1)
33
 32
 112
 98
Firm Transportation Exit Cost (2)
—
 —
 92
 —
(1)
Relates to third party mitigation activities we engage in to utilize a portion of our Marcellus Shale transportation commitment. Cost of purchased gas includes utilized and unutilized transportation expense. Amounts for the nine months ended 2019 increased as compared to 2018 due to increased transportation expense for pipelines that came into service in fourth quarter 2018.
(2)
Represents exit costs related to future commitments to a third party resulting from a permanent capacity assignment.
See Item 1. Financial Statements – Note 9. Exit Cost – Transportation Commitments.
General and Administrative Expense   G&A expense was as follows:
 Three Months Ended September 30, Nine Months Ended September 30,
(millions, except unit rate)2019 2018 2019 2018
G&A Expense$91
 $107
 $298
 $316
Unit Rate per BOE (1)
$2.62
 $3.44
 $3.11
 $3.34
(1)
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investments.
Due to our focus on overall G&A cost reductions, expense for third quarter and the first nine months of 2019 decreased as compared with 2018, and we achieved a 15% reduction as compared to third quarter 2018. Decreases were primarily due to reduced employee, office and travel expenses, partially offset by increases in technology costs. The unit rate per BOE for third quarter and the first nine months of 2019 also decreased as compared with 2018 due to the reduction in G&A expense and the increase in the total sales volumes.
Interest Expense and Capitalized Interest  Interest expense and capitalized interest were as follows:
 Three Months Ended September 30, Nine Months Ended September 30,
(millions, except unit rate)2019 2018 2019 2018
Interest Expense, Gross$92
 $88
 $269
 $269
Capitalized Interest(25) (18) (73) (53)
Interest Expense, Net$67
 $70
 $196
 $216
Unit Rate per BOE (1)
$1.93
 $2.25
 $2.04
 $2.28
(1)
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investments.
Interest expense, gross, for third quarter and the first nine months of 2019 remained relatively flat as compared with 2018. See Item 1. Financial Statements – Note 7. Debt. Capitalized interest for third quarter and the first nine months of 2019 increased as compared with 2018, primarily due to higher work in progress amounts related to Leviathan development and additions to equity method investments engaged in construction activities.
The unit rate per BOE for third quarter and the first nine months of 2019 decreased as compared with 2018, primarily due to the reduction in net interest expense, noted above, and the increase in total sales volumes.
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 commodity price cycles, including a sustained period of low prices.
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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 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. We occasionally access the capital markets to ensure adequate liquidity exists in negotiations with third partiesthe form of unutilized capacity under our Revolving Credit Facility or to refinance scheduled debt maturities. Refer to Noble Midstream Services 2019 Term Loan Credit Facility and Subsequent Event below for recently completed capital market activities.
Supported by our investment grade credit rating, we established a $4.0 billion commercial paper program in first quarter 2019. This program can be accessed as needed to supplement operating cash flows for short-term funding needs. In addition, we may from time to time seek to retire or purchase our outstanding senior notes through cash purchases in the commercializationopen market, privately negotiated transactions or otherwise. Such repurchases, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and permanent assignment or releaseother factors.
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. Additionally, we enter into crude oil and natural gas price hedging arrangements in an effort to mitigate the effects of commodity price volatility and enhance the predictability of cash flows relating to the marketing of a portion of our capacitycrude oil and natural gas production.
Thus far in 2019, we have funded our capital program with cash flows from operations, cash on hand, commercial paper borrowings, and proceeds from divestments of non-strategic assets. We did not repurchase any shares of Noble Energy common stock under these contractsthe Board of Directors-authorized $750 million share repurchase program during the first nine months of 2019.
Third Quarter 2019 Highlights
During third quarter 2019, we completed the following financing activities:
borrowed $271 million, net, under our $4.0 billion commercial paper program for working capital purposes;
repaid $320 million, net, under the Noble Midstream Services Revolving Credit Facility; and
borrowed $400 million under the Noble Midstream Services 2019 Term Loan Credit Facility, primarily to repay a portion of borrowings outstanding under the Noble Midstream Services Revolving Credit Facility.
Available Liquidity
The following table summarizes our cash, debt and available liquidity:
 September 30, 2019 December 31, 2018
(millions, except percentages)
Noble Energy Excluding
Noble Midstream Partners
 Noble Midstream Partners Total 
Noble Energy Excluding
Noble Midstream Partners
 Noble Midstream Partners Total
Total Cash (1)
$455
 $18
 $473
 $707
 $12
 $719
Amounts Available for Borrowing (2)
3,489
 —
 3,489
 4,000
 —
 4,000
Total Liquidity$3,944
 $18
 $3,962
 $4,707
 $12
 $4,719
            
Total Debt (3)
$6,601
 $950
 $7,551
 $6,115
 $560
 $6,675
Noble Energy Share of Equity    $9,004
     $9,426
Ratio of Debt-to-Book Capital (4)
    46%     41%
(1)
Total cash includes $3 million of restricted cash at December 31, 2018.
(2)
Excludes amounts available to be borrowed under the Noble Midstream Services Revolving Credit Facility, which is not available to Noble Energy for general corporate purposes.
(3)
Total debt excludes unamortized debt discount/premium and debt issuance costs. See Item 1. Financial Statements – Note 7. Debt.
(4)
We define our ratio of debt-to-book capital as total debt divided by the sum of total debt plus Noble Energy's share of equity.
Cash and Cash EquivalentsWe had $473 million in cash and cash equivalents at September 30, 2019, primarily denominated in US dollars and invested in money market funds and short-term deposits with major financial institutions. Approximately
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$430 million of this cash is attributable to our foreign subsidiaries. We do not expect to incur significant US income tax expense with respect to future repatriation of foreign cash.
Revolving Credit Facilities and Commercial Paper Program Noble Energy's $4.0 billion Revolving Credit Facility and the $800 million Noble Midstream Services Revolving Credit Facility both mature in 2023. These facilities are used to fund capital investment programs and acquisitions and may periodically provide amounts for working capital purposes. Additionally, in first quarter 2019, we established a commercial paper program to provide for short-term funding needs. The program allows for a maximum of $4.0 billion of unsecured commercial paper notes and is supported by Noble Energy's Revolving Credit Facility.
At September 30, 2019, outstanding commercial paper borrowings of $511 million reduced the amount available for borrowing under Noble Energy's Revolving Credit Facility to approximately $3.5 billion. Additionally, at September 30, 2019, $50 million was outstanding under the Noble Midstream Services Revolving Credit Facility, leaving $750 million available for borrowing. See Item 1. Financial Statements – Note 7. Debt.
Noble Midstream Services 2019 Term Loan Credit Facility In August 2019, Noble Midstream Services entered into a three-year senior unsecured term loan agreement, which would reduceprovides for aggregate borrowings of up to $400 million. Noble Midstream Services borrowed $400 million in third quarter 2019. See Item 1. Financial Statements – Note 7. Debt.
GIP Preferred Equity Commitment In March 2019, Noble Midstream Partners 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 – Note4. Acquisitions and Divestitures.
Subsequent Event On October 1, 2019, we issued $1.0 billion of notes, using proceeds from the issuance to fund the tender offer and redemption of our undiscounted financial commitment. As these pipeline projects become commercially available to us$1.0 billion 4.15% notes due December 15, 2021. In connection with the tender and our commitment begins,redemption, in fourth quarter 2019, we will evaluate our position, commercialization activities and ability to utilize retained capacity. If we determine that we will not utilize a portion, or all,record early debt extinguishment fees of the contracted and retained pipeline capacity, we will accrue a liability, at fair value, for the net amount of the estimated remaining financial commitment and include the related expense in operating expenseapproximately $44 million in our consolidated statements of operations. At this time,See Item 1. Financial Statements – Note 7. Debt.
Contractual Obligations
Marcellus Shale Transportation Commitments We have remaining financial commitments of approximately $1.0 billion, undiscounted, associated with Marcellus Shale transportation contracts. See Item 1. Financial Statements – Note 9. Exit Cost – Transportation Commitments.
Letters of CreditIn the ordinary course of business, we are unable to predictmaintain letters of credit and bank guarantees with certainty the outcomea variety of banks in support of certain performance obligations of our commercializationsubsidiaries. Outstanding letters of credit and bank guarantees, including those of Noble Midstream Partners, totaled approximately $121 million at September 30, 2019.
Cash Flows
The following table summarizes our total cash provided by (used in) operating, investing and financing activities:
 Nine Months Ended September 30,
 (millions)2019 2018
Operating Activities$1,529
 $1,776
Investing Activities(2,528) (1,502)
Financing Activities753
 (266)
(Decrease) Increase in Cash, Cash Equivalents and Restricted Cash$(246) $8
Operating ActivitiesCash provided by operating activities our abilityfor the first nine months of 2019 decreased $247 million as compared with 2018. The decrease was primarily driven by a decrease in net revenues driven by lower commodity prices and higher production costs attributable to utilize retained capacityincreased operational activity in US onshore, partially offset by cash received in settlements for commodity derivatives of $28 million, as compared with cash payments of $160 million in the prior year.
Investing Activities   Cash used in investing activities increased approximately $1.0 billion for the first nine months of 2019 as compared with 2018, primarily due to a decrease in net proceeds provided by divestitures and additions to equity method investments of $686 million. These were partially offset by a decrease in capital spending for property, plant and equipment and the timingabsence of when we may recognize a non-cash exit cost in line with accounting for exit costs associated with these two pipeline projects. See Note 2. Basis of Presentation.
The remaining commitments relatespending on acquisitions, compared to two additional pipeline projects that are targeted to be placed in service late 2018, one of which has not yet been approved by the FERC. We continue to monitor and assess the status of these pipeline projects, including regulatory approval and construction progress, and are evaluating commercialization options.
We cannot guarantee our commercialization efforts will be successful and we may recognize substantial future liabilities, at fair value, for the net amount of the estimated remaining commitments under these contracts. These financial commitments are included$653 million in the table below consistent with expected futureprior year.
Financing Activities  Our financing activities during the first nine months of 2019 included net borrowings of $511 million under the commercial paper program, Noble Midstream Partners' borrowings of $400 million on the Noble Midstream Services 2019 Term Loan Credit Facility, the receipt of $97 million of GIP preferred equity, net of offering costs, and net repayments of
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$10 million on the Noble Midstream Services Revolving Credit Facility. Proceeds from the 2019 Term Loan Credit Facility were used to repay borrowings on Noble Midstream Services Revolving Credit Facility. In addition, during the first nine months of 2019, we paid $168 million of cash payments associated withdividends to Noble Energy shareholders.
Our financing activities during the underlying agreements.first nine months of 2018 included a $230 million, net, Revolving Credit Facility repayment and $35 million, net, Noble Midstream Services Revolving Credit Facility repayment, which included borrowings of $465 million primarily used to fund the Saddle Butte acquisition, offset by a repayment of $500 million drawn under the Noble Midstream Services 2018 Term Loan Credit Facility. We used $384 million of cash to redeem senior notes, repurchased $223 million of common stock pursuant to our stock repurchase program, paid $156 million of cash dividends to Noble Energy shareholders and paid $35 million of cash distributions to Noble Midstream Partners noncontrolling interest owners. We also received $348 million of contributions from noncontrolling interest owners. See Note Item 1. Financial Statements – Consolidated Statements of Cash Flows4. Acquisitions and Divestitures..
Non-Cancelable Leases and Other Commitments We hold leases and other commitments for drilling rigs, buildings, equipment and other property and have entered into numerous long-term contracts for gathering, processing and transportation services. Minimum commitments have been updated to give effect to the Clayton Williams Energy Acquisition, the Marcellus Shale upstream divestiture,Capital Expenditure Activities
Our capital expenditures (on an accrual basis) were as well as commitments related to Leviathan development activities, and consist of the following as of September 30, 2017:follows:
(millions) 
Drilling, Equipment,
and Purchase Obligations
 
Transportation
and Gathering Obligations(1)
 
Operating
Lease
 Obligations
 
 Capital
 Lease Obligations(2)
 Total
October - December 2017 $136
 $53
 $12
 $20
 $221
2018 425
 247
 43
 74
 789
2019 148
 276
 32
 45
 501
2020 26
 249
 32
 42
 349
2021 7
 213
 32
 29
 281
2022 and Thereafter 36
 1,499
 189
 145
 1,869
Total $778
 $2,537
 $340
 $355
 $4,010
 Three Months Ended September 30, Nine Months Ended September 30,
(millions)2019 2018 2019 2018
Unproved Property Acquisition (1)
$(4) $8
 $35
 $21
Proved Property Acquisition (1)
—
 —
 4
 —
Exploration and Development518
 676
 1,728
 2,090
Midstream (2)
56
 69
 174
 685
Corporate and Other21
 11
 52
 38
Total$591
 $764
 $1,993
 $2,834
        
Additions to Equity Method Investments       
EMED Pipeline B.V.$185
 $—
 $185
 $—
EPIC Y-Grade18
 —
 169
 —
EPIC Crude Holdings54
 —
 273
 —
Delaware Crossing14
 —
 53
 —
Other—
 —
 6
 —
Total Additions to Equity Method Investments (3)
$271
 $—
 $686
 $—
        
Increase in Finance Lease Obligations$1
 $9
 $4
 $9
(1)
Includes approximately $1.6 billion of future cash payments relatedCosts relate to retained Marcellus Shale firm transportation contracts. See discussion above.US onshore leasehold activity.
(2)
Midstream expenditures for the nine months ended September 30, 2018 include $206 million related to the Saddle Butte acquisition.
(3)
Annual lease payments, net to our interest, exclude regular maintenanceSee Item 1. Financial Statements – Note4. Acquisitions and operating costs. See Note 6. DebtDivestitures.

Exploration and development costs for third quarter and the first nine months of 2019 decreased as compared with 2018 due to our focus on US onshore capital efficiencies and the near-term completion of Leviathan development activities. Year-to-date exploration and development costs include approximately $1.3 billion for US onshore and $368 million for Eastern Mediterranean, primarily related to Leviathan.
Colorado Air Matter In April 2015, we entered intoMidstream capital spending, excluding acquisitions, for third quarter and the first nine months of 2019 decreased as compared with 2018. 2019 activities focused primarily on well connections in the DJ and Delaware Basins, as well as expansion of the Mustang IDP gathering system. 2018 activities included construction and commencement of services for the Mustang IDP gathering and fresh water systems, Delaware Basin CGFs, and connecting the Black Diamond system to a joint consent decree (Consent Decree) withmajor crude oil takeaway outlet in the US Environmental Protection Agency, US DepartmentDJ Basin.
Dividends
On October 22, 2019, our Board of Justice, and StateDirectors declared a quarterly cash dividend of Colorado12 cents per Noble Energy common share, which will be paid on November 18, 2019 to improve emission control systemsshareholders of record on November 4, 2019. The amount of future dividends will be determined on a quarterly basis at a numberthe discretion of our condensate storage tanks that are partBoard of our upstream crude oilDirectors and natural gas operations within the Non-Attainment Area of the DJ Basin. The Consent Decree was entered by the courtwill depend on June 2, 2015.   earnings, financial condition, capital requirements and other factors.
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 injunctive relief activities and to complete mitigation projects and supplemental environmental projects (SEP), and pay a civil penalty. Costs associated with the settlement consist of $4.95 million in civil penalties which were paid in 2015. Mitigation costs of $4.5 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. During 2015 and 2016, we spent approximately $54.7 million to undertake injunctive relief 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.
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 Air Compliance Order on Consent In April 2017, we received a proposed Compliance Order on Consent (COC) from the Colorado Department of Public Health and Environment’s Air Pollution Control Division (APCD) to resolve allegations of noncompliance associated with compliance testing of certain engines subject to various General Permit 02 conditions and/or individual permit conditions. In May 2017, we reached a final resolution with the APCD and executed the COC, which requires payment of a civil penalty of $24,710 and an expenditure of no less than $98,840 on an approved SEP(s). This resolution is not believed to have a material adverse effect on our financial position, results of operations or cash flows. 
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Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide a narrative about our business from the perspective of 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&P;
•
Results of Operations – Midstream;
•
Liquidity and Capital Resources; and
•
Critical Accounting Policies and Estimates, Update. 
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 third quarter 2017. This discussion should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2016, which includes disclosures regarding our critical accounting policies as part of “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Current Upstream Environment
Crude Oil PricesCrude oil prices strengthened during third quarter 2017 lifting the West Texas Intermediate (WTI) to settlements above $50 per barrel, consistent with prices seen earlier in the year, and the Brent index rallied with a two-year high of nearly $60 per barrel. The increase in crude oil prices provides evidence of rebalancing between supply and demand. On the supply side, certain global producers continue to adhere to production cuts in an attempt to lower excess supply, while global demand has increased driven by usage in refineries and consumption in the European and US markets.
For the remainder of 2017, inventory and production levels, particularly US onshore supply growth and the effectiveness of OPEC-led curtailment actions, as well as OPEC production from countries not bound to OPEC curtailments, such as Libya and Nigeria, are likely to be the primary determinants of near-term crude oil prices with the risk that strong production trends cause crude oil prices to remain capped or possibly decline. Adherence to current and possible future OPEC decisions regarding extension of production curtailments, changes in crude oil storage levels and US shale oil production trends, are likely to continue to have significant impacts on crude oil prices.
Natural Gas PricesThe US domestic natural gas market remains oversupplied as domestic production has continued to grow due to drilling efficiencies, completion of drilled but uncompleted well inventory and de-bottlenecking of transportation infrastructure. In contrast to crude oil supply curtailments, there has been little to offset natural gas supply growth, which continues to outpace natural gas demand domestically. As a result, during the first nine months of 2017, natural gas prices remained range bound. We expect this situation to continue for the remainder of 2017, with natural gas prices near current or recent trading levels.
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Price Trend Chart The chart below shows the historical trend in benchmark prices for WTI crude oil, Brent crude oil and U.S. Henry Hub natural gas.

pricingindexperformance3q17.jpg

Development and Operating Costs Third party oilfield service and supply costs are also subject to supply and demand dynamics. During the first nine months of 2017, increases in US onshore drilling and completion activity resulted in higher demand for oilfield services. As a result, the costs of drilling, equipping and operating wells and infrastructure have begun to experience some inflation, which, along with the current commodity prices noted above, results in continued pressures on industry operating margins. Conversely, the industry has reduced capital-intensive offshore exploration and drilling activities in response to the commodity price environment. As a result, demand for and costs associated with offshore services have declined and in the near-term, will likely not be subject to cost inflation.
Recent Achievements 
Despite the current commodity price and cost environment, Noble Energy has had a very successful 2017 thus far, achieving several strategic, operational and financial goals. Strategically, we closed several transformative portfolio transactions demonstrating our continued focus on enhancing margins and project returns. Operationally, we continued to enhance US onshore drilling and completions and advanced our Eastern Mediterranean regional natural gas developments. Financially, we continued to maintain our strong balance sheet and liquidity position.
Clayton Williams Energy Acquisition On April 24, 2017, we completed the acquisition (Clayton Williams Energy Acquisition) of Clayton Williams Energy, Inc. (Clayton Williams Energy) for $2.5 billion of stock and cash consideration. In connection with the acquisition, we assumed, and then subsequently retired, $595 million of Clayton Williams Energy long-term debt. The transaction adds highly contiguous acreage in the core of the Delaware Basin and materially expands our Delaware position to approximately 118,000 net acres. The integration of the Clayton Williams Energy assets into our portfolio expands our opportunities in the core, high crude oil content area of the Delaware Basin, significantly increasing our US onshore growth outlook. See Item 1. Financial Statements – Note 3. Clayton Williams Energy Acquisition.
Marcellus Shale Upstream Divestiture On June 28, 2017, we closed the sale of the Marcellus Shale upstream assets, receiving net proceeds of $1.0 billion. The divestment enables us to further focus our organization on our highest-return areas that are expected to deliver US onshore volume and cash flow growth. In addition, we have signed a definitive agreement to divest our Marcellus Shale midstream business for $765 million. See Item 1. Financial Statements – Note 4. Acquisitions and Divestitures and Note 12. Commitments and Contingencies.  
Midstream GrowthAlong with our upstream portfolio actions, we continued to grow our Midstream business and completed our first drop-down transaction of midstream assets to Noble Midstream Partners L.P. (NBLX) for total consideration of $270 million.
Operational Accomplishments Operationally, we delivered quarterly sales volumes of 355 MBoe/d with approximately 54% of our production mix attributable to crude oil and NGLs, established an all-time record for quarterly gross sales volumes of 997 MMcfe/d in Israel primarily from the Tamar field and continued to progress the Leviathan development project within budget towards first natural gas production by the end of 2019. See Project Updates, below, and Result of Operations.
Financial Flexibility, Liquidity and Balance Sheet Strength We continue to undertake proactive and strategic actions to maintain liquidity and a strong balance sheet. During third quarter 2017, for example, we engaged in debt refinancing activities
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which collectively enhance our financial flexibility and result in future interest expense savings. In addition, during second quarter 2017, we utilized proceeds received from the Marcellus Shale upstream divestiture and NBLX drop-down transaction to offset the cash impact of the Clayton Williams Energy Acquisition. Proceeds received from these transactions were used to retire $1.3 billion borrowed under our Revolving Credit Facility to pay for the cash consideration of the Clayton Williams Energy Acquisition and associated costs, as well as the retirement of all $595 million of assumed Clayton Williams Energy debt. We strive to maintain a robust liquidity position and ended third quarter 2017 with approximately $4.3 billion of liquidity, which includes cash on hand and unused borrowing capacity. See Liquidity and Capital Resources.
Positioned for the Future 
We believe the following guiding principles will contribute to the sustainability and success of our business throughout the commodity price cycle, including extended periods of lower prices:
Execution of a disciplined capital allocation process by:
◦designing a flexible investment program aligned with the current commodity price environment; and
◦maintaining a strong balance sheet and liquidity position.
Enhancing capital efficiencies through:
◦utilizing our technical competencies and applying historical learnings from unconventional US shale plays to reduce US onshore finding and development costs; and
◦driving Delaware Basin economics through development cycle efficiencies.
Leveraging the benefits of our well-positioned and diversified portfolio including:
◦exercising investment optionality and flexibility afforded by our assets held by production; and
◦continuing portfolio optimization actions to maximize strategic value.
Capitalizing on a currently low-cost offshore environment with execution of high-quality long-cycle development projects, such as:
◦sanctioning and commencing the first phase of Leviathan field development.
Maintaining financial strength through:
◦focusing operational activities on high-margin, high-return assets;
◦improving overall corporate returns; and
◦ensuring cash flow sources and uses remain balanced.
In summary, as we progress through the remainder of 2017, 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 continuously evaluate commodity prices along with well productivity and efficiency gains as we optimize our activity levels in alignment with commodity price conditions.
To this end, our 2017 capital investment program is responsive to positive or negative commodity price conditions that may develop. Excluding acquisition and Noble Midstream Partners capital, we expect our 2017 capital spending program to be in the upper end of our investment range of $2.3 to $2.6 billion, or approximately 50% higher than 2016.  See Operating Outlook – 2017 Capital Investment Program, below.
Although the industry has begun to recover from the recent downturn, if commodity prices decline or operating costs begin to rise, we could experience material negative impacts on our revenues, profitability, cash flows, liquidity and proved reserves, and in response, we may consider reductions in our capital program or dividends, asset sales or cost structure. Our production and our stock price could decline as a result of these potential developments.
Recently Issued Accounting Standards
See Item 1. Financial Statements – Note 2. Basis of Presentation.

OPERATING OUTLOOK
2017 Production Our expected crude oil, natural gas and NGL production for the remainder of 2017 may be impacted by several factors including:
commodity prices which, if subject to a significant decline, could result in certain current production becoming uneconomic;
overall level and timing of capital expenditures which, as discussed below and dependent upon our drilling success, will impact near-term production volumes;
with increased drilling activity, US onshore cost inflation pressure may result in certain current production becoming less profitable or uneconomic;
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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 the divestiture of a portion of our working interest in the Tamar field, in accordance with the Israel Natural Gas Framework (Framework), which will lower our sales volumes;
timing of crude oil and condensate liftings impacting sales volumes in West Africa as well as the unitization of the Alba field;
additional purchases of producing properties or divestments of operating assets;
natural field decline in the US onshore, Gulf of Mexico and offshore Equatorial Guinea;
potential weather-related volume curtailments due to hurricanes in the Gulf of Mexico and Gulf Coast areas, or winter storms and flooding impacting US onshore operations;
availability or reliability of supplier services, including access to support equipment and facilities, occurrence of pipeline disruptions, and/or potential pipeline and processing facility capacity constraints which may cause delays, restrictions or interruptions in production and/or midstream processing;
timing and completion of midstream expansion projects by Noble Midstream Partners in areas that provide services to our assets;
malfunctions and/or mechanical failures at terminals or other US onshore delivery points;
impact of enhanced completion efforts for US onshore assets;
possible abandonment of low-margin US onshore wells;
shut-in of US producing properties if storage capacity becomes unavailable; and
drilling and/or completion permit delays due to future regulatory changes.

2017 Capital Investment Program  Given the current commodity price environment, we have designed a flexible capital investment program as part of our comprehensive effort to maintain strong liquidity and manage the Company's balance sheet. Excluding acquisition capital and Noble Midstream Partners, we expect our 2017 capital investment program to be in the upper end of our range of $2.3 to $2.6 billion, of which $1.9 billion has been incurred during the nine months ended September 30, 2017. More than 75% of the total capital investment program is allocated to US onshore development primarily in liquids-rich opportunities in the DJ Basin, Delaware Basin, and Eagle Ford Shale. The remaining 25% capital investment program will be predominately allocated to the Eastern Mediterranean, including initial development costs associated with the Leviathan project.
See Liquidity and Capital Resources – Financing Activities, below.
Potential for Future Dry Hole Cost, Lease Abandonment Expense or Property Impairments
Exploration Activities and Unproved Properties Our exploration program seeks to provide growth through long-term and/or large-scale exploration opportunities. We continue to seek exploration opportunities in various geographical areas, such as our entry into Newfoundland, Canada. In other areas of the world, we have capitalized a significant amount of exploratory drilling costs. In the event we conclude that an exploratory well did not encounter hydrocarbons or that a discovery or prospect is not economically or operationally viable, the associated capitalized exploratory well costs would be charged to expense. As of September 30, 2017, we have capitalized costs related to exploratory wells of $575 million. See Item 1. Financial Statements - Note 8. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs and Results of Operations – Oil and Gas Exploration Expense, below.
We may also impair and/or relinquish certain undeveloped leases prior to expiration, based upon geological evaluation or other factors. For example, during the first nine months of 2017, we impaired $49 million of assets related to certain Gulf of Mexico undeveloped leases. We have numerous leases for Gulf of Mexico prospects that have not yet been drilled. A significant portion of these leases are scheduled to expire over the years 2018 to 2020 and some leases may become impaired if production is not established, no action is taken to extend the terms of the leases, or the leases become uneconomic due to low commodity prices or other factors.
In addition, we have undeveloped leasehold costs, to which proved reserves had not been attributed, of $3.0 billion. Of this amount, $1.6 billion is attributable to Delaware Basin assets acquired in the Clayton Williams Energy Acquisition in 2017, and $1.1 billion and $149 million are attributable to Delaware Basin and Eagle Ford Shale assets, respectively, acquired in the Rosetta Resources Inc. acquisition in 2015. These 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 utilizing a future cash flows analysis.
The remaining undeveloped leasehold costs as of September 30, 2017 included $56 million related to Gulf of Mexico unproved properties and $53 million related to international unproved properties. These costs are evaluated as part of our periodic impairment review. 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
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factors, an impairment is indicated, we will record impairment expense related to the respective leases. As a result of our exploration activities, future exploration expense, including undeveloped leasehold impairment expense, could be significant. See Results of Operations - Oil and Gas Exploration Expense, below.
Proved Properties During the first nine months of 2017, no impairments were incurred related to proved properties. The cash flow model that we use to assess proved properties for impairment includes numerous assumptions, such as management’s estimates of future crude oil and natural gas production along with operating and development costs, market outlook on forward commodity prices, and interest rates. All inputs to the cash flow model must be evaluated at each date of estimate. However, a decrease in forward commodity prices, or widening of basis differentials, could result in an impairment.
In addition, well decommissioning programs, especially in deepwater or remote locations, are often complex and expensive. It may be difficult to estimate timing of actual abandonment activities, which are subject to regulatory approval and the availability of rigs and services. It may also be difficult to estimate costs of rigs and services in periods of fluctuating demand. In addition, we do not operate certain assets and we therefore work with respective operators to receive updated estimates of abandonment activities and costs. For example, in third quarter 2017, we recorded a revision of $42 million that decreased our estimated asset retirement obligation for the North Sea remediation project from $87 million to $45 million. The revision was a result of a more precise estimate received from the operator based upon their completion of activities performed to-date, as well as due to revised timing and scope of the remediation work. We will continue to monitor the status and costs of the project as the operator progresses with decommissioning activities and will adjust our estimate accordingly. The revision is included in other operating expense, net in the consolidated statement of operations. See Item 1. Financial Statements - Note 2. Basis of Presentationand Item 1. Financial Statements - Note 9. Asset Retirement Obligations.
Divestments We actively manage our asset portfolio to ensure our assets are well-positioned on the industry cost of supply curve and offer growth at financially attractive rates of return. Therefore, we may periodically divest certain assets, such as the Marcellus Shale upstream assets, to reposition our portfolio. Proceeds from asset sales are redeployed in our capital investment program, used to pay down debt, strengthen our balance sheet and/or support returns to shareholders through dividends or other mechanisms.
When properties meet the criteria for reclassification as assets held for sale, they are valued at the lower of net book value or anticipated sales proceeds less transaction related costs to sell. Impairment expense would be recorded for any excess of net book value over anticipated sales proceeds less transaction related costs to sell.
We strive to obtain the most advantageous price for any asset divestment; however, various factors, such as current and future commodity prices, reserves, production profiles, operating costs, capital investment requirements and potential future liabilities, as well as legal and regulatory requirements, can make it difficult to predict an asset's selling price and whether a transaction will result in a gain or loss. Inability to achieve a desired sales price, or underestimation of amounts of retained liabilities or indemnification obligations, can result in a possible loss on the sale, which could be material. See Item 1. Financial Statements - Note 4. Acquisitions and Divestitures.
We continue to review our portfolio to ensure alignment with the aforementioned strategic objectives. Further, the State of Israel requires that 7.5% of our working interest in the Tamar field offshore Israel be divested by December 2021, reducing our working interest from 32.5% to 25%. Additional potential divestments may be considered, even though no commitments have been made by our management and our Board of Directors.
Deferred Income Taxes We currently forecast that our US federal income tax net operating loss (NOL) carryforwards will be substantial at year end 2017. Included in the resulting deferred tax assets are acquired deferred tax assets associated with net operating losses of the Clayton Williams Energy Acquisition in 2017 and with the Rosetta Resources Inc. acquisition in 2015.
We have established a valuation allowance against the deferred tax asset associated with foreign and certain state NOLs, and we could be required to record an additional valuation allowance against deferred tax assets if market conditions change materially and, as a result, our future earnings are, or are projected to be, significantly less than we currently estimate. Any increase or decrease in the deferred tax asset valuation allowance would impact net income (loss) through offsetting changes in income tax expense (benefit), which could have a negative impact on our financial position and results of operations.
Regulatory Update
US Regulatory Developments In early 2017, President Trump issued two executive orders directing the US Environmental Protection Agency (EPA) and other executive agencies to review their rules and policies that unduly burden domestic energy development. Specifically, on February 28, 2017, President Trump signed an executive order directing the EPA and the US Army Corps of Engineers (Corps) to review the Clean Water Rule and to initiate rulemaking to rescind or revise it, as appropriate under the stated policies of protecting navigable waters from pollution while promoting economic growth, reducing uncertainty, and showing due regard for Congress and the states. On March 28, 2017, President Trump signed an executive
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order directing the EPA and other executive agencies to review all regulations, orders, guidance documents and policies and take actions to suspend, revise or rescind them, as appropriate and consistent with the law, to the extent that they unduly burden the development of domestic energy resources beyond the degree necessary to protect the public interest.
Pursuant to the first executive order, on June 27, 2017, the EPA and the Corps announced a proposed rule to rescind the Clean Water Rule and to re-codify the regulations that existed before the Clean Water Rule. Consistent with the second executive order, on June 5, 2017, the EPA published notice that it would reconsider certain requirements of a May 2016 rule, which set standards for emissions of methane and volatile organic compounds from new and modified oil and gas production sources, and that it would stay for 90 days those requirements pending reconsideration. On June 16, 2017, the EPA published a proposed rule to extend the stay for two years. On July 3, 2017, the D.C. Circuit Court of Appeals vacated the 90-day stay, but noted that this decision did not limit the EPA’s authority to reconsider its regulations and proceed with the June 16, 2017 proposed rulemaking. Also, on July 25, 2017, the Bureau of Land Management (BLM) published a proposed rule to rescind its March 2015 rules governing hydraulic fracturing on federal and Indian lands. The EPA and the BLM have also announced that they are reconsidering, or plan to reconsider, additional regulations that impact the oil and gas industry. However, it remains unclear how and to what extent this broad review could impact environmental regulations at the federal level.
Voluntary Withdrawal from International Climate Change Accord In December 2015, the United States signed the Paris Agreement on climate change and pledged to take efforts to reduce greenhouse gas (GHG) emissions and to conserve and enhance sinks and reservoirs of GHGs. The Paris Agreement entered into force in November 2016. However, on June 1, 2017, President Trump announced that the United States would withdraw from the Paris Agreement and begin negotiations to either re-enter or negotiate an entirely new agreement with more favorable terms for the United States. While President Trump expressed a clear intent to cease implementing the Paris Agreement, it is not clear how the Administration plans to accomplish this goal, whether a new agreement can be negotiated, or what terms would be included in such an agreement. Furthermore, in response to the announcement, many state and local leaders stated their intent to intensify efforts to uphold the commitments set forth in the international accord. It is not possible at this time to predict the timing or effect of international treaties or regulations on our operations or to predict with certainty the future costs that we may incur in order to comply with such treaties or regulations.
Impact of Dodd-Frank Act Section 1504In June 2016, the Securities and Exchange Commission (SEC) adopted resource extraction issuer payment disclosure rules under Section 1504 of the Dodd-Frank Act that would have required resource extraction companies, such as us, to publicly file with the SEC beginning in 2019 information about the type and total amount of payments made to a foreign government, including subnational governments (such as states and/or counties), or the U.S. federal government for each project related to the commercial development of crude oil, natural gas or minerals, and the type and total amount of payments made to each government (such rules, the Resource Extraction Issuer Payment Rules).
However, on February 14, 2017, President Trump signed a joint resolution passed by the United States Congress under the Congressional Review Act and eliminated the Resource Extraction Issuer Payment Rules. It should be noted that Section 1504 of the Dodd-Frank Act has not been repealed and that the SEC will now have until February 2018 to issue replacement rules to implement Section 1504 of the Dodd-Frank Act, and that under the Congressional Review Act a rule may not be issued in “substantially the same form” as the disapproved rule unless it is specifically authorized by a subsequent law. We cannot predict whether the SEC will issue replacement rules or, if it does so, whether such replacement rules will again be eliminated pursuant to the Congressional Review Act.
We will continue to monitor proposed and new regulations and legislation in all of our operating jurisdictions to assess the potential impact on our company. We continue to engage in extensive public education and outreach efforts with the goal of engaging and educating the general public and communities about the energy, economic and environmental benefits of safe and responsible crude oil and natural gas development.
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EXPLORATION AND PRODUCTION (E&P)
We continue to advance our major development projects, which we expect to deliver incremental production over the next several years. Updates on major development projects are as follows:
Sanctioned Ongoing Development Projects
A "sanctioned" development project is one for which a final investment decision has been reached. Third quarter 2017 activities included the following:
DJ Basin (US Onshore)   Our activities during third quarter 2017 were focused primarily in Wells Ranch and East Pony where we operated an average of two drilling rigs, drilled 32 wells and commenced production on 32 wells. We continue to optimize value in these oil-rich areas through our horizontal development program, which has led to an increasing mix of crude oil sales volumes and a new record crude oil mix of 54% in the DJ Basin during third quarter 2017, slightly higher than the prior quarter. While we expect our total horizontal production to continue to grow for the remainder of 2017, we anticipate certain of our legacy horizontal wells, as well as the majority of our vertical wells, to experience production declines as we enhance our focus on horizontal development in the oil-rich areas of the basin.
Delaware Basin (US Onshore) During third quarter 2017, we operated an average of five drilling rigs, drilled 17 horizontal wells and commenced production from 14 wells with the majority of our activity focused on long laterals and multi-well pads targeting multiple zones within the basin. We averaged 27 MBoe/d of sales volumes during third quarter 2017 with 85% our production mix attributable to crude oil and NGLs. Our integration and assumption of operations of the Clayton Williams Energy assets in second quarter 2017 continues to be successful as we apply learnings from our legacy Delaware Basin assets across the play to optimize our development plan, realize cost efficiencies, enhance completion designs and optimize well placement, thereby positively impacting costs and performance associated with these assets.
Eagle Ford Shale (US Onshore) Our activity in Webb and Dimmit Counties during third quarter 2017 was focused on well completion activities for previously drilled wells and we commenced production on 12 wells during the quarter. We continue to execute a strong development plan and surpass previous quarterly sales volumes records, including averaging sales volumes of 76 MBoe/d during third quarter 2017 despite multiple weather-related events causing the temporary suspension and shut-in of production across our Eagle Ford Shale assets. After inspection and safe return to operations, the impact of these weather-related events reduced our sales volumes by approximately 5 MBoe/d for third quarter 2017. For the remainder of 2017, we expect sales volumes to grow in this liquids-rich play.
Gulf of Mexico (US Offshore) Our offshore assets continue to provide high-margin oil production, and during third quarter 2017, average daily sales volumes were 25 MBoe/d. In July, the Gunflint field surpassed its one-year anniversary of first production. Also, during the third quarter, the Company exceeded more than one year of offshore performance without a recordable safety incident in either production operations or at the Company's operated facilities.
Tamar Natural Gas Project (Offshore Israel) Growth in power and industrial demand in Israel, resulting from the increased use of natural gas over coal to fuel power generation, enabled us to set a new all-time record for average daily gross sales volumes of 997 MMcfe/d during third quarter 2017 primarily from the Tamar field. We achieved this record despite planned maintenance procedures performed at the Tamar platform in late September 2017. During these procedures, we identified and completed additional modifications to the venting system, which resulted in a controlled full-field shut-down. All facility maintenance was completed safely and timely with no material impact to sales volumes. Our active response, coupled with operational uptimeofapproximately 97% for 2017, as well as the commencement of production from the Tamar 8 well earlier in the year, reflect our continued commitment to reliably and consistently deliver natural gas to Israeli customers.
In third quarter 2017, we completed additional reservoir modeling reflecting integration of Tamar 8 well results into our geologic modeling across the reservoir and, as a result, we added one Tcfe, gross, or 48 MMBoe, net, of proved developed natural gas reserves as of September 30, 2017. In accordance with the terms of the Framework, we continue to market a portion of our working interest in Tamar, which provides for reduction in our ownership interest to 25% by year-end 2021.
Leviathan Natural Gas Project (Offshore Israel) The first phase of development of the Leviathan field provides 1.2 Bcf/d of production capacity and consists of four wells, a subsea production system and a shallow-water processing platform, with a connection to an onshore valve station and the Israel Natural Gas Lines (INGL) pipeline network. We expect our share of development costs to total approximately $1.5 billion and to be funded from our share of cash flows from the Tamar asset and expected proceeds to be received from the sell-down of our ownership interest in Tamar as noted above. In addition, we have the ability to borrow under the Leviathan Term Loan Facility (defined below).
During third quarter 2017, we continued to progress the project within budget towards first gas by the end of 2019. We continued detailed design and engineering activities and fabrication of topsides, jacket and subsea equipment. We also commenced front-end engineering design (FEED) studies for the Hagit terminal, which will provide condensate storage and offloading facilities.
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As of September 30, 2017, the project remained on schedule at approximately 23% complete, with all critical path equipment and major contracts secured. We expect to continue drilling activities and commence well completion in 2018.
At June 30, 2017, we recorded initial proved reserves of 551 MMBoe associated with the first phase of development.
Alba Field Unitization (Offshore West Africa) In April 2017, we executed a unitization agreement on the Alba field with our partner and the Government of Equatorial Guinea. The agreement was between Alba Block and Block D interest owners. As a result of the unitization, our revenue interest going forward changed from 34% to 32%, and our non-operated working interest changed from 35% to 33%. As anticipated, our third quarter 2017 sales volumes from the Alba field were lower as a result of the unitization, and we expect the impact on our proved reserves and allocated future sales volumes to be de minimis. Total sales volumes across our West Africa assets averaged 63 MBoe/d for third quarter 2017, which was better than anticipated due to the conversion of two wells from natural gas injection to production at the Alba field during the third quarter.
Unsanctioned Development Projects
Tamar Expansion Project (Offshore Israel) We are engaged in the planning phase for the Tamar expansion project. The project would expand field deliverability from the current level of approximately 1.2 Bcf/d to up to 2.1 Bcf/d, a quantity that would allow for additional regional export. Expansion would include a third flow line component and additional producing wells. Timing of project sanction is dependent upon progress relating to domestic and regional marketing efforts of these resources.
Leviathan Expansion Project (Offshore Israel) The full field development of Leviathan will be accomplished through a phased approach. Current build-out and construction of the first phase of the Leviathan production assets allows for future cost-effective expansion. Through the expansion phase, field capacity would increase from currently planned capacity of 1.2 Bcf/d to up to 2.1 Bcf/d through the addition of multiple process trains, a third subsea tieback flow line and a potential export pipeline, allowing for regional exports. Similar to the Tamar expansion project, sanction of Leviathan expansion is dependent upon both domestic and regional marketing efforts of these resources.
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, would deliver natural gas to potential regional customers. In addition, we are focused on 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.
West Africa Natural Gas Monetization   We continue our efforts to monetize our significant natural gas discoveries offshore West Africa. A natural gas development team has been working with local governments to evaluate natural gas monetization concepts. After analyzing existing infrastructure, including the Alen platform and other facilities, we believe these assets can be efficiently modified and retrofitted to allow for future commercialization of natural gas. Leveraging existing assets for the development of natural gas minimizes future capital expenditures while providing advantageous financial returns.
Given the monetization plan, to develop the Alen resources through existing infrastructure, we changed the units-of-production depletion rate, based on risked resources, during first quarter 2017. As a result, we proportionally allocated the book value associated with the existing infrastructure assets to the natural gas resources that will be developed in the future, resulting in approximately $153 million of net asset value being reclassified as development costs not subject to depletion in first quarter 2017. See Operating Outlook – Potential for Future Dry Hole Cost, Lease Abandonment Expense or Property Impairments, above, and Results of Operations - Operating Costs and Expenses, below.
Exploration Program Update
While our 2017 exploration budget has been substantially reduced compared to prior years due to the current commodity price environment, we continue to seek and evaluate opportunities for future exploration. For example, our partner spud the Araku-1 exploration well offshore Suriname in early October 2017 and subsequently plugged and abandoned the well. We own a 20% non-operating working interest in the well and anticipate our portion of costs to be less than $10 million, which will be recorded as dry hole expense in fourth quarter 2017.
Through our drilling activities, we do not always encounter hydrocarbons. In addition, we may find hydrocarbons but subsequently reach a decision, through additional analysis or appraisal drilling, that a development project is not economically or operationally viable. In the event we conclude that one of our exploratory wells did not encounter hydrocarbons or that a discovery is not economically or operationally viable, the associated capitalized exploratory well costs will be recorded as dry hole expense.
Additionally, we may not be able to conduct exploration activities prior to lease expirations. As a result, in a future period, dry hole cost and/or leasehold abandonment expense could be significant. See Item 1. Financial Statements – Note 8. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs and Operating Outlook – Potential for Future Dry Hole Cost, Lease Abandonment Expense or Property Impairments, above.
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Results of Operations
Highlights for our E&P business were as follows:
Third Quarter 2017 Significant E&P Operating Highlights Included:
total average daily sales volumes of 355 MBoe/d;
record average daily sales volumes for US onshore crude oil of 93 MBbl/d;
average daily sales volumes of 285 MMcfe/d, net, in Israel, and an all-time record for quarter average daily gross sales volumes of 997 MMcfe/d, primarily from the Tamar field;
natural gas sales volumes exceeding 1 Bcf/d, gross, for 79 days in Israel, primarily from the Tamar field; and
an increase of one Tcfe, gross, or 48 MMBoe, net, of proved developed natural gas reserves for the Tamar field.
Third Quarter 2017 E&P Financial Results Included:
average realized crude oil price increase of 13% as compared to 2016;
average realized NGL price increase of 57% as compared to 2016;
pre-tax income of $41 million, as compared with pre-tax loss of $105 million for third quarter 2016; and
capital expenditures of $596 million, excluding acquisitions, as compared with $288 million for third quarter 2016.

Following is a summarized statement of operations for our E&P business:
 Three Months Ended September 30, Nine Months Ended September 30,
(millions)2017 2016 2017 2016
Oil, NGL and Gas Sales from Third Parties$907
 $882
 $2,918
 $2,411
Income from Equity Method Investees33
 19
 84
 31
Total Revenues940
 901
 3,002
 2,442
Production Expense316
 309
 953
 911
Exploration Expense64
 125
 136
 376
Depreciation, Depletion and Amortization502
 605
 1,502
 1,815
Loss on Marcellus Shale Upstream Divestiture (1)
4
 —
 2,326
 —
(Gain) Loss on Commodity Derivative Instruments22
 (55) (145) 53
Clayton Williams Energy Acquisition Expenses (2)
4
 —
 98
 —
Income (Loss) Before Income Taxes41
 (105) (1,944) (810)
(1)
See Note 4. Acquisitions and Divestitures.
(2)
See Note 3. Clayton Williams Energy Acquisition.




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Oil, NGL and Gas Sales
Average daily sales volumes and average realized sales prices were as follows:
 Sales Volumes Average Realized Sales Prices
 
Crude Oil & Condensate
(MBbl/d)
 
NGLs
(MBbl/d)
 
Natural
Gas
(MMcf/d)
 
Total
(MBoe/d) (1)
 
Crude Oil & Condensate
(Per Bbl)
 
NGLs
(Per Bbl)
 
Natural
Gas
(Per Mcf)
Three Months Ended September 30, 2017
United States114
 56
 449
 244
 $46.63
 $22.88
 $2.23
Israel—
 —
 283
 48
 —
 —
 5.36
Equatorial Guinea (2)
13
 —
 246
 54
 51.32
 —
 0.27
Total Consolidated Operations127
 56
 978
 346
 47.13
 22.88
 2.65
Equity Investees (3)
2
 7
 —
 9
 52.69
 37.49
 —
Total129
 63
 978
 355
 $47.27
 $24.56
 $2.65
Three Months Ended September 30, 2016
United States99
 55
 874
 299
 $41.23
 $14.70
 $2.38
Israel—
 —
 310
 52
 —
 —
 5.22
Equatorial Guinea (2)
22
 —
 261
 65
 43.73
 —
 0.27
Total Consolidated Operations121
 55
 1,445
 416
 41.67
 14.70
 2.61
Equity Investees (3)
2
 7
 —
 9
 45.72
 23.65
 —
Total123
 62
 1,445
 425
 $41.75
 $15.66
 $2.61
Nine Months Ended September 30, 2017
United States108
 56
 637
 270
 $47.07
 $21.66
 $3.06
Israel—
 —
 276
 46
 —
 —
 5.33
Equatorial Guinea (2)
18
 —
 240
 58
 51.29
 —
 0.27
Total Consolidated Operations126
 56
 1,153
 374
 47.66
 21.66
 3.02
Equity Investees (3)
1
 6
 —
 7
 51.72
 36.23
 —
Total127
 62
 1,153
 381
 $47.75
 $23.07
 $3.02
Nine Months Ended September 30, 2016
United States99
 56
 902
 304
 $37.23
 $13.38
 $2.00
Israel—
 —
 284
 48
 —
 —
 5.19
Equatorial Guinea (2)
25
 —
 230
 64
 40.74
 —
 0.27
Total Consolidated Operations124
 56
 1,416
 416
 37.94
 13.38
 2.36
Equity Investees (3)
2
 5
 —
 7
 43.95
 24.43
 —
Total126
 61
 1,416
 423
 $38.02
 $14.32
 $2.36
(1)
Natural gas is converted on the basis of six Mcf of gas per one barrel of crude oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given commodity price disparities, the price for a barrel of crude oil equivalent for 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.
(2)
Natural gas from the Alba field in Equatorial Guinea is under contract for $0.25 per MMBtu to a methanol plant, an LPG plant, an LNG plant and a power generation plant. The methanol and LPG plants are owned in part by affiliated entities accounted for under the equity method of accounting.
(3)
Volumes represent sales of condensate and LPG from the LPG plant in Equatorial Guinea. See Income from Equity Method Investees, below.
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An analysis of revenues from sales of crude oil, natural gas and NGLs is as follows:
 Sales Revenues
(millions)Crude Oil & Condensate NGLs 
Natural
Gas
 Total
Three Months Ended September 30, 2016$461
 $74
 $347
 $882
Changes due to       
Increase (Decrease) in Sales Volumes26
 1
 (82) (55)
Increase (Decrease) in Sales Prices66
 41
 (27) 80
Three Months Ended September 30, 2017$553
 $116
 $238
 $907
        
Nine Months Ended September 30, 2016$1,291
 $204
 $916
 $2,411
Changes due to       
Increase (Decrease) in Sales Volumes20
 1
 (135) (114)
Increase in Sales Prices326
 124
 171
 621
Nine Months Ended September 30, 2017$1,637
 $329
 $952
 $2,918
Crude Oil and Condensate SalesRevenues Revenues from crude oil and condensate sales increased for third quarter 2017 as compared with 2016 due to the following:
13% increase in average realized prices due to the partial rebalancing of global supply and demand factors; and
higher US onshore sales volumes of 19 MBbl/d, including 7 MBbl/d contributed by recently acquired Clayton Williams Energy assets;
partially offset by:
lower sales volumes of 12 MBbl/d offshore US and West Africa due to the timing of liftings (7 MBbl/d) and natural field decline (5 MBbl/d) in the Gulf of Mexico and at Aseng and Alen, offshore Equatorial Guinea.
Revenues from crude oil and condensate sales increased for the nine months ended September 30, 2017 as compared with 2016 due to the following:
26% increase in average realized prices due to the partial rebalancing of global supply and demand factors;
higher US onshore sales volumes of 10 MBbl/d primarily in the DJ Basin and Delaware Basin, including 4 MBbl/d contributed by recently acquired Clayton Williams Energy assets; and
higher sales volumes of 4 MBbl/d from the Gunflint development, Gulf of Mexico, which began producing in July 2016;
partially offset by:
lower sales volumes of 11 MBbl/d due to natural field decline in the Gulf of Mexico and at Aseng and Alen, offshore Equatorial Guinea.
NGL SalesRevenues Revenuesfrom NGL sales increased for third quarter 2017 as compared with 2016 due to the following:
57% increase in average realized prices due to the partial rebalancing of domestic supply and demand factors; and
higher sales volumes of 11 MBbl/d in the Delaware Basin and Eagle Ford Shale, primarily attributable to increased development and enhanced well design and completion techniques;
partially offset by:
lower sales volumes of 9 MBbl/d due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017.
Revenuesfrom NGL sales increased for the nine months ended September 30, 2017 as compared with 2016 due to the following:
61% increase in average realized prices due to the partial rebalancing of domestic supply and demand factors; and
higher sales volumes of 4 MBbl/d in the Delaware Basin and Eagle Ford Shale primarily attributable to increased development and enhanced well design and completion techniques;
partially offset by:
lower sales volumes 3 MBbl/d due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017.
Natural Gas SalesRevenuesRevenues from natural gas sales decreased for third quarter 2017 as compared with 2016 due to the following:
a reduction of $31 million related to previously recorded processing fees included within the US reportable segment;
a 498 MMcf/d reduction in sales volumes due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017;
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lower sales volumes of 27 MMcf/d in the DJ Basin primarily attributable to increased focus on the oil-rich well locations of the basin;
lower sales volumes of 30 MMcf/d as a result of the sale of a 3.5% working interest in the Tamar field, offshore Israel, in December 2016; and
lower sales volumes of 15 MMcf/d at the Alba field, offshore Equatorial Guinea, due to natural field decline;
partially offset by:
higher sales volumes of 85 MMcf/d in the Eagle Ford Shale primarily attributable to commodity mix from recently completed wells; and
higher sales volumes of 14 MMcf/d in the Delaware Basin primarily attributable to increased development and enhanced well design and completion techniques.
Revenuesfrom natural gas sales increased for the nine months ended September 30, 2017 as compared with 2016 due to the following:
28% increase in average realized natural gas prices due to the partial rebalancing of domestic supply and demand factors;
higher domestic sales volumes of 41 MMcf/d in the Delaware Basin and Eagle Ford Shale combined, primarily attributable to increased development and enhanced completion techniques;
higher sales volumes of 16 MMcf/d offshore Israel, primarily attributable to higher production at the Tamar field; and
higher sales volumes of 10 MMcf/d at the Alba field, offshore Equatorial Guinea, following the startup of the B3 compression platform in July 2016;
partially offset by:
a reduction of $31 million related to previously recorded processing fees included within the US reportable segment;
a 267 MMcf/d reduction in sales volumes due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017;
lower sales volumes of 37 MMcf/d in the DJ Basin primarily attributable to increased focus on the oil-rich well locations of the basin; and
lower sales volumes of 29 MMcf/d as a result of the sale of a 3.5% working interest in the Tamar field, offshore Israel, in December 2016, which is partially offset by higher gross field production.
Income from Equity Method Investees and Other 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 the first nine months of 2017 as compared with 2016. The increase includes a $29 million increase from Atlantic Methanol Production Company, LLC (AMPCO), our methanol investee, and a $24 million increase from Alba Plant, our LPG investee, both primarily driven by rising commodity prices.

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Production Expense Components of production expense from our upstream operations were as follows:
(millions, except unit rate)
Total per BOE (1) (2)
 Total 
United
States (2)
 Eastern
Mediter- ranean		 West Africa
Three Months Ended September 30, 2017         
Lease Operating Expense (3)
$4.78
 $152
 $118
 $9
 $25
Production and Ad Valorem Taxes1.10
 35
 35
 —
 —
Gathering, Transportation and Processing (4)
4.06
 129
 129
 —
 —
Total Production Expense$9.94
 $316
 $282
 $9
 $25
Total Production Expense per BOE  $9.94
 $12.58
 $2.06
 $5.00
Three Months Ended September 30, 2016 
  
  
  
  
Lease Operating Expense (3)
$3.55
 $136
 $106
 $8
 $22
Production and Ad Valorem Taxes0.76
 29
 29
 —
 —
Gathering, Transportation and Processing (4)
3.76
 144
 144
 —
 —
Total Production Expense$8.07
 $309
 $279
 $8
 $22
Total Production Expense per BOE  $8.07
 $10.16
 $1.67
 $3.67
Nine Months Ended September 30, 2017         
Lease Operating Expense (3)
$4.12
 $420
 $332
 $23
 $65
Production and Ad Valorem Taxes1.15
 117
 117
 —
 —
Gathering, Transportation and Processing (4)
4.08
 416
 416
 —
 —
Total Production Expense$9.35
 $953
 $865
 $23
 $65
Total Production Expense per BOE  $9.35
 $11.76
 $1.82
 $4.12
Nine Months Ended September 30, 2016 
  
  
  
  
Lease Operating Expense (3)
$3.72
 $424
 $324
 $25
 $75
Production and Ad Valorem Taxes0.61
 70
 70
 —
 —
Gathering, Transportation and Processing (4)
3.66
 417
 417
 —
 —
Total Production Expense$7.99
 $911
 $811
 $25
 $75
Total Production Expense per BOE  $7.99
 $9.72
 $1.91
 $4.30
(1)
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
(2)
United States upstream 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)
Certain of our gathering and processing expenses were historically presented as components of other operating expense, net, in our consolidated statements of operations. Beginning in 2017, we have changed our presentation to reflect these as components of production expense. These costs are now included within gathering, transportation and processing expense. For the three and nine months ended September 30, 2017, these costs totaled $12 million and $17 million, respectively. For the three and nine months ended September 30, 2016, these costs totaled $8 million and $19 million, respectively, and have been reclassified from marketing expense to conform to the current presentation.
For third quarter 2017, total production expense increased as compared with 2016 due to the following:
an increase in production and ad valorem taxes in the United States due to higher commodity prices;
an increase in total production expense due to higher sales volumes in the Delaware Basin and the Eagle Ford Shale; and
an increase in gathering, transportation and processing expense in the DJ Basin due to the shifting of crude oil volumes onto a new export pipeline and contractual increases of pipeline fees;
partially offset by:
a decrease in lease operating expense due to natural field decline in the Gulf of Mexico; and
a decrease in total production expense due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017.

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For the first nine months of 2017, total production expense increased slightly as compared with 2016 due to the following:
an increase in production and ad valorem taxes due to higher commodity prices;
an increase in total production expense due to higher production in the Delaware Basin and Eagle Ford Shale; and
an increase in production and ad valorem taxes due to a $28 million US onshore severance tax refund recorded in first quarter 2016 versus a $7 million US onshore severance tax charge recorded in first quarter 2017;
partially offset by:
a decrease in total production expense due to natural field decline in the Gulf of Mexico;
a decrease in lease operating expense due to a 3.5% lower working interest in the Tamar field, offshore Israel, following the partial divestiture in December 2016;
a decrease in lease operating expense due to various cost reduction initiatives offshore West Africa; and
a decrease in total production expense due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017.
Production expense on a per BOE basis increased for the three and nine months ended September 30, 2017 compared to 2016 primarily due to the decrease in total sales volumes driven by the divestiture of the Marcellus Shale upstream assets in second quarter 2017, coupled with an increase in certain production expenses noted above. Specifically, the divestiture of the Marcellus Shale upstream 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 increasing our average production expense per BOE. Also, higher commodity prices lead to higher production and ad valorem taxes per BOE.
Exploration Expense Our 2017 exploration budget has been substantially reduced compared to prior years due to the current commodity price environment. Exploration expense for the first nine months totaled $136 million, including $51 million of undeveloped leasehold impairment expense, of which $49 million was attributable to our Gulf of Mexico leases. Other primary costs included staff expenses of $40 million and seismic, geological and geophysical expenses of $20 million.
Exploration expense for the first nine months of 2016 totaled $376 million, including $81 million of undeveloped leasehold impairment expense, of which $56 million was attributable to our Gulf of Mexico leases and $25 million attributable to the Falkland Islands. Dry hole cost totaled $105 million and primarily related to the Silvergate exploratory well, Gulf of Mexico, and the Dolphin 1 natural gas discovery, offshore Israel. Other primary costs included staff expenses of $53 million and seismic, geological and geophysical expenses of $47 million.
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Depreciation, Depletion and Amortization   DD&A expense for our upstream operations was as follows:
(millions, except unit rate)Total United
States		 Eastern
Mediter- ranean		 
West
Africa
 Other Int'l
Three Months Ended September 30, 2017         
DD&A Expense$502
 $442
 $18
 $41
 $1
Unit Rate per BOE (1)
$15.79
 $19.72
 $4.11
 $8.19
 $—
Three Months Ended September 30, 2016         
DD&A Expense$605
 $536
 $22
 $46
 $1
Unit Rate per BOE (1)
$15.81
 $19.51
 $4.58
 $7.67
 $—
Nine Months Ended September 30, 2017         
DD&A Expense$1,502
 $1,326
 $58
 $114
 $4
Unit Rate per BOE (1)
$14.73
 $18.02
 $4.58
 $7.23
 $—
Nine Months Ended September 30, 2016         
DD&A Expense$1,815
 $1,599
 $62
 $150
 $4
Unit Rate per BOE (1)
$15.93
 $19.17
 $4.74
 $8.60
 $—
(1)
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.

Total DD&A expense for third quarter and the first nine months of 2017 decreased as compared with 2016 due to the following:
lower sales volumes in the DJ Basin and the impact of certain property divestitures in second quarter 2016;
Marcellus Shale upstream divestiture in second quarter 2017, which reduced DD&A expense by $101 million in third quarter and $201 million during the first nine months of 2017;
sale of a 3.5% working interest in the Tamar field, offshore Israel, in December 2016, which reduced DD&A expense by approximately $2 million and $6 million, in third quarter and first nine months of 2017, respectively;
a reduction in depletable costs of $153 million in the second quarter 2017 due to the reallocation of common asset costs from Alen, offshore Equatorial Guinea, to the West Africa natural gas monetization development project, which reduced DD&A expense by $26 million in the first nine months of 2017; and
lower sales volumes in Gulf of Mexico due to natural field decline and reduction in the depletable costs due to downward revisions in estimates of asset retirement costs;
partially offset by:
higher sales volumes of 17 MBoe/d in the Delaware Basin during third quarter 2017, including 8 MBoe/d attributable to increased development and enhanced well design and completion techniques and 9 MBoe/d contributed by recently acquired Clayton Williams Energy assets;
an increase in sales volumes from the Gunflint development, Gulf of Mexico, which commenced production in July 2016; and
higher sales volumes from the Tamar field, offshore Israel, due to higher domestic demand.
The unit rate per BOE for third quarter 2017, as compared with 2016, was relatively flat. Overall, the unit rate decreased primarily due to the reduction in Alen net book value in second quarter 2017 and certain DJ Basin property divestitures since third quarter 2016. These decreases were offset by the commencement of sales volumes from new crude oil-focused wells in US onshore, as well as, the divestiture of natural gas-focused sales volumes from Marcellus Shale upstream assets.
The decrease in the unit rate per BOE for the first nine months of 2017, as compared with 2016, was primarily due to the divestiture of certain assets in the DJ Basin, an increase in natural gas sales volumes from the Tamar field, and the reduction in Alen net book value, partially offset by the divestiture of natural gas-focused sales volumes from Marcellus Shale upstream assets and the commencement of sales volumes from new crude oil-focused wells in US onshore.
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 third quarter and first nine months of 2017 as compared with 2016.
Loss (Gain) on Commodity Derivative Instruments  (Gain) loss 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 the first nine months of 2017, gain on commodity derivative instruments included:
net cash settlement receipts of $18 million; and
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non-cash increases in the fair value of our derivative instruments of $127 million primarily driven by changes in the forward commodity price curves for both crude oil and natural gas.
For the first nine months of 2016, loss on commodity derivative instruments included:
net cash settlement receipts of $454 million; and
non-cash decreases in the fair value of our derivative instruments of $507 million primarily driven by changes in the forward commodity price curves for both crude oil and natural gas.
See Item 1. Financial Statements – Note 5. Derivative Instruments and Hedging Activities andNote 7. Fair Value Measurements and Disclosures.
MIDSTREAM
The Midstream segment owns, operates, develops and acquires domestic midstream infrastructure assets with current focus areas being the DJ and Delaware Basins.
Noble Midstream Segment – Major Midstream Project Updates
Third-Party Sales During third quarter 2017, we began providing crude oil and produced water gathering services to an unaffiliated third party in the Greeley Crescent integrated development plan (IDP) area of the DJ Basin, in addition to the fresh water delivery services we began providing in second quarter 2017.
Major Midstream Construction Projects During third quarter 2017, we progressed the construction and development of multiple major projects including:
completion of construction of our crude oil and produced water gathering systems servicing the Greeley Crescent IDP area of the DJ Basin;
completion of the connection from the central gathering facility (CGF) in the Delaware Basin to the Advantage pipeline allowing crude oil to flow from the completed facility to the Advantage pipeline in late August 2017;
continued construction activities on the expansion of a freshwater system servicing the Mustang IDP area of the DJ Basin and commencement of construction of the backbone gathering infrastructure build-out, which is expected to be completed in early 2018; and
commencement of the construction of a second CGF in the Delaware Basin which is expected to be online by the end of 2017.
Results of Operations
Highlights for our Midstream segment were as follows:
Third Quarter 2017 Significant Midstream Operating Highlights Included:
completion of our first CGF and crude oil, natural gas and produced water gathering infrastructure located in the Delaware Basin of Texas along with tie-in to the Advantage pipeline; and
commencement of crude oil, natural gas and produced water gathering services to a third party in the DJ Basin.
Third Quarter 2017 Midstream Financial Results Included:
pre-tax income of $58 million, as compared with pre-tax income of $47 million for third quarter 2016; and
capital expenditures, excluding acquisitions, of $96 million compared with $9 million capital expenditures for third quarter 2016.
Following is a summarized statement of operations for our Midstream segment:
 Three Months Ended September 30, Nine Months Ended September 30,
(millions)2017 2016 2017 2016
Midstream Services Revenues - Third Party$7
 $—
 $12
 $—
Income from Equity Method Investees13
 9
 41
 39
Intersegment Revenues72
 57
 198
 143
Total Revenues92
 66
 251
 182
Operating Costs and Expenses24
 14
 66
 42
Depreciation and Amortization10
 5
 20
 14
Income Before Income Taxes58
 47
 165
 126
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The amount of revenue generated by the midstream business depends primarily on the volumes of crude oil, natural gas and water for which services are provided to the E&P business and third party customers. These volumes are affected primarily by the level of drilling and completion activity in the areas of upstream operations and by changes in the supply of, and demand for, crude oil, natural gas and NGLs in the markets served directly or indirectly by our midstream assets.
Total revenues for the three and nine months ended September 30, 2017 increased from 2016 due to the following:
an increase of $15 million and $55 million, respectively, driven by drilling and completion activity in the Wells Ranch and East Pony IDP areas of the DJ Basin coupled with expansion and gathering system growth which resulted in increased services related to fresh water delivery, water logistics, and additional crude oil and natural gas gathering services;
an increase of $7 million and $12 million, respectively, due to the commencement of fresh water deliveries and crude oil, natural gas and produced water gathering services provided to a third party in the DJ Basin; and
an increase of $4 million and $2 million, respectively, in income from Cone Gathering LLC and Cone Midstream Partners LP as well as income received from Advantage Pipeline LLC.
Total operating expenses for the three and nine months ended September 30, 2017 increased from 2016 by $12 million and $24 million, respectively, due to the following:
an increase due to higher drilling and completion activity in the Wells Ranch and East Pony IDP areas of the DJ Basin which resulted in increased fresh water volumes required and additional water logistic services for produced water; and
an increase associated with the commencement of crude oil and natural gas gathering services driven by expansion and gathering system growth.
Depreciation and amortization expense for the three and nine months ended September 30, 2017 increased from 2016 by $5 million and $6 million, respectively, due to the assets placed in service in the respective periods, specifically assets associated with the construction of the Greeley Crescent facilities and expansion of the Delaware Basin gathering systems.
Results of Operations – Corporate and Other
General and Administrative Expense   General and administrative expense (G&A) was as follows:
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
G&A Expense (millions)$102
 $95
 $304
 $293
Unit Rate per BOE (1)
$3.21
 $2.48
 $2.98
 $2.57
(1)
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
G&A expense for the third quarter and first nine months of 2017 increased as compared with 2016 primarily due to increased employee costs driven by acquisition activities. The increase in the unit rate per BOE for the first nine months of 2017 as compared with 2016 was due primarily to the decrease in total sales volumes driven by the divestiture of the Marcellus Shale upstream assets.
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 the third quarter and first nine months of 2017 as compared with 2016.
Loss (Gain) on Extinguishment of Debt See Item 1. Financial Statements – Note 6. Debt for discussion of our extinguishment of debt activities for the third quarter and first nine months of 2017 as compared with 2016.
Interest Expense and Capitalized Interest  Interest expense and capitalized interest were as follows:
 Three Months Ended September 30, Nine Months Ended September 30,
(millions, except unit rate)2017 2016 2017 2016
Interest Expense, Gross$100
 $103
 $306
 $312
Capitalized Interest(12) (17) (35) (70)
Interest Expense, Net$88
 $86
 $271
 $242
Unit Rate per BOE (1)
$2.77
 $2.25
 $2.66
 $2.12
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(1)
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
Interest expense, gross, for the third quarter and first nine months of 2017 remained relatively flat as compared with 2016. While we engaged in debt refinancing activities in third quarter 2017, interest expense remained consistent for the period and in the future as a result of these activities, we expect future cash interest expense will be lower by approximately $35 million on an annual basis. See Item 1. Financial Statements - Note 6. Debt.
The decrease in capitalized interest for the third quarter and first nine months of 2017 as compared with 2016 is primarily due to lower work in progress amounts related to major long-term projects including Gunflint, Gulf of Mexico, and the Alba B3 compression project, offshore Equatorial Guinea, which were both completed in July 2016. We also impaired certain of our discoveries offshore Equatorial Guinea after an additional review of 3D seismic data was completed in fourth quarter 2016, resulting in a lower capitalized exploratory well cost balance. See Item 1. Financial Statements - Note 8. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
The increase in the unit rate of interest expense, net, per BOE was due to the changes noted above, combined with the decrease in total sales volumes.
Income Taxes See Item 1. Financial Statements – Note 10. Income Taxes for a discussion of the change in our effective tax rate for the third quarter and first nine months of 2017 as compared with 2016.
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, including the current commodity price environment. 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 periodically capitalize on financially attractive merger and acquisition opportunities, such as the recent Clayton Williams Energy Acquisition. We endeavor to maintain a strong balance sheet and 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, available borrowing capacity under our Revolving Credit Facility and proceeds from property divestitures. 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 maturities. We also evaluate potential strategic farm-out arrangements of our working interests for reimbursement of our capital spending.
In 2017, we engaged in significant development and portfolio activities which has required an intensive capital program. We strive to fund our capital program through organic cash flows and when needed, utilize borrowings under our Revolving Credit Facility. In third quarter 2017, we borrowed under our Revolving Credit Facility and had outstanding $275 million as of September 30, 2017. Funds were utilized for general corporate purposes and for funding of our capital development program.
We continue to undertake proactive and strategic actions to maintain liquidity and a strong balance sheet. During third quarter 2017, for example, we took steps in managing our long-term debt maturities and liquidity. We issued $600 million of 3.85% senior unsecured notes that will mature on January 15, 2028 and $500 million of 4.95% senior unsecured notes that will mature on August 15, 2047. We used the proceeds to repurchase $1 billion of our 8.25% senior unsecured notes which were due March 1, 2019. Through these transactions we effectively enhanced our financial flexibility and lowered our future cash interest expense by approximately $35 million on an annual basis. As a result, we ended third quarter 2017 with over $4 billion in liquidity, including $3.7 billion of availability under our Revolving Credit Facility.
During second quarter 2017, Noble Midstream Partners purchased additional midstream assets from Noble Energy for $270 million and expanded its business through entry into a joint venture. Funding for these transactions included a $138 million private placement of common units and $90 million of net borrowings under the Noble Midstream Services Revolving Credit Facility. As of September 30, 2017, $200 million was outstanding under the Noble Midstream Services Revolving Credit Facility. Funds were used to partially fund the second quarter 2017 acquisitions and to finance the midstream capital program. See Note 4. Acquisitions and Divestitures.
Also, during the first nine months of 2017, we received $300 million in payments from foreign operations on an outstanding note payable, leaving a balance of approximately $430 million that can be repaid without additional US tax impact.
As of September 30, 2017, our outstanding debt (excluding capital lease obligations) totaled $7.3 billion. While we have no near-term debt maturities, we may periodically seek to access the capital markets to refinance a portion of our outstanding indebtedness.
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We may from time to time seek to retire or purchase our outstanding senior notes through cash purchases in 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 material.
Available Liquidity
Information regarding cash and debt balances is shown in the table below:
 September 30, December 31,
(millions, except percentages)2017 2016
Total Cash (1)
$564
 $1,209
Amount Available to be Borrowed Under Revolving Credit Facility (2)
3,725
 4,000
Total Liquidity$4,289
 $5,209
Total Debt (3)
$7,604
 $7,114
Noble Energy Share of Equity9,466
 9,288
Ratio of Debt-to-Book Capital (4)
45% 43%
(1)
As of September 30, 2017, total cash included cash and cash equivalents of $11 million related to Noble Midstream Partners. As of December 31, 2016, total cash included cash and cash equivalents of $57 million related to Noble Midstream Partners and restricted cash of $30 million related to a Delaware Basin property acquisition that closed in January 2017.
(2)
Excludes $150 million and $625 million available to be borrowed under the Noble Midstream Services Revolving Credit Facility and Leviathan Term Loan Facility, respectively, which are not available to Noble Energy for general corporate purposes. See discussion below.
(3)
Total debt includes capital lease obligations and excludes unamortized debt discount/premium. See Item 1. Financial Statements – Note 6. Debt.
(4)
We define our ratio of debt-to-book capital as total debt (which includes long-term debt excluding unamortized discount, the current portion of long-term debt, and short-term borrowings) divided by the sum of total debt plus Noble Energy's share of equity.
Cash and Cash EquivalentsWe had approximately $564 million in cash and cash equivalents at September 30, 2017, primarily denominated in US dollars and invested in money market funds and short-term deposits with major financial institutions. Approximately $425 million of this cash is attributable to our foreign subsidiaries. We have recorded a related deferred tax liability on undistributed foreign earnings of $324 million for the future additional US tax liability for the US and foreign tax rate differences, net of estimated foreign tax credits. Our cash and cash equivalents at September 30, 2017 included $11 million relating to Noble Midstream Partners.
Revolving Credit Facility Noble Energy's Revolving Credit Facility matures on August 27, 2020, and the commitment is $4 billion through the maturity date. On April 24, 2017, we borrowed $1.3 billion to fund activities in connection with the Clayton Williams Energy Acquisition, including the cash portion of the acquisition consideration, redeem outstanding debt, pay associated make-whole premiums and pay related fees and expenses. We repaid all outstanding borrowings during second quarter 2017 with proceeds received from the Marcellus Shale upstream divestiture, cash on hand, and cash proceeds received from the Noble Midstream Partners asset contribution. In third quarter 2017, we borrowed and had outstanding $275 million as of September 30, 2017 under our Revolving Credit Facility which was utilized for general corporate purposes and for funding of our capital development program. See Item 1. Financial Statements - Note 3. Clayton Williams Energy Acquisition and Note 4. Acquisitions and Divestitures.
Noble Midstream Services Revolving Credit Facility Noble Midstream Services Revolving Credit Facility matures on September 20, 2021, and the commitment is $350 million through the maturity date. As of September 30, 2017, $200 million was outstanding under this facility which was used to partially fund second quarter 2017 acquisitions and to finance the midstream capital program. See Note 4. Acquisitions and Divestitures. During October 2017, an additional $25 million was borrowed under this facility to fund midstream construction activities.
Leviathan Term Loan Facility On February 24, 2017, we entered into a facility agreement (Leviathan Term Loan Facility) providing for a limited recourse secured term loan facility with an aggregate principal borrowing amount of up to $1.0 billion, of which $625 million 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 online by the end of 2019, we may borrow amounts under this facility in the near-term. As of September 30, 2017, no amounts were drawn under this facility.
Senior Notes On August 15, 2017, we issued $600 million of 3.85% senior unsecured notes that will mature on January 15, 2028 and $500 million of 4.95% senior unsecured notes that will mature on August 15, 2047. Interest on the 3.85% senior notes and 4.95% senior notes is payable semi-annually beginning January 15, 2018, and February 15, 2018, respectively. We may redeem some or all of the senior notes at any time at the applicable redemption price, plus accrued interest, if any. The senior
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notes were issued at a discount of $4 million and debt issuance costs incurred totaled $11 million. These amounts are reflected as a reduction of long-term debt and are amortized over the life of the facility. Proceeds of $1.1 billion from the issuance of senior notes were used solely to fund the tender offer and the redemption of $1 billion of our 8.25% senior notes due March 1, 2019.
Interest Rate Risk Certain of our borrowings subject us to interest rate risk. See Item 1. Financial Statements – Note 6. Debt andItem 3. Quantitative and Qualitative Disclosures About Market Risk.
Contractual Obligations
The following table summarizes certain contractual obligations as of September 30, 2017 that are reflected in the consolidated balance sheets and/or disclosed in the accompanying notes. Unless otherwise noted, the table excludes amounts related to Noble Midstream Partners, and all amounts shown are net to our interest. For additional information, see the Notes to the Consolidated Financial Statements under Item 1. Financial Statements of this Form 10-Q.
 
Obligation
Note
Reference
Total October - December 2017 2018 and 2019 2020 and 2021 2022 and beyond
(millions)          
Long-Term Debt (1)
Note 6
$6,839
 $—
 $550
 $1,379
 $4,910
Interest Payments (2)
Note 6
5,884
 83
 648
 619
 4,534
Capital Lease Obligations (3)
Note 6
355
 20
 119
 71
 145
Drilling and Equipment Obligations (4)
Note 12
510
 105
 405
 —
 —
Purchase Obligations (5)
Note 12
268
 31
 168
 33
 36
Transportation and Gathering (6)
Note 12
2,537
 53 523
 462
 1,499
Operating Lease Obligations (7)
Note 12
340
 12
 75
 64
 189
Other Liabilities (8)
  
  
  
  
  
Asset Retirement Obligations (9)
Note 9
944
 30
 231
 63
 620
Total Contractual Obligations $17,677
 $334
 $2,719
 $2,691
 $11,933
(1)
Long-term debt excludes balances outstanding under the revolving credit facilities and capital lease obligations.
(2)
Interest payments are based on the total debt balance, excluding balances outstanding under the revolving credit facilities, scheduled maturities and interest rates in effect at September 30, 2017.
(3)
Annual capital lease payments, net to our interest, exclude regular maintenance and operational costs.
(4)
Drilling and equipment obligations represent our working interest share of contractual agreements with third-party service providers to procure drilling rigs and other related equipment for exploratory and development drilling activities.
(5)
Purchase obligations represent our working interest share of contractual agreements to purchase goods or services that are enforceable, are legally binding and specify all significant terms, including fixed and minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction.
(6)
Transportation and gathering obligations represent minimum charges for firm transportation and gathering agreements associated with production. 
(7)
Operating lease obligations represent non-cancelable leases for office buildings and facilities and oil and gas operations equipment used in our daily operations. Amounts have not been discounted.
(8)
The table excludes deferred compensation liabilities of $216 million as specific payment dates are unknown.
(9)
Asset retirement obligations are discounted.
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. We have executed major equipment and installation contracts in support of our development activities. As of September 30, 2017, we had entered into approximately $534 million, net, of contracts to support development 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 are held through continuous development obligations. As such, we plan our activities and budget accordingly to ensure that we meet any such obligations that are in line with our strategic plans. Therefore, we are contractually obligated to fund a level of development activity in these areas.
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Marcellus Shale Firm Transportation Agreements In connection with the Marcellus Shale upstream divestiture, we reduced our firm transportation financial commitments through transfer of several contracts to the acquirer.
We retained certain other firm transportation contracts representing a total financial commitment of approximately $1.6 billion, undiscounted, primarily with remaining contract terms of 15 years.
One of the retained contracts, related to Texas Eastern pipeline, will be fully utilized through an agreement with the acquirer, whereby the acquirer will deliver quantities of natural gas to us and receive a netback sales price that reflects the value received by us at the sales point, less our effective fixed transportation fees and other expenses, plus a margin. This contract represents an undiscounted financial commitment of approximately $119 million as of September 30, 2017, before offset by the netback agreement, thus reducing the remaining overall commitment noted above.
Two of the retained contracts relate to the Leach & Rayne Xpress projects, which are currently under construction and targeted to be placed in service mid-to-late fourth quarter 2017. These contracts represent an undiscounted financial commitment of approximately $627 million. We are in negotiations with third parties for the permanent assignment or release of a portion of our capacity under these contracts which would reduce our undiscounted financial commitment. At this time, we are unable to predict with certainty the outcome of our commercialization activities, our ability to utilize retained capacity and the timing of when we may recognize a non-cash exit cost in line with accounting for exit costs associated with these two pipeline projects.
Two additional retained contracts relate to the NEXUS and WB Xpress projects. The NEXUS project received approval from the FERC in third quarter 2017, construction commenced in late 2017 and the project is scheduled to be placed in service fourth quarter 2018. The WB Xpress project, while also scheduled to be placed in service fourth quarter 2018, has not yet been approved by the FERC, and construction has not begun. These contracts represent an undiscounted financial commitment of approximately $869 million.
We are currently engaged in actions to commercialize and address these remaining commitments, which provide for the transportation of approximately 500,000 MMBtu/day 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. In addition, we have a “call” or right to purchase natural gas, priced at a regional index, from the acquirer of the Marcellus Shale upstream assets. This call extends through July 1, 2022 and may be exercised on quantities of the acquirer's production between 431,100 MMBtu/d and 832,645 MMBtu/d.
We expect these actions, some of which may require pipeline and/or FERC approval, to ultimately reduce the 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 a liability, at fair value, for the net amount of the estimated remaining financial commitment and include the related expense in operating expense in our consolidated statements of operations.
In accordance with US GAAP, we recognize the fair value of a liability for an exit cost in the period in which a liability is incurred. As a result, in second quarter 2017, we accrued non-cash exit costs of $41 million, discounted, relating to our transportation contract with the Gateway pipeline project. Gateway is currently in service; however, we no longer have production to satisfy this commitment and do not plan to utilize this capacity in the future. As such, we recorded a charge to expense which is included in loss on Marcellus Shale upstream divestiture in our consolidated statements of operations.
See Item 1. Financial Statements – Note 12. Commitments and Contingencies.
Certain of these contracts require us to make payments for any shortfalls in delivering or transporting minimum volumes under the commitments. As properties are undergoing development activities, we may experience temporary shortfalls until production volumes increase to meet or exceed the minimum volume commitments.
For the first nine months of both 2017 and 2016, we incurred expense of $39 million, related to volume deficiencies and/or unutilized commitments primarily in our US onshore operations. These amounts are recorded as marketing expense in our consolidated statements of operations. We expect to continue to incur expense related to deficiency and/or unutilized commitments in the near-term. Should commodity prices decline or if we are unable to continue to develop our properties as planned, or certain wells become uneconomic and are shut-in, we could incur additional shortfalls in delivering or transporting the minimum volumes and we could be required to make payments in the event that these commitments are not otherwise offset. We continually seek to optimize under-utilized assets through capacity release and third-party arrangements, as well as, for example, through the shifting of transportation of production from rail cars to pipelines when we receive a higher netback price. We may continue to experience these shortfalls both in the near and long-term.
Credit Rating EventsWe 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
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commitments and certain abandonment obligations. A requirement to post collateral could have a negative impact on our liquidity.
Cash Flows
Summary cash flow information is as follows:
 Nine Months Ended September 30,
 (millions)2017 2016
Total Cash Provided By (Used in)   
Operating Activities$1,418
 $1,054
Investing Activities(1,810) (386)
Financing Activities(224) 123
(Decrease) Increase in Cash and Cash Equivalents$(616) $791
Operating ActivitiesNet cash provided by operating activities for the first nine months of 2017 increased as compared with 2016. The change in cash flows from operating activities was primarily the result of higher average realized commodity prices partially offset by lower sales volumes. Working capital changes resulted in a $27 million operating cash flow decrease for the first nine months of 2017, as compared with a $171 million operating cash flow decrease for the first nine months of 2016. The changes in working capital were primarily due to an increase in our current liabilities, including accrued liabilities and trade payables for drilling and development costs and midstream capital expenditures. The increase in current liabilities was partially offset by the increase in accounts receivable resulting from higher revenues and higher joint interest billing receivables primarily due to billings associated with Leviathan development project costs.
Investing Activities   Our investing activities include capital spending on a cash basis for oil and gas properties and investments in unconsolidated subsidiaries accounted for by the equity method. These investing activities may be offset by proceeds from property sales or dispositions, including farm-out arrangements, which may result in reimbursement for capital spending that occurred in prior periods.
The following presents our capital expenditures (on an accrual basis) for the three and nine months ended September 30, 2017 and 2016:
 Three Months Ended September 30, Nine Months Ended September 30,
(millions)2017 2016 2017 2016
Acquisition, Capital and Exploration Expenditures 
  
  
  
Unproved Property Acquisition (1)
$(10) $—
 $1,816
 $—
Proved Property Acquisition (2)
(2) —
 839
 —
Exploration15
 25
 32
 183
Development570
 223
 1,751
 657
Midstream (3)
96
 9
 342
 29
Corporate and Other11
 38
 24
 58
Total$680
 $295
 $4,804
 $927
Investment in Equity Method Investee (4)
$—
 $2
 $68
 $8
Increase in Capital Lease Obligations$—
 $5
 $—
 $5
(1) Unproved property acquisition cost for the three months ended September 30, 2017 includes purchase price adjustments related to the Clayton Williams Energy Acquisition. Unproved property acquisition cost for the first nine months of 2017 includes $1.6 billion related to the Clayton Williams Energy Acquisition and $246 million related to the Delaware Basin asset acquisition.
(2) Proved property acquisition cost for the three months ended September 30, 2017 includes purchase price adjustments related to the Clayton Williams Energy Acquisition. Proved property acquisition cost for the first nine months of 2017 includes $722 million of proved properties and $58 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 first nine months of 2017 include gathering and processing assets related to the Clayton Williams Energy Acquisition.
(4) Investment in equity method investee for the first nine months of 2017 represents our contribution to the Advantage Joint Venture, in which Noble Midstream Partners owns a 50% interest.
Capital spending for additions to property, plant and equipment increased by $792 million during the first nine months of 2017 as compared with the first nine months of 2016, primarily due to increased US onshore development activity in response to a more favorable commodity price environment, and included $258 million related to the initial Leviathan project development.
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In addition, we used $637 million of cash, net of $21 million of cash acquired through the Clayton Williams Acquisition, to fund a portion of the consideration paid in the Clayton Williams Energy Acquisition, and we acquired Delaware Basin and other assets for $327 million. We received net cash proceeds of $1.0 billion from the Marcellus Shale upstream divestiture, and other investing activities provided a net $61 million of cash.
In comparison, during the first nine months of 2016, we received net proceeds of $786 million from asset sales.
Financing Activities  Our financing activities include the issuance or repurchase of Noble Energy common stock and Noble Midstream Partners common units, payment of cash dividends to Noble Energy shareholders and cash distributions to Noble Midstream Partners noncontrolling interest owners, and debt transactions.
Our primary financing activities during the first nine months of 2017 included $275 million net Revolving Credit Facility borrowings (including the borrowing and repayment of $1.3 billion associated with the Clayton Williams Energy Acquisition), $200 million net Noble Midstream Services Revolving Credit Facility borrowings used primarily to fund an acquisition, a $1.1 billion senior note refinancing, and $595 million related to the repayment of Clayton Williams Energy debt. In addition, we received $138 million net proceeds from the issuance of Noble Midstream Partners common units, paid $141 million of cash dividends and $19 million of cash distributions, and made $44 million of capital lease principal payments.
During the first nine months of 2017, we received $9 million cash proceeds from the exercise of stock options. We also purchased 1,010,078 shares of treasury stock with a value of $36 million. These shares included 719,849 shares with a value of $25 million related to vesting of Clayton Williams Energy restricted stock and options in connection with the Clayton Williams Energy Acquisition. The remaining shares were surrendered for the payment of withholding taxes due on the vesting of employee restricted stock awards.
In comparison, during the first nine months of 2016, we drew $1.4 billion under our Term Loan Facility and received $299 million proceeds from the Noble Midstream Partners initial public offering. We paid $129 million of cash dividends, repurchased senior notes for $1.38 billion, and made $39 million of capital lease principal payments. We also received $8 million cash proceeds from the exercise of stock options and purchased 235,157 shares of treasury stock from employees with a value of $8 million for the payment of withholding taxes.
See Item 1. Financial Statements – Consolidated Statements of Cash Flows.
Dividends   On October 24, 2017, our Board of Directors declared a quarterly cash dividend of 10 cents per common share, which will be paid on November 20, 2017 to shareholders of record on November 6, 2017. 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.

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES, UPDATE
The following discussion updates the policies and estimates disclosed in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Estimates of our Annual Report on Form 10-K for the year ended December 31, 2016.
Goodwill
As of September 30, 2017, our consolidated balance sheet includes goodwill of $1.3 billion, which resulted from the excess of the purchase price over amounts assigned to assets acquired and liabilities assumed in the Clayton Williams Energy Acquisition in second quarter 2017. All of our recorded goodwill is assigned to the Texas reporting unit.
Annual Goodwill Test Goodwill is not amortized to earnings but is assessed, at least annually, for impairment at the reporting unit level. Our policy is to conduct a qualitative goodwill impairment assessment by examining relevant events and circumstances which could have a negative impact on our goodwill such as: macroeconomic conditions; industry and market conditions, including commodity prices; cost factors; overall financial performance; reporting unit dispositions and acquisitions; and other relevant entity-specific events.
If, after assessing the totality of events or circumstances described above, we determine that it is more likely than not that the fair value of our Texas reporting unit is less than its carrying amount, the two-step goodwill test is performed. The two-step goodwill impairment test is also performed whenever events or changes in circumstances indicate that the carrying value may not be recoverable. If, after performing the two-step goodwill test, it is determined that the carrying value of goodwill is impaired, the amount of goodwill is reduced and a corresponding charge is made to earnings in the period in which the goodwill is determined to be impaired.
The two-step impairment test is used to identify potential goodwill impairment and measure the amount of a goodwill impairment loss to be recognized. The first step of the goodwill impairment test, used to identify potential impairment, compares the fair value of a reporting unit with its carrying amount, including goodwill. If the fair value of the reporting unit exceeds its carrying amount, goodwill is not considered to be impaired, and the second step of the test is not required. If necessary, the second step of the impairment test, used to measure the amount of impairment loss, compares the implied fair value of reporting unit goodwill with the carrying amount of that goodwill. If the carrying amount of reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess.
Goodwill Impairment Test - Estimates and Assumptions
The first step of the impairment test requires management to make estimates regarding the fair value of the reporting unit to which goodwill has been assigned. If it is necessary to determine the fair value of the Texas reporting unit, we use a combination of the income approach and the market approach.
Under the income approach, the fair value of the Texas reporting unit is estimated based on the present value of expected future cash flows. The income approach is dependent on a number of factors including estimates of forecasted revenue and operating costs and proved reserves, as well as the success of future exploration for and development of unproved reserves, discount rates and other variables. Negative revisions of estimated reserves quantities, increases in future cost estimates, divestiture of a significant component of the reporting unit, or sustained decreases in crude oil or natural gas prices could lead to a reduction in expected future cash flows and possibly an impairment of all or a portion of goodwill in future periods.
Key assumptions used in the discounted cash flow model described above include estimated quantities of crude oil, natural gas and NGL reserves, including both proved reserves and risk-adjusted unproved reserves; estimates of market prices considering forward commodity price curves as of the measurement date; and estimates of operating, administrative and capital costs adjusted for inflation. We discount the resulting future cash flows using a peer group based weighted average cost of capital.
Under the market approach, we estimate the fair value of the Texas reporting unit by comparison to similar businesses whose securities are actively traded in the public market. This requires management to make certain judgments about the selection of comparable companies and/or comparable recent company and asset transactions and transaction premiums, thereby creating a group of guideline public companies or transactions, or a peer group, that are engaged in similar operations with comparable risks and returns as our reporting unit. We use the peer group multiple method for the market approach. Market multiples represent market estimates of fair value based on selected financial metrics. We use earnings before interest, taxes, DD&A and exploration expense (also known as EBITDAX) as our financial metric as we believe it more accurately compares companies using successful efforts and full cost accounting methods, both of which are in our peer group.
GoodwillImpairment Review - Conclusion
Based on the results of our impairment test, we concluded that our goodwill at September 30, 2017 was not impaired, because the fair value of our Texas reporting unit was in excess of its respective net book value, including goodwill, by approximately 6%. While not required under Accounting Standards Codification (“ASC”) 350 “Intangibles - Goodwill and Other", we also
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performed a reconciliation of the determined enterprise fair value as compared to our total company market capitalization. From this additional analysis, we have concluded that the determination of the enterprise fair value closely aligns with our market capitalization.
We will continue to perform our annual impairment test at the end of the third quarter of each year unless events or circumstances trigger the need for an interim impairment test. The estimates used in our goodwill impairment test do not constitute forecasts or projections of future results of operations, but are rather estimates and assumptions based on historical results and assessments of macroeconomic factors affecting the Texas reporting unit as of the valuation date. We believe that our estimates and assumptions are reasonable, but they are subject to change from period to period. Actual results of operations and other factors will likely differ from the estimates used in our discounted cash flow valuation and it is possible that differences could be material. Although we base the fair value estimate of the Texas reporting unit on assumptions we believe to be reasonable, those assumptions are inherently unpredictable and uncertain and actual results could differ from the estimate. In the event of a prolonged industry downturn, commodity prices may stay depressed or decline further, thereby causing the fair value of the Texas reporting unit to decline, which could result in an impairment of goodwill.
DisposalsIf, in the future, we dispose of a reporting unit or a portion of a reporting unit that constitutes a business, we will include goodwill associated with that business in the carrying amount of the business in order to determine the gain or loss on disposal. The amount of goodwill allocated to the carrying amount of a business can significantly impact the amount of gain or loss recognized on the sale of that business. The amount of goodwill to be included in that carrying amount will be based on the relative fair value of the business to be disposed of and the portion of the reporting unit that will be retained. See Item 1. Financial Statements - Note 3. Clayton Williams Energy Acquisition.
Exit Costs
During second quarter 2017, in connection with our Marcellus Shale upstream divestiture, we accrued a liability of $41 million, discounted, for exit costs related to our commitment under a retained firm transportation contract, and charged the amount to loss on Marcellus Shale upstream divestiture in our consolidated statements of operations.
We have retained additional Marcellus Shale firm transportation contracts, relating to pipeline projects which are not yet commercially available to us. These projects are either under construction or have not yet been approved by the FERC. We did not accrue any exit cost liabilities related to these contracts as of June 30, 2017 or September 30, 2017. See Item 1. Financial Statements – Note 12. Commitments and Contingencies.
We account for exit costs in accordance with ASC 420 – Exit or Disposal Cost Obligations, which requires that a liability for a cost associated with an exit or disposal activity be recognized at fair value in the period in which the liability is incurred. Further, a liability for costs that will continue to be incurred under a contract for its remaining term without economic benefit to the entity shall be recognized at the “cease-use date”, which is defined as the date the entity ceases using the right conveyed by the contract, for example, the right to use a leased property or to receive future goods or services.
As these projects become commercially available to us, our management must make significant judgments and estimates regarding the timing and amount of recognition of any additional exit cost liabilities, taking into consideration our commercialization activities and/or the potential occurrence of a cease-use date.
Any additional exit cost liability will be initially recorded at fair value, and, in periods subsequent to initial measurement, changes to the liability, including changes resulting from revisions to either the timing or the amount of estimated cash flows over the future contract period, will be recognized as an adjustment to the liability in the period of the change. Therefore, initial recognition of a liability, as well as subsequent increases or decreases in exit cost liability estimates, could have a significant impact on our consolidated net income (loss).
Item 3.    Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
We areexposed 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 - Revenues– 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 managing our exposure to price changes.
At September 30, 2017, 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. Our2019, our open commodity derivative instruments were in a net asset position with a fair value of $6$102 million. Based on the September 30, 20172019 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 decrease the fair value of our net commodity derivative asset by approximately $44 million, effectively changing$228 million. Even with certain hedging arrangements in place to mitigate the risk of commodity price volatility, our net asset position to a net liability2019 revenues and results of $38 million. Our derivative instruments are executed
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under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty wouldoperations could be net cash settled at the time of election.adversely affected if commodity prices decline. See Item 1. Financial Statements – Note 5.12. Derivative Instruments and Hedging Activities.
Marcellus Shale Firm Transportation Contracts We retained certain other firm transportation contracts after the closing of the Marcellus Shale upstream divestiture. These contracts generally relate to pipelines which are currently under construction and not available for use, or pipelines for which construction has not yet begun and which are not currently approved by the FERC. Our volume commitments under these contracts total approximately 500,000 MMBtu/d.
Access to these contracts may be operationally or financially beneficial to other natural gas operators in the region. We are currently assessing various options to commercialize and address the remaining commitments, including the negotiation of capacity release, utilization of capacity through the purchase of third party natural gas and other potential arrangements. In addition, we have a “call” or right to purchase natural gas priced at a regional index from the acquirer of the Marcellus Shale upstream assets through July 1, 2022 when the acquirer's production exceeds 431,100 MMBtu/d but is less than 832,645 MMBtu/d. However, we do not have information regarding the acquirer's future development plans; therefore, there is uncertainty regarding when or if any volumes may become available. We expect these actions, some of which may require pipeline and/or FERC approval, to ultimately reduce the financial commitment associated with these contracts.
Changes in natural gas prices, in and out of basin supply and demand, the industry's ability to export substantial natural gas volumes to areas outside of the Marcellus Shale, as well as changes in basis differentials, could impact our commercialization options. We have no control over these market factors and therefore may not realize any benefits from our commercialization efforts. As a result, and when or if required, we may recognize substantial future liabilities, at fair value, for the net amount of the estimated remaining commitments under these contracts and charges to other operating expense in future periods. See Item 1. Financial Statements – Note 12. Commitments and Contingencies.
Interest Rate Risk
Changes in interest rates affect the amount of interest we pay on certain of our borrowings and the amount of interest we earn onborrowings. Borrowings under our short-term investments.
At September 30, 2017, we had approximately $7.3 billion (excluding capital lease obligations) of long-term debt outstanding, net of unamortized discount, premium and debt issuance costs. Of this amount, $6.2 billion was fixed-rate debt, net of unamortized discount, premium and debt issuance costs, with a weighted average interest rate of 5.05%. 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 September 30, 2017, our cash and cash equivalents totaled $564 million, approximately 59% of which was invested in money market funds and short-term investments with major financial institutions.
In addition, borrowings undercommercial paper program, the Revolving Credit Facility, Noble Midstream Services Revolving Credit Facility, and Noble Midstream Services Term Loan FacilityCredit Facilities, which as of September 30, 2019 total $1.5 billion and have a weighted average interest rate of 2.96%, 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 September 30, 2017,2019, 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, Term Loan Facility or the amounts, currentlyif any, outstanding under the Noble Revolving Credit Facilityfacilities or Noble Midstream Services Revolving Credit Facilitycommercial paper issuances mentioned above, would have had a de minimis impact.
Foreign Currency Risk
The US dollar is consideredimpact on interest expense for third quarter and the functional currency for each of our international operations. Substantially all of our international crude oil, natural gas and NGL production is sold pursuant to US dollar denominated contracts. Transactions, such as operating costs and administrative expenses that are paid in a foreign currency, are remeasured into US dollars and recorded in the financial statements at prevailing currency exchange rates. Certain monetary assets and liabilities, such as taxes payable in foreign tax jurisdictions, are settled in the foreign local currency. A reduction in the value of the US dollar against currencies of other countries in which we have material operations could result in the use of additional cash to settle operating, administrative and tax liabilities.
Net transaction gains and losses were de minimis for the three andfirst nine months ended September 30, 2017 and 2016.
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.
Table of Contents2019. See Item 1. Financial Statements – Note

7. Debt.
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;
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 projectsprojections 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, 2016 and in this quarterly report on Form 10-Q,2018, which describe factors that could cause our actual results to differ from
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those set forth in the forward-looking statements. Our Annual Report on Form 10-K for the year ended December 31, 20162018 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, 2016.2018.
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, 2016.2018.
Item 2.    Unregistered Sales of Equity Securities and Use of Proceeds
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
 
Approximate Dollar
Value of Shares that
May Yet Be
Purchased Under the
Plans or Programs
       (in thousands)
7/1/2017 - 7/31/20175,208
 $28.65
 —
 —
8/1/2017 - 8/31/201716,908
 23.78
 —
 —
9/1/2017 - 9/30/20171,568
 26.87
 —
 —
Total23,684
 $25.05
 —
 —
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)
7/1/2019 - 7/31/2019—
 $—
 —
  
8/1/2019 - 8/31/201910,931
 $22.20
 —
  
9/1/2019 - 9/30/2019—
 $—
 —
  
Total10,931
 $22.20
 —
 $455
(1) 
Stock repurchases during the period related to common stock received by us from employees for the payment of withholding taxes due on shares of common stock issued under stock-based compensation plans.
(2)
During third quarter 2019, we did not repurchase shares under the $750 million share repurchase program, authorized by the Board of Directors and announced on February 15, 2018, which expires December 31, 2020.

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Item 3.    Defaults Upon Senior Securities
None. 
Item 4.    Mine Safety Disclosures
Not applicable. 
Item 5.    Other Information
None.
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Item 6.    Exhibits

Exhibit Number Exhibit**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).
2.4
Purchase and Sale Agreement among Noble Energy, Inc. and HG Energy II Appalachia, LLC dated May 1, 2017 (filed as Exhibit 2.1 to the Registrant’s Current Report on Form 8-K (Date of Report: May 1, 2017) filed on May 5, 2017 and incorporated herein by reference).

2.5
Purchase Agreement by and among Wheeling Creek Midstream, LLC, Noble Energy US Holdings, LLC and Noble Energy, Inc. dated May 17, 2017 (filed as Exhibit 2.1 to the Registrant’s Current Report on Form 8-K (Date of Report: May 17, 2017) filed on May 23, 2017 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 24, 2017) (filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K (Date of Report: January 23, 2017) filed on January 27, 2017 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.February 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).

4.1
Seventh Supplemental Indenture dated as of August 15, 2017, to Indenture dated as of February 27, 2009 between Noble Energy, Inc. and Wells Fargo Bank, National Association, as Trustee, relating to senior debt securities of Noble Energy, Inc. (filed as Exhibit 4.1 to the Registrant’s Current Report on Form 8-K (Date of Report: August 15, 2017) filed on August 15, 2017 and incorporated herein by reference).
12.1
Calculation of ratio of earnings to fixed charges, 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.INS101 XBRL Instance DocumentThe following materials from Noble Energy, Inc.'s Quarterly Report on Form 10-Q for the quarter ended September 30, 2019 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Statements of Operations and Comprehensive Income (Loss); (ii) Consolidated Balance Sheets; (iii) Consolidated Statements of Cash Flows; (iv) Consolidated Statements of Equity; and (v) Notes to Consolidated Financial Statements.
   
101.SCH104 XBRL Schema DocumentCover Page Interactive Data File (formatted in iXBRL and contained in Exhibit 101).
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101.CALXBRL Calculation Linkbase Document
101.LABXBRL Label Linkbase Document
101.PREXBRL Presentation Linkbase Document
101.DEFXBRL Definition Linkbase Document
**Copies of exhibits will be furnished upon prepayment of 25 cents per page. Requests should be addressed to the Executive Vice President and Chief Financial Officer, Noble Energy, Inc., 1001 Noble Energy Way, Houston, Texas 77070.



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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 October 31, 2017November 7, 2019 /s/By: /s/ Kenneth M. Fisher
    
Kenneth M. Fisher
Executive Vice President, Chief Financial Officer




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