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x
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.
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o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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Delaware
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47-1054194
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(State or other jurisdiction of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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TABLE OF CONTENTS
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Page
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ITEM 1.
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CONSOLIDATED FINANCIAL STATEMENTS
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Three Months Ended
June 30, |
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Six Months Ended
June 30, |
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2018
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2017
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2018
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2017
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||||||||
Revenue
|
|
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Gathering revenue — related party
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$
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37,576
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$
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55,667
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$
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75,306
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$
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114,625
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Gathering revenue — third party
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23,438
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867
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49,577
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867
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||||
Total Revenue
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61,014
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56,534
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124,883
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115,492
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Expenses
|
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Operating expense — related party
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5,079
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7,089
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9,514
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14,717
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Operating expense — third party
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7,406
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5,957
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15,874
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12,590
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General and administrative expense — related party
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3,620
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2,663
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7,232
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5,546
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General and administrative expense — third party
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2,319
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1,033
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4,868
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2,225
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(Gain) loss on asset sales
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(254
|
)
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3,241
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2,501
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3,914
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||||
Depreciation expense
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5,443
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5,675
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11,299
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11,346
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Interest expense
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7,119
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1,124
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9,608
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2,162
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Total Expense
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30,732
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26,782
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60,896
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52,500
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Net Income
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30,282
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29,752
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63,987
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62,992
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Less: Net income attributable to noncontrolling interest
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277
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761
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6,135
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3,934
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Net Income Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP
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$
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30,005
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$
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28,991
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$
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57,852
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$
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59,058
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Calculation of Limited Partner Interest in Net Income:
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Net Income Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP
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$
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30,005
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$
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28,991
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$
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57,852
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$
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59,058
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Less: General partner interest in net income, including incentive distribution rights
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2,903
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1,305
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5,055
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2,434
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Limited partner interest in net income
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$
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27,102
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$
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27,686
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$
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52,797
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$
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56,624
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Net income per limited partner unit - basic
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$
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0.43
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$
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0.44
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$
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0.83
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$
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0.89
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Net income per limited partner unit - diluted
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$
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0.43
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$
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0.44
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$
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0.83
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$
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0.89
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Limited partner units outstanding - basic
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63,638
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63,585
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63,630
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63,575
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Limited partner unit outstanding - diluted
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63,677
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63,644
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63,670
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63,630
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Cash distributions declared per unit
(*)
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$
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0.3361
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$
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0.2922
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$
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0.6606
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$
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0.5743
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(*)
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Represents the cash distributions declared during the month following the end of each respective quarterly period. See Note 15.
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June 30,
2018 |
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December 31,
2017 |
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ASSETS
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Current Assets:
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Cash
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$
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707
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$
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3,194
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Receivables — related party
(Note 6)
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12,072
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13,104
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Receivables — third party
(Note 6)
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7,546
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8,251
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Other current assets
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2,726
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2,169
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Total Current Assets
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23,051
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26,718
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Property and Equipment
(Note 7)
:
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Property and equipment
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864,611
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972,841
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Less — accumulated depreciation
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72,098
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73,563
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Property and Equipment — Net
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792,513
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899,278
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Other assets
(Note 8)
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3,494
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593
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TOTAL ASSETS
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$
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819,058
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$
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926,589
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LIABILITIES AND EQUITY
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Current Liabilities:
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Accounts payable and other accrued liabilities
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$
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38,327
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$
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23,602
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Accounts payable — related party
(Note 9)
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3,211
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2,376
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Total Current Liabilities
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41,538
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25,978
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Other Liabilities:
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Revolving credit facility
(Note 10)
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11,000
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149,500
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Long-term debt
(Note 11)
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393,169
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—
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Total Liabilities
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445,707
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175,478
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Partners’ Capital:
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Common units (63,638,165 units issued and outstanding at June 30, 2018 and 63,588,152 units issued and outstanding at December 31, 2017)
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295,405
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389,427
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General partner interest
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8,893
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4,328
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Partners’ capital attributable to CNX Midstream Partners LP
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304,298
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393,755
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Noncontrolling interest
|
69,053
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357,356
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Total Partners’ Capital
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373,351
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751,111
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TOTAL LIABILITIES AND PARTNERS’ CAPITAL
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$
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819,058
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$
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926,589
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Partners’ Capital
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Total
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Capital
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||||||||||
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Limited
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General
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Attributable
|
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Noncontrolling
|
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||||||||||
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Partners
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Partner
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to Partners
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Interest
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Total
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||||||||||
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Balance at December 31, 2017
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$
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389,427
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$
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4,328
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$
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393,755
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$
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357,356
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$
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751,111
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|
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Net income
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52,797
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5,055
|
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57,852
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6,135
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|
|
63,987
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|
|||||
(Distributions to) contributions from general partner and noncontrolling interest holders, net
|
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—
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|
20
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|
20
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|
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(3,525
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)
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(3,505
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)
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|||||
Quarterly distributions to unitholders
|
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(40,574
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)
|
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(3,615
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)
|
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(44,189
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)
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—
|
|
|
(44,189
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)
|
|||||
Acquisition of Shirley-Penns System
|
|
(153,587
|
)
|
|
—
|
|
|
(153,587
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)
|
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(111,413
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)
|
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(265,000
|
)
|
|||||
HG Energy Transaction
|
|
46,420
|
|
|
—
|
|
|
46,420
|
|
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(179,500
|
)
|
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(133,080
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)
|
|||||
Noncash contribution of assets held by general partner
|
|
—
|
|
|
3,105
|
|
|
3,105
|
|
|
—
|
|
|
3,105
|
|
|||||
Unit-based compensation
|
|
1,269
|
|
|
—
|
|
|
1,269
|
|
|
—
|
|
|
1,269
|
|
|||||
Vested units withheld for unitholder taxes
|
|
(347
|
)
|
|
—
|
|
|
(347
|
)
|
|
—
|
|
|
(347
|
)
|
|||||
Balance at June 30, 2018
|
|
$
|
295,405
|
|
|
$
|
8,893
|
|
|
$
|
304,298
|
|
|
$
|
69,053
|
|
|
$
|
373,351
|
|
|
Six Months Ended
June 30, |
||||||
|
2018
|
|
2017
|
||||
Cash Flows from Operating Activities:
|
|
|
|
||||
Net income
|
$
|
63,987
|
|
|
$
|
62,992
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
||||
Depreciation expense and amortization of debt issuance costs
|
11,872
|
|
|
11,430
|
|
||
Unit-based compensation
|
1,269
|
|
|
650
|
|
||
Loss on long-term asset sales
|
2,501
|
|
|
3,914
|
|
||
Other
|
387
|
|
|
167
|
|
||
Changes in assets and liabilities:
|
|
|
|
||||
Receivables — related party
|
1,032
|
|
|
4,009
|
|
||
Receivables — third party
|
705
|
|
|
(867
|
)
|
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Other current and non-current assets
|
108
|
|
|
3,574
|
|
||
Accounts payable and other accrued liabilities
|
12,824
|
|
|
(3,645
|
)
|
||
Accounts payable — related party
|
856
|
|
|
(5,790
|
)
|
||
Net Cash Provided by Operating Activities
|
95,541
|
|
|
76,434
|
|
||
|
|
|
|
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Cash Flows from Investing Activities:
|
|
|
|
||||
Capital expenditures
|
(41,587
|
)
|
|
(23,415
|
)
|
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Proceeds from sale of assets
|
6,462
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|
|
14,000
|
|
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Net Cash Used in Investing Activities
|
(35,125
|
)
|
|
(9,415
|
)
|
||
|
|
|
|
||||
Cash Flows from Financing Activities:
|
|
|
|
||||
Distributions to general partner and noncontrolling interest holders, net
|
(3,505
|
)
|
|
(25,317
|
)
|
||
Vested units withheld for unitholder taxes
|
(347
|
)
|
|
(411
|
)
|
||
Quarterly distributions to unitholders
|
(44,189
|
)
|
|
(36,846
|
)
|
||
Net payments on unsecured $250.0 million credit facility
|
(149,500
|
)
|
|
(6,000
|
)
|
||
Net borrowings on secured $600.0 million credit facility
|
11,000
|
|
|
—
|
|
||
Proceeds from issuance of long-term debt, net of discount
|
394,000
|
|
|
—
|
|
||
Debt issuance costs
|
(5,362
|
)
|
|
—
|
|
||
Acquisition of Shirley-Penns System
|
(265,000
|
)
|
|
—
|
|
||
Net Cash Used in Financing Activities
|
(62,903
|
)
|
|
(68,574
|
)
|
||
|
|
|
|
||||
Net Decrease in Cash
|
(2,487
|
)
|
|
(1,555
|
)
|
||
Cash at Beginning of Period
|
3,194
|
|
|
6,421
|
|
||
Cash at End of Period
|
$
|
707
|
|
|
$
|
4,866
|
|
|
|
|
|
||||
Cash paid during the period for:
|
|
|
|
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Interest
|
$
|
1,367
|
|
|
$
|
2,171
|
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•
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Our Anchor Systems, in which the Partnership owns a
100%
controlling interest, include our most developed midstream systems that generate the largest portion of our current cash flows, which includes our four primary midstream systems (the McQuay System, the Majorsville System, the Mamont System and the Shirley-Penns System) and related assets.
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•
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Our Growth Systems were primarily located in the dry gas regions of our dedicated acreage in central West Virginia that were generally in earlier phases of development than our other systems and required substantial future expansion capital expenditures to materially increase production. As a result of the HG Energy Transaction described below, the Partnership distributed its ownership interests in the Growth Systems assets to CNX Gathering, which subsequently transferred these assets to HG Energy.
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•
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Our Additional Systems currently include several gathering systems primarily located in the wet gas regions of our dedicated acreage (current activity is primarily located within the Pittsburgh Airport area) that we expect will require lower levels of expansion capital investment relative to our Growth Systems. The substantial majority of capital investment on these systems would be funded by CNX in proportion to CNX Gathering’s
95%
retained ownership interest. As a result of the HG Energy Transaction described below, the Partnership distributed its ownership interests in the Moundsville area assets to CNX Gathering, which subsequently transferred these assets to HG Energy.
|
•
|
Dedication to the Partnership of approximately
16,100
additional Utica acres in our Anchor Systems;
|
•
|
Commitment to develop
40
additional wells in the Anchor Systems by 2023, subject to the terms of the GGA;
|
•
|
Contribution to the Anchor Systems of a 20” high pressure pipeline in addition to a one-time payment to us of approximately
$2.0 million
in cash; and
|
•
|
Distribution of our
5%
interest in the Growth Systems and related assets as well as our
5%
interest in the Moundsville midstream assets, which were a part of the Additional Systems, to CNX Gathering, which subsequently transferred these assets to HG Energy.
|
•
|
Release from dedication of approximately
18,000
acres, net to the Partnership, which was comprised of approximately
275,000
acres (or approximately
14,000
acres, net to the Partnership) within the Growth and Additional Systems and approximately
4,200
scattered acres located in the Anchor Systems;
|
•
|
Removal of our obligation to provide gathering services or make capital investments in the Growth Systems or in the Moundsville area of the Additional Systems; and
|
•
|
Commitment by HG Energy to develop
12
additional wells in the Anchor Systems by 2021, subject to the terms of the HG Energy GGA.
|
•
|
we have more than
$1.0
billion of revenues in the year ending December 31, 2018;
|
•
|
the limited partner interests held by non-affiliates have a market value of more than
$700
million as of June 30, 2018, which determination shall be made as of December 31, 2018; or
|
•
|
we issue more than
$1.0
billion of non-convertible debt over a
three
-year period.
|
|
|
|
|
Marginal Percentage Interest in
Distributions
|
||||
Distribution Targets
|
|
Total Quarterly Distribution Per Unit Target Amount
|
|
Unitholders
|
|
General Partner (including IDRs)
|
||
Minimum Quarterly Distribution
|
|
|
|
$0.2125
|
|
98%
|
|
2%
|
First Target Distribution
|
|
Above $0.2125
|
|
up to $0.24438
|
|
98%
|
|
2%
|
Second Target Distribution
|
|
Above $0.24438
|
|
up to $0.26563
|
|
85%
|
|
15%
|
Third Target Distribution
|
|
Above $0.26563
|
|
up to $0.31875
|
|
75%
|
|
25%
|
Thereafter
|
|
Above $0.31875
|
|
|
|
50%
|
|
50%
|
(in thousands, except per unit information)
|
|
|
|
|
|
|
||||
Quarters Ended
|
|
Total Quarterly Distribution Per Unit
|
|
Total Quarterly Cash Distribution
|
|
Date of Distribution
|
||||
Year ended December 31, 2017
|
|
|
|
|
|
|
||||
March 31
|
|
$
|
0.2821
|
|
|
$
|
18,842
|
|
|
May 15, 2017
|
June 30
|
|
0.2922
|
|
|
19,698
|
|
|
August 14, 2017
|
||
September 30
|
|
0.3025
|
|
|
20,573
|
|
|
November 14, 2017
|
||
December 31
|
|
0.3133
|
|
|
21,489
|
|
|
February 14, 2018
|
||
|
|
|
|
|
|
|
||||
Year ending December 31, 2018
|
|
|
|
|
|
|
||||
March 31
|
|
$
|
0.3245
|
|
|
$
|
22,700
|
|
|
May 15, 2018
|
|
Three Months Ended June 30,
|
|
Six Months Ended
June 30, |
||||||||||||
(in thousands, except per unit information)
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Net Income Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP
|
$
|
30,005
|
|
|
$
|
28,991
|
|
|
$
|
57,852
|
|
|
$
|
59,058
|
|
Less: General partner interest in net income, including incentive distribution rights
|
2,903
|
|
|
1,305
|
|
|
5,055
|
|
|
2,434
|
|
||||
Limited partner interest in net income
|
$
|
27,102
|
|
|
$
|
27,686
|
|
|
$
|
52,797
|
|
|
$
|
56,624
|
|
|
|
|
|
|
|
|
|
||||||||
Net income allocable to common units — basic and diluted
|
$
|
27,102
|
|
|
$
|
14,988
|
|
|
$
|
52,797
|
|
|
$
|
30,652
|
|
Net income allocable to subordinated units — basic and diluted
|
—
|
|
|
12,698
|
|
|
—
|
|
|
25,972
|
|
||||
Limited partner interest in net income — basic and diluted
|
$
|
27,102
|
|
|
$
|
27,686
|
|
|
$
|
52,797
|
|
|
$
|
56,624
|
|
|
|
|
|
|
|
|
|
||||||||
Weighted average limited partner units outstanding — Basic
|
|
|
|
|
|
|
|
||||||||
Common units
|
63,638
|
|
|
34,422
|
|
|
63,630
|
|
|
34,412
|
|
||||
Subordinated units
|
—
|
|
|
29,163
|
|
|
—
|
|
|
29,163
|
|
||||
Total
|
63,638
|
|
|
63,585
|
|
|
63,630
|
|
|
63,575
|
|
||||
|
|
|
|
|
|
|
|
||||||||
Weighted average limited partner units outstanding — Diluted
|
|
|
|
|
|
|
|
||||||||
Common units
|
63,677
|
|
|
34,481
|
|
|
63,670
|
|
|
34,467
|
|
||||
Subordinated units
|
—
|
|
|
29,163
|
|
|
—
|
|
|
29,163
|
|
||||
Total
|
63,677
|
|
|
63,644
|
|
|
63,670
|
|
|
63,630
|
|
||||
|
|
|
|
|
|
|
|
||||||||
Net income per limited partner unit — Basic
|
|
|
|
|
|
|
|
||||||||
Common units
|
$
|
0.43
|
|
|
$
|
0.44
|
|
|
$
|
0.83
|
|
|
$
|
0.89
|
|
Subordinated units
|
—
|
|
|
0.44
|
|
|
—
|
|
|
0.89
|
|
||||
Total
|
$
|
0.43
|
|
|
$
|
0.44
|
|
|
$
|
0.83
|
|
|
$
|
0.89
|
|
|
|
|
|
|
|
|
|
||||||||
Net income per limited partner unit — Diluted
|
|
|
|
|
|
|
|
||||||||
Common units
|
$
|
0.43
|
|
|
$
|
0.43
|
|
|
$
|
0.83
|
|
|
$
|
0.89
|
|
Subordinated units
|
—
|
|
|
0.44
|
|
|
—
|
|
|
0.89
|
|
||||
Total
|
$
|
0.43
|
|
|
$
|
0.44
|
|
|
$
|
0.83
|
|
|
$
|
0.89
|
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
(in thousands)
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Operational services — CNX
|
$
|
3,257
|
|
|
$
|
2,999
|
|
|
$
|
6,092
|
|
|
$
|
6,187
|
|
Electrical compression
|
1,822
|
|
|
4,090
|
|
|
3,422
|
|
|
8,530
|
|
||||
Total Operating Expense — Related Party
|
$
|
5,079
|
|
|
$
|
7,089
|
|
|
$
|
9,514
|
|
|
$
|
14,717
|
|
|
|
|
|
|
|
|
|
||||||||
CNX
|
$
|
3,620
|
|
|
$
|
2,530
|
|
|
$
|
7,232
|
|
|
$
|
5,241
|
|
Noble Energy
|
—
|
|
|
133
|
|
|
—
|
|
|
305
|
|
||||
Total General and Administrative Expense — Related Party
|
$
|
3,620
|
|
|
$
|
2,663
|
|
|
$
|
7,232
|
|
|
$
|
5,546
|
|
•
|
our payment of an annually-determined administrative support fee (approximately
$1.9 million
for the year ending December 31, 2018) for the provision of certain services by CNX and its affiliates, including executive costs;
|
•
|
our obligation to reimburse CNX for all other direct or allocated costs and expenses incurred by CNX in providing general and administrative services (which reimbursement is in addition to certain expenses of our general partner and its affiliates that are reimbursed under our partnership agreement);
|
•
|
our right of first offer to acquire (i) CNX Gathering’s retained interests in our Additional Systems, (ii) CNX Gathering’s other ancillary midstream assets and (iii) any additional midstream assets that CNX Gathering develops; and
|
•
|
an indemnity from CNX Gathering for liabilities associated with the use, ownership or operation of our assets, including environmental liabilities, to the extent relating to the period of time prior to the closing of the IPO; and our obligation to indemnify CNX Gathering for events and conditions associated with the use, ownership or operation of our assets that occur after the closing of the IPO, including environmental liabilities.
|
•
|
Gas Gathering:
|
◦
|
McQuay area Utica - a fee of
$0.225
per MMBtu; and
|
◦
|
Wadestown Marcellus and Utica - a fee of
$0.35
per MMBtu.
|
•
|
Compression:
|
◦
|
For areas not benefitting from system expansion pursuant to the Second Amended and Restated GGA, compression services are included in the base fees; and
|
◦
|
In the McQuay and Wadestown areas, for wells turned in line beginning January 1, 2018 and beyond, we will receive additional fees of
$0.065
per MMBtu for Tier 1 pressure services (maximum receipt point of pressure of 600 psi) and
$0.130
per MMBtu for Tier 2 pressure services (maximum receipt point of pressure of 300 psi).
|
•
|
January 1, 2018 to December 31, 2018 -
30
wells (deficiency payment of
$3.5 million
per well)
|
•
|
January 1, 2019 to April 30, 2020 -
40
wells (deficiency payment of
$3.5 million
per well)
|
•
|
May 1, 2020 to April 30, 2021 -
40
wells (deficiency payment of
$2.0 million
per well)
|
•
|
May 1, 2021 to April 30, 2022 -
30
wells (deficiency payment of
$2.0 million
per well)
|
|
Revenue under MVC (in millions)
|
||
Remainder of year ending December 31, 2018
|
$
|
14.2
|
|
Year ending December 31, 2019
|
28.8
|
|
|
Year ending December 31, 2020
|
34.7
|
|
|
Year ending December 31, 2021
|
40.8
|
|
|
Year ending December 31, 2022
|
47.8
|
|
|
Remainder of term
|
256.6
|
|
|
Total revenue to be recognized under Shirley-Penns contract through December 31, 2031
|
$
|
422.9
|
|
•
|
For the services we provide with respect to natural gas from the Marcellus Shale formation that does not require downstream processing, or dry gas, we will receive a fee of
$0.431
per MMBtu.
|
•
|
For the services we provide with respect to natural gas from the Marcellus Shale formation that requires downstream processing, or wet gas, we will receive:
|
◦
|
a fee of
$0.296
per MMBtu in the Moundsville area (Marshall County, West Virginia) and in the Pittsburgh International Airport area; and
|
◦
|
a fee of
$0.593
per MMBtu for all other areas in the dedication area.
|
•
|
For the services we provide with respect to natural gas from the Utica Shale formation, we will receive a weighted average rate of
$0.16
per MMBtu.
|
•
|
Our fees for condensate services will be
$5.38
per Bbl in the Majorsville area and
$2.693
per Bbl in the Moundsville area.
|
(in thousands)
|
June 30, 2018
|
|
December 31, 2017
|
||||
Receivables - related party
|
|
|
|
||||
CNX
|
$
|
12,072
|
|
|
$
|
12,801
|
|
CNX Gathering
|
—
|
|
|
303
|
|
||
Receivables - related party
|
$
|
12,072
|
|
|
$
|
13,104
|
|
|
|
|
|
||||
Receivables - third party
|
7,546
|
|
|
8,251
|
|
||
Total receivables
|
$
|
19,618
|
|
|
$
|
21,355
|
|
(in thousands)
|
June 30, 2018
|
|
December 31, 2017
|
|
Estimated Useful
Lives in Years
|
||||
Land
|
$
|
47,975
|
|
|
$
|
76,130
|
|
|
N/A
|
Gathering equipment
|
570,603
|
|
|
662,595
|
|
|
25 — 40
|
||
Compression equipment
|
176,652
|
|
|
180,038
|
|
|
30 — 40
|
||
Processing equipment
|
30,979
|
|
|
30,979
|
|
|
40
|
||
Assets under construction
|
38,402
|
|
|
23,099
|
|
|
N/A
|
||
Total Property and Equipment
|
$
|
864,611
|
|
|
$
|
972,841
|
|
|
|
|
|
|
|
|
|
||||
Less: Accumulated depreciation
|
|
|
|
|
|
||||
Gathering equipment
|
$
|
50,744
|
|
|
$
|
53,544
|
|
|
|
Compression equipment
|
15,808
|
|
|
14,886
|
|
|
|
||
Processing equipment
|
5,546
|
|
|
5,133
|
|
|
|
||
Total Accumulated Depreciation
|
$
|
72,098
|
|
|
$
|
73,563
|
|
|
|
|
|
|
|
|
|
||||
Property and Equipment, Net
|
$
|
792,513
|
|
|
$
|
899,278
|
|
|
|
(in thousands)
|
June 30, 2018
|
|
December 31, 2017
|
||||
Pipe stock
|
$
|
—
|
|
|
$
|
392
|
|
Financing fees
|
3,219
|
|
|
122
|
|
||
Other
|
275
|
|
|
79
|
|
||
Total Other Assets
|
$
|
3,494
|
|
|
$
|
593
|
|
(in thousands)
|
June 30, 2018
|
|
December 31, 2017
|
||||
CNX Resources:
|
|
|
|
||||
Expense reimbursements
|
$
|
1,148
|
|
|
$
|
780
|
|
Capital expenditures reimbursements
|
—
|
|
|
83
|
|
||
General and administrative services
|
2,055
|
|
|
1,458
|
|
||
Total due to CNX Resources
|
3,203
|
|
|
2,321
|
|
||
|
|
|
|
||||
Noble Energy:
|
|
|
|
||||
General and administrative services
|
—
|
|
|
55
|
|
||
Total due to Noble Energy
|
—
|
|
|
55
|
|
||
|
|
|
|
||||
CNX Gathering LLC:
|
|
|
|
||||
Capital expenditures reimbursement
|
8
|
|
|
—
|
|
||
Total due to CNX Gathering LLC
|
8
|
|
|
—
|
|
||
|
|
|
|
||||
Total Accounts Payable — Related Party
|
$
|
3,211
|
|
|
$
|
2,376
|
|
•
|
the base rate, which is the highest of (i) the federal funds open rate plus
0.50%
, (ii) PNC Bank, N.A.’s prime rate, and (iii) the one-month LIBOR rate plus
1.0%
, in each case, plus a margin ranging from
0.75%
to
1.75%
; or
|
•
|
the LIBOR rate, which is the LIBOR rate plus a margin ranging from
1.75%
to
2.75%
.
|
•
|
a maximum total leverage ratio of no greater than between
4.75
to 1.00 ranging to no greater than
5.50
to 1.00 in certain circumstances;
|
•
|
a maximum secured leverage ratio of no greater than
3.50
to 1.00; and
|
•
|
a minimum interest coverage ratio of no less than
2.50
to 1.00;
|
|
June 30, 2018
|
|
December 31, 2017
|
||||
Senior Notes due March 2026 at 6.5%
|
$
|
400,000
|
|
|
$
|
—
|
|
Less: Unamortized debt issuance costs
|
1,081
|
|
|
—
|
|
||
Less: Unamortized bond discount
|
5,750
|
|
|
—
|
|
||
Long-term debt
|
$
|
393,169
|
|
|
$
|
—
|
|
(in thousands)
|
Minimum Lease Payments
|
||
Period from July 1, 2018 through December 31, 2018
|
$
|
1,023
|
|
Year ending December 31, 2019
|
1,627
|
|
|
Year ending December 31, 2020
|
1,042
|
|
|
|
$
|
3,692
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
(in thousands)
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Gathering Revenue:
|
|
|
|
|
|
|
|
||||||||
Anchor Systems
|
$
|
56,584
|
|
|
$
|
50,195
|
|
|
$
|
112,774
|
|
|
$
|
102,894
|
|
Growth Systems
|
668
|
|
|
2,018
|
|
|
2,572
|
|
|
4,243
|
|
||||
Additional Systems
|
3,762
|
|
|
4,321
|
|
|
9,537
|
|
|
8,355
|
|
||||
Total Gathering Revenue
|
$
|
61,014
|
|
|
$
|
56,534
|
|
|
$
|
124,883
|
|
|
$
|
115,492
|
|
|
|
|
|
|
|
|
|
||||||||
Net Income (Loss):
|
|
|
|
|
|
|
|
||||||||
Anchor Systems
|
$
|
29,991
|
|
|
$
|
30,764
|
|
|
$
|
63,134
|
|
|
$
|
62,380
|
|
Growth Systems
|
186
|
|
|
506
|
|
|
379
|
|
|
453
|
|
||||
Additional Systems
|
105
|
|
|
(1,518
|
)
|
|
474
|
|
|
159
|
|
||||
Total Net Income
|
$
|
30,282
|
|
|
$
|
29,752
|
|
|
$
|
63,987
|
|
|
$
|
62,992
|
|
|
|
|
|
|
|
|
|
||||||||
Depreciation Expense:
|
|
|
|
|
|
|
|
||||||||
Anchor Systems
|
$
|
4,733
|
|
|
$
|
4,201
|
|
|
$
|
9,203
|
|
|
$
|
8,397
|
|
Growth Systems
|
195
|
|
|
543
|
|
|
748
|
|
|
1,088
|
|
||||
Additional Systems
|
515
|
|
|
931
|
|
|
1,348
|
|
|
1,861
|
|
||||
Total Depreciation Expense
|
$
|
5,443
|
|
|
$
|
5,675
|
|
|
$
|
11,299
|
|
|
$
|
11,346
|
|
|
|
|
|
|
|
|
|
||||||||
Capital Expenditures for Segment Assets:
|
|
|
|
|
|
|
|
||||||||
Anchor Systems
|
$
|
24,502
|
|
|
$
|
11,841
|
|
|
$
|
38,290
|
|
|
$
|
22,374
|
|
Growth Systems
|
42
|
|
|
382
|
|
|
120
|
|
|
821
|
|
||||
Additional Systems
|
1,071
|
|
|
—
|
|
|
3,177
|
|
|
220
|
|
||||
Total Capital Expenditures
|
$
|
25,615
|
|
|
$
|
12,223
|
|
|
$
|
41,587
|
|
|
$
|
23,415
|
|
(in thousands)
|
June 30, 2018
|
|
December 31, 2017
|
||||
Segment Assets
|
|
|
|
||||
Anchor Systems
|
$
|
737,152
|
|
|
$
|
694,942
|
|
Growth Systems
|
—
|
|
|
92,659
|
|
||
Additional Systems
|
81,906
|
|
|
138,988
|
|
||
Total Segment Assets
|
$
|
819,058
|
|
|
$
|
926,589
|
|
|
Number of Units
|
|
Weighted Average Grant Date Fair Value
|
||
Total awarded and unvested at December 31, 2017
|
134,153
|
|
$
|
16.40
|
|
Granted
|
132,933
|
|
19.14
|
|
|
Vested
|
(70,872)
|
|
16.65
|
|
|
Forfeited
|
(17,639)
|
|
16.25
|
|
|
Total awarded and unvested at June 30, 2018
|
178,575
|
|
$
|
18.30
|
|
ITEM 2.
|
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
•
|
The transactions provide for the additional dedication of 16,100 additional Utica acres in the Anchor Systems by our Sponsor and the release from dedication of approximately
18,000
acres, net to the Partnership, which was comprised
|
•
|
The transactions increase minimum well commitments, with our Sponsor committing to develop 40 additional wells in the Anchor Systems by 2023 and HG Energy committing to develop 12 additional wells in the Anchor Systems by 2021, in each case, subject to the applicable GGAs;
|
•
|
Our Sponsor contributed to the Partnership’s Anchor Systems a 20” high-pressure pipeline as well as $2.0 million in cash;
|
•
|
In exchange for the incremental Utica acreage dedication, minimum well commitments, and high-pressure pipeline with third-party revenue, we distributed our 5% controlling interest in the midstream assets of the Growth Systems and the Moundsville midstream assets located within the Additional Systems, to affiliates of our Sponsor, which it subsequently transferred to HG Energy, and released acreage from dedication discussed above; and
|
•
|
The transaction with HG Energy also includes an amended GGA in the Anchor Systems, which we believe provides us with more control over operating strategies and expansion in the Anchor Systems. In addition, we will no longer be obligated to provide gathering services or make capital investments in the Growth Systems and the Moundsville midstream assets.
|
•
|
Net income of $
30.0 million
as compared to $
29.0 million
;
|
•
|
Cash provided by operating activities of $
53.7 million
as compared to
$42.3 million
;
|
•
|
Adjusted EBITDA (non-GAAP) of
$41.3 million
as compared to
$34.4 million
; and
|
•
|
Distributable cash flow (non-GAAP) of
$31.6 million
as compared to
$29.6 million
.
|
|
Quarter Ended June 30,
|
|||||||||||||
|
2018
|
|
2017
|
|
Change ($)
|
|
Change (%)
|
|||||||
|
($ in thousands)
|
|||||||||||||
Revenue
|
|
|
|
|
|
|
|
|||||||
Gathering revenue — related party
|
$
|
37,576
|
|
|
$
|
55,667
|
|
|
$
|
(18,091
|
)
|
|
(32.5
|
)%
|
Gathering revenue — third party
|
23,438
|
|
|
867
|
|
|
22,571
|
|
|
2,603.3
|
%
|
|||
Total Revenue
|
61,014
|
|
|
56,534
|
|
|
4,480
|
|
|
7.9
|
%
|
|||
Expenses
|
|
|
|
|
|
|
|
|||||||
Operating expense — related party
|
5,079
|
|
|
7,089
|
|
|
(2,010
|
)
|
|
(28.4
|
)%
|
|||
Operating expense — third party
|
7,406
|
|
|
5,957
|
|
|
1,449
|
|
|
24.3
|
%
|
|||
General and administrative expense — related party
|
3,620
|
|
|
2,663
|
|
|
957
|
|
|
35.9
|
%
|
|||
General and administrative expense — third party
|
2,319
|
|
|
1,033
|
|
|
1,286
|
|
|
124.5
|
%
|
|||
(Gain) loss on asset sales
|
(254
|
)
|
|
3,241
|
|
|
(3,495
|
)
|
|
(107.8
|
)%
|
|||
Depreciation expense
|
5,443
|
|
|
5,675
|
|
|
(232
|
)
|
|
(4.1
|
)%
|
|||
Interest expense
|
7,119
|
|
|
1,124
|
|
|
5,995
|
|
|
533.4
|
%
|
|||
Total Expense
|
30,732
|
|
|
26,782
|
|
|
3,950
|
|
|
14.7
|
%
|
|||
Net Income
|
$
|
30,282
|
|
|
$
|
29,752
|
|
|
$
|
530
|
|
|
1.8
|
%
|
Less: Net income attributable to noncontrolling interest
|
277
|
|
|
761
|
|
|
(484
|
)
|
|
(63.6
|
)%
|
|||
Net Income Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP
|
$
|
30,005
|
|
|
$
|
28,991
|
|
|
$
|
1,014
|
|
|
3.5
|
%
|
|
Anchor
|
|
Growth
|
|
Additional
|
|
TOTAL
|
||||
Dry Gas (BBtu/d) (**)
|
667
|
|
|
15
|
|
|
9
|
|
|
691
|
|
Wet Gas (BBtu/d) (**)
|
530
|
|
|
1
|
|
|
121
|
|
|
652
|
|
Condensate (MMcfe/d)
|
3
|
|
|
—
|
|
|
5
|
|
|
8
|
|
Total Gathered Volumes (*)
|
1,200
|
|
|
16
|
|
|
135
|
|
|
1,351
|
|
|
Anchor
|
|
Growth
|
|
Additional
|
|
TOTAL
|
||||
Dry Gas (BBtu/d) (**)
|
589
|
|
|
47
|
|
|
11
|
|
|
647
|
|
Wet Gas (BBtu/d) (**)
|
437
|
|
|
4
|
|
|
126
|
|
|
567
|
|
Condensate (MMcfe/d)
|
6
|
|
|
—
|
|
|
3
|
|
|
9
|
|
Total Gathered Volumes (*)
|
1,032
|
|
|
51
|
|
|
140
|
|
|
1,223
|
|
|
Six Months Ended June 30,
|
|||||||||||||
|
2018
|
|
2017
|
|
Change ($)
|
|
Change (%)
|
|||||||
|
($ in thousands)
|
|||||||||||||
Revenue
|
|
|
|
|
|
|
|
|||||||
Gathering revenue — related party
|
$
|
75,306
|
|
|
$
|
114,625
|
|
|
$
|
(39,319
|
)
|
|
(34.3
|
)%
|
Gathering revenue — third party
|
49,577
|
|
|
867
|
|
|
48,710
|
|
|
5,618.2
|
%
|
|||
Total Revenue
|
124,883
|
|
|
115,492
|
|
|
9,391
|
|
|
8.1
|
%
|
|||
Expenses
|
|
|
|
|
|
|
|
|||||||
Operating expense — related party
|
9,514
|
|
|
14,717
|
|
|
(5,203
|
)
|
|
(35.4
|
)%
|
|||
Operating expense — third party
|
15,874
|
|
|
12,590
|
|
|
3,284
|
|
|
26.1
|
%
|
|||
General and administrative expense — related party
|
7,232
|
|
|
5,546
|
|
|
1,686
|
|
|
30.4
|
%
|
|||
General and administrative expense — third party
|
4,868
|
|
|
2,225
|
|
|
2,643
|
|
|
118.8
|
%
|
|||
Loss on asset sales
|
2,501
|
|
|
3,914
|
|
|
(1,413
|
)
|
|
(36.1
|
)%
|
|||
Depreciation expense
|
11,299
|
|
|
11,346
|
|
|
(47
|
)
|
|
(0.4
|
)%
|
|||
Interest expense
|
9,608
|
|
|
2,162
|
|
|
7,446
|
|
|
344.4
|
%
|
|||
Total Expense
|
60,896
|
|
|
52,500
|
|
|
8,396
|
|
|
16.0
|
%
|
|||
Net Income
|
$
|
63,987
|
|
|
$
|
62,992
|
|
|
$
|
995
|
|
|
1.6
|
%
|
Less: Net income attributable to noncontrolling interest
|
6,135
|
|
|
3,934
|
|
|
2,201
|
|
|
55.9
|
%
|
|||
Net Income Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP
|
$
|
57,852
|
|
|
$
|
59,058
|
|
|
$
|
(1,206
|
)
|
|
(2.0
|
)%
|
|
Anchor
|
|
Growth
|
|
Additional
|
|
TOTAL
|
||||
Dry Gas (BBtu/d) (**)
|
652
|
|
|
29
|
|
|
16
|
|
|
697
|
|
Wet Gas (BBtu/d) (**)
|
538
|
|
|
2
|
|
|
141
|
|
|
681
|
|
Condensate (MMcfe/d)
|
4
|
|
|
—
|
|
|
13
|
|
|
17
|
|
Total Gathered Volumes (*)
|
1,194
|
|
|
31
|
|
|
170
|
|
|
1,395
|
|
|
Anchor
|
|
Growth
|
|
Additional
|
|
TOTAL
|
||||
Dry Gas (BBtu/d) (**)
|
625
|
|
|
50
|
|
|
20
|
|
|
695
|
|
Wet Gas (BBtu/d) (**)
|
440
|
|
|
4
|
|
|
111
|
|
|
555
|
|
Condensate (MMcfe/d)
|
5
|
|
|
—
|
|
|
3
|
|
|
8
|
|
Total Gathered Volumes (*)
|
1,070
|
|
|
54
|
|
|
134
|
|
|
1,258
|
|
•
|
our operating performance as compared to those of other companies in the midstream energy industry, without regard to financing methods, historical cost basis or capital structure;
|
•
|
the ability of our assets to generate sufficient cash flow to make distributions to our partners;
|
•
|
our ability to incur and service debt and fund capital expenditures; and
|
•
|
the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.
|
•
|
the ability of our assets to generate cash sufficient to support our indebtedness and make future cash distributions to our unitholders; and
|
•
|
the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.
|
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
(in thousands)
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Net Income
|
|
$
|
30,282
|
|
|
$
|
29,752
|
|
|
$
|
63,987
|
|
|
$
|
62,992
|
|
Depreciation expense
|
|
5,443
|
|
|
5,675
|
|
|
11,299
|
|
|
11,346
|
|
||||
Interest expense
|
|
7,119
|
|
|
1,124
|
|
|
9,608
|
|
|
2,162
|
|
||||
EBITDA
|
|
42,844
|
|
|
36,551
|
|
|
84,894
|
|
|
76,500
|
|
||||
Non-cash unit-based compensation expense
|
|
690
|
|
|
367
|
|
|
1,269
|
|
|
650
|
|
||||
(Gain) Loss on asset sales
|
|
(254
|
)
|
|
3,241
|
|
|
2,501
|
|
|
3,914
|
|
||||
Adjusted EBITDA
|
|
43,280
|
|
|
40,159
|
|
|
88,664
|
|
|
81,064
|
|
||||
Less:
|
|
|
|
|
|
|
|
|
||||||||
Net income attributable to noncontrolling interest
|
|
277
|
|
|
761
|
|
|
6,135
|
|
|
3,934
|
|
||||
Depreciation expense attributable to noncontrolling interest
|
|
674
|
|
|
1,833
|
|
|
2,339
|
|
|
3,663
|
|
||||
Other expenses attributable to noncontrolling interest
|
|
1,224
|
|
|
112
|
|
|
1,660
|
|
|
194
|
|
||||
(Gain) Loss on asset sales attributable to noncontrolling interest
|
|
(242
|
)
|
|
3,079
|
|
|
2,375
|
|
|
3,718
|
|
||||
Adjusted EBITDA attributable to General and Limited Partner ownership interest in CNX Midstream Partners LP
|
|
$
|
41,347
|
|
|
$
|
34,374
|
|
|
$
|
76,155
|
|
|
$
|
69,555
|
|
Less: cash interest, net to the Partnership
|
|
5,573
|
|
|
1,079
|
|
|
7,588
|
|
|
2,079
|
|
||||
Less: maintenance capital expenditures, net to the Partnership
|
|
4,125
|
|
|
3,715
|
|
|
7,708
|
|
|
7,596
|
|
||||
Distributable Cash Flow
|
|
$
|
31,649
|
|
|
$
|
29,580
|
|
|
$
|
60,859
|
|
|
$
|
59,880
|
|
|
|
|
|
|
|
|
|
|
||||||||
Net Cash Provided by Operating Activities
|
|
$
|
53,674
|
|
|
$
|
42,258
|
|
|
$
|
95,541
|
|
|
$
|
76,434
|
|
Interest expense
|
|
7,119
|
|
|
1,124
|
|
|
9,608
|
|
|
2,162
|
|
||||
(Gain) Loss on asset sales
|
|
(254
|
)
|
|
3,241
|
|
|
2,501
|
|
|
3,914
|
|
||||
Other, including changes in working capital
|
|
(17,259
|
)
|
|
(6,464
|
)
|
|
(18,986
|
)
|
|
(1,446
|
)
|
||||
Adjusted EBITDA
|
|
43,280
|
|
|
40,159
|
|
|
88,664
|
|
|
81,064
|
|
||||
Less:
|
|
|
|
|
|
|
|
|
||||||||
Net income attributable to noncontrolling interest
|
|
277
|
|
|
761
|
|
|
6,135
|
|
|
3,934
|
|
||||
Depreciation expense attributable to noncontrolling interest
|
|
674
|
|
|
1,833
|
|
|
2,339
|
|
|
3,663
|
|
||||
Other expenses attributable to noncontrolling interest
|
|
1,224
|
|
|
112
|
|
|
1,660
|
|
|
194
|
|
||||
(Gain) Loss on asset sales attributable to noncontrolling interest
|
|
(242
|
)
|
|
3,079
|
|
|
2,375
|
|
|
3,718
|
|
||||
Adjusted EBITDA attributable to General and Limited Partner ownership interest in CNX Midstream Partners LP
|
|
$
|
41,347
|
|
|
$
|
34,374
|
|
|
$
|
76,155
|
|
|
$
|
69,555
|
|
Less: cash interest, net to the Partnership
|
|
5,573
|
|
|
1,079
|
|
|
7,588
|
|
|
2,079
|
|
||||
Less: maintenance capital expenditures, net to the Partnership
|
|
4,125
|
|
|
3,715
|
|
|
7,708
|
|
|
7,596
|
|
||||
Distributable Cash Flow
|
|
$
|
31,649
|
|
|
$
|
29,580
|
|
|
$
|
60,859
|
|
|
$
|
59,880
|
|
|
|
Six Months Ended June 30,
|
||||||||||
(in millions)
|
|
2018
|
|
2017
|
|
Change
|
||||||
Net cash provided by operating activities
|
|
$
|
95.5
|
|
|
$
|
76.4
|
|
|
$
|
19.1
|
|
Net cash used in investing activities
|
|
$
|
(35.1
|
)
|
|
$
|
(9.4
|
)
|
|
$
|
(25.7
|
)
|
Net cash used in financing activities
|
|
$
|
(62.9
|
)
|
|
$
|
(68.6
|
)
|
|
$
|
5.7
|
|
•
|
the base rate, which is the highest of (i) the federal funds open rate plus
0.50%
, (ii) PNC Bank, N.A.’s prime rate, and (iii) the one-month LIBOR rate plus
1.0%
, in each case, plus a margin ranging from
0.75%
to
1.75%
; or
|
•
|
the LIBOR rate, which is the LIBOR rate plus a margin ranging from
1.75%
to
2.75%
.
|
•
|
Maintenance capital expenditures
, which are cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long term, our operating capacity, operating income or revenue. Examples of maintenance capital expenditures are expenditures to repair, refurbish and replace pipelines, to maintain equipment reliability, integrity and safety and to comply with environmental laws and regulations. In addition, we designate a portion of our capital expenditures to connect new wells to maintain gathering throughput as maintenance capital to the extent such capital expenditures are necessary to maintain, over the long term, our operating capacity, operating income or revenue; or
|
•
|
Expansion capital expenditures
, which are cash expenditures to construct new midstream infrastructure and those expenditures incurred in order to extend the useful lives of our assets, reduce costs, increase revenues or increase system throughput or capacity from current levels, including well connections that increase existing system throughput. Examples of expansion capital expenditures include the construction, development or acquisition of additional gathering pipelines and compressor stations, in each case to the extent such capital expenditures are expected to expand our operating capacity, operating income or revenue. In the future, if we make acquisitions that increase system throughput or capacity, the associated capital expenditures may also be considered expansion capital expenditures.
|
|
Anchor
|
|
Growth
|
|
Additional
|
|
TOTAL
|
||||||||
Capital Investment
|
|
|
|
|
|
|
|
||||||||
Maintenance capital
|
$
|
8,033
|
|
|
$
|
218
|
|
|
$
|
1,115
|
|
|
$
|
9,366
|
|
Expansion capital
|
30,257
|
|
|
(98
|
)
|
|
2,062
|
|
|
32,221
|
|
||||
Total Capital Investment
|
$
|
38,290
|
|
|
$
|
120
|
|
|
$
|
3,177
|
|
|
$
|
41,587
|
|
|
|
|
|
|
|
|
|
||||||||
Capital Investment Net to the Partnership
|
|
|
|
|
|
|
|
||||||||
Maintenance capital
|
$
|
8,033
|
|
|
$
|
11
|
|
|
$
|
56
|
|
|
$
|
8,100
|
|
Expansion capital
|
30,257
|
|
|
(5
|
)
|
|
103
|
|
|
30,355
|
|
||||
Total Capital Investment Net to the Partnership
|
$
|
38,290
|
|
|
$
|
6
|
|
|
$
|
159
|
|
|
$
|
38,455
|
|
•
|
our reliance on our customers, including our Sponsor;
|
•
|
the effects of changes in market prices of natural gas, NGLs and crude oil on our customers’ drilling and development plans on our dedicated acreage and the volumes of natural gas and condensate that are produced on our dedicated acreage;
|
•
|
changes in our customers’ drilling and development plans in the Marcellus Shale and Utica Shale;
|
•
|
our customers’ ability to meet their drilling and development plans in the Marcellus Shale and Utica Shale;
|
•
|
the demand for natural gas and condensate gathering services;
|
•
|
changes in general economic conditions;
|
•
|
competitive conditions in our industry;
|
•
|
actions taken by third-party operators, gatherers, processors and transporters;
|
•
|
our ability to successfully implement our business plan;
|
•
|
our ability to complete internal growth projects on time and on budget;
|
•
|
the price and availability of debt and equity financing;
|
•
|
the availability and price of oil and natural gas to the consumer compared to the price of alternative and competing fuels;
|
•
|
competition from the same and alternative energy sources;
|
•
|
energy efficiency and technology trends;
|
•
|
operating hazards and other risks incidental to our midstream services;
|
•
|
natural disasters, weather-related delays, casualty losses and other matters beyond our control;
|
•
|
interest rates;
|
•
|
labor relations;
|
•
|
defaults by our customers under our gathering agreements;
|
•
|
changes in availability and cost of capital;
|
•
|
changes in our tax status;
|
•
|
the effect of existing and future laws and government regulations;
|
•
|
the effects of future litigation; and
|
•
|
certain factors discussed elsewhere in this report.
|
ITEM 3.
|
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|
ITEM 4.
|
CONTROLS AND PROCEDURES
|
ITEM 1.
|
LEGAL PROCEEDINGS
|
ITEM 6.
|
EXHIBITS
|
|
|
|
|
Incorporated by Reference
|
||||||
Exhibit
Number
|
|
Exhibit Description
|
|
Form
|
|
SEC File
Number |
|
Exhibit
|
|
Filing Date
|
10.1
†
|
|
|
|
|
|
|
|
|
|
|
10.2
†
|
|
|
|
|
|
|
|
|
|
|
10.3
†
|
|
|
|
|
|
|
|
|
|
|
31.1
†
|
|
|
|
|
|
|
|
|
|
|
31.2
†
|
|
|
|
|
|
|
|
|
|
|
32.1
‡
|
|
|
|
|
|
|
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32.2
‡
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101.INS
†
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XBRL Instance Document.
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101.SCH
†
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XBRL Taxonomy Extension Schema Document.
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101.CAL
†
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XBRL Taxonomy Extension Calculation Linkbase Document.
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101.DEF
†
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XBRL Taxonomy Extension Definition Linkbase Document.
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101.LAB
†
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XBRL Taxonomy Extension Labels Linkbase Document.
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101.PRE
†
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XBRL Taxonomy Extension Presentation Linkbase Document.
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CNX MIDSTREAM PARTNERS LP
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By:
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CNX MIDSTREAM GP, LLC, its general partner
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By:
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/S/ NICHOLAS J. DEIULIIS
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Nicholas J. DeIuliis
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Chief Executive Officer and Chairman of the Board
(Duly Authorized Officer and Principal Executive Officer)
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By:
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/
S
/ DONALD W. RUSH
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Donald W. Rush
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Chief Financial Officer and Director
(Duly Authorized Officer and Principal Financial Officer)
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By:
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/S/
BRIAN R. RICH
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Brian R. Rich
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Chief Accounting Officer
(Duly Authorized Officer and Principal Accounting Officer)
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1.
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New Definitions
. The following definitions shall be inserted into Section 1.1 of the Original Agreement in the appropriate place, accounting for alphabetical order:
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2.
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Revised Definitions
.
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(a)
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The definition of “Compression Services” in Section 1.1 of the Original Agreement shall be replaced in its entirety with the following:
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(b)
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The definition of “Condensate Services” in Section 1.1 of the Original Agreement shall be replaced in its entirety with the following:
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(c)
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The definition of “Dedicated Liquid Condensate” in Section 1.1 of the Original Agreement shall be replaced in its entirety with the following:
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3.
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Dedication of Shirley Penns Liquid Condensate
.
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(a)
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Sections 2.1(a) and 2.1(b) of the Original Agreement shall be replaced in their entireties with the following:
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(b)
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The last sentence of Section 3.7 of the Original Agreement shall be replaced in its entirety with the following:
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(c)
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The last sentence of Section 4.3 of the Original Agreement shall be replaced in its entirety with the following:
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(d)
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The last sentence of Section 5.1(b) of the Original Agreement shall be replaced in its entirety with the following:
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(e)
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The last sentence of Section 1.4(i) of Exhibit A to the Original Agreement shall be replaced in its entirety with the following:
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(f)
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Sections 1.8(c) and 1.8(d) of Exhibit A to the Original Agreement shall be replaced in their entireties with the following:
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4.
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Limitation on Dedication of Shirley Penns Liquid Condensate
. Section 2.4(f) of the Original Agreement shall be replaced in its entirety with the following:
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5.
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Shirley Penns Minimum Volume Commitment
. The following text shall be inserted immediately after Section 3.2(g) in the Original Agreement as Section 3.2(h):
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(i)
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For each Quarter during the Shirley Penns MVC Period, if at the end of any such Quarter, (A) the Quarterly Shirley Penns Gas Volume Commitment for such Quarter exceeds the Adjusted Quarterly Shirley Penns Gas Volume Deliveries for such Quarter (the amount of such excess, if any, the “
Shirley Penns Quarterly Gas Deficiency
” for such Quarter) and (B) aggregate Quarterly Shirley Penns Gas Volume Commitments for such Quarter and all prior Quarters since January 1, 2018 exceed the aggregate Adjusted Quarterly Shirley Penns Gas Volume Deliveries for such Quarter and all prior Quarters since January 1, 2018 (the amount of such excess, if any, the “
Shirley Penns Cumulative Gas Deficiency
” for such Quarter), Producer shall pay Gatherer an amount (the “
Shirley Penns Gas Deficiency Payment
” for such Quarter) equal to the product of (A) the lesser of the Shirley Penns Quarterly Gas Deficiency for such Quarter and the Shirley Penns Cumulative Gas Deficiency as of such Quarter and (B) the Gas Gathering Fee applicable during such Quarter for Gas Services provided for Dedicated Gas on the Shirley Penns System.
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(ii)
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Notwithstanding anything to the contrary herein, at the end of any Quarter during the Shirley Penns MVC Period, in the event that (A) there is a positive balance in the Shirley Penns Gas Deficiency Payment Bank and (B) the Adjusted Quarterly Shirley Penns Gas Volume Deliveries for such Quarter exceed the Quarterly Shirley Penns Gas Volume Commitment for such Quarter (the amount of such excess, if any, the “
Shirley Penns Gas Surplus
” for such Quarter), Producer shall be entitled to credit against amounts otherwise payable by Producer hereunder for each of the three Months after such Quarter an amount, in the aggregate, equal to the Shirley Penns Credit for such Month.
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6.
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Fee Adjustments for Failure to Provide Shirley Penns Pressure Service
. Section 5.2(c) of the Original Agreement shall be replaced in its entirety with the following:
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7.
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Shirley Penns Pressure Requirements
.
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(l)
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Shirley Penns Pressure Requirements
. Notwithstanding anything to the contrary herein, unless Gatherer is otherwise obligated to provide Tier 1 Pressure Service or Tier 2 Pressure Service, as applicable, at any Receipt Point on the Shirley Penns System, Gatherer shall provide Shirley Penns Pressure Service for the Receipt Points on the Shirley Penns System.
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8.
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Replacement of Exhibit B-13(a) (Shirley Penns Map)
. Exhibit B-13(a) to the Original Agreement shall be replaced in its entirety with Exhibit B-13(a) attached hereto.
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9.
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Replacement of Exhibit B-13(b) (Shirley Penns Fees)
. Exhibit B-13(b) to the Original Agreement shall be replaced in its entirety with Exhibit B-13(b) attached hereto.
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10.
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Addition of Exhibit B-13(c) (Shirley Penns Minimum Commitment Daily Volumes)
. Exhibit B-13(c) attached hereto shall be added to the Original Agreement.
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11.
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Replacement of Exhibit M (Initial Well Development Schedule)
. Exhibit M to the Original Agreement shall be replaced in its entirety with Exhibit M attached hereto.
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12.
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Replacement of Exhibit P (Compression Curves for Certain Systems)
. Exhibit P to the Original Agreement shall be replaced in its entirety with Exhibit P attached hereto.
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13.
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Replacement of Exhibit R-1 (DevCo I Area)
. Exhibit R-1 to the Original Agreement shall be replaced in its entirety with Exhibit R-1 attached hereto.
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14.
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Replacement of Exhibit R-3 (DevCo III Area)
. Exhibit R-3 to the Original Agreement shall be replaced in its entirety with Exhibit R-3 attached hereto.
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15.
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Original Agreement
. Except as modified herein, the Original Agreement remains in full force and effect in accordance with its terms.
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16.
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Incorporation of Certain Terms
. Capitalized terms used but not otherwise defined herein shall have the meanings ascribed to such terms in the Original Agreement. Sections 10.1 and 16.7 of the Original Agreement are incorporated by reference herein,
mutatis mutandis
.
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1.
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Certain Defined Terms
.
Section 1.1
of the Original Agreement is hereby amended to add the following defined terms, which shall be inserted in alphabetic order into the current definitions in Section 1.1 of the Original Agreement:
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2.
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Utica Option Area Planned Wells
. The following text shall be added as a new Section 3.1(i) immediately after Section 3.1(h) of the Original Agreement:
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3.
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Change to Minimum Well Commitment
.
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Majorsville/Mamont Minimum Well Period
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7/1/2018 to 12/31/2020
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1/1/2021 to 12/31/2023
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Majorsville/Mamont Minimum Well Requirement
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15
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25
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4.
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Change to Priority of Service
. Section 4.1(c) of the Original Agreement shall be replaced in its entirety with the following:
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5.
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Replacement of Exhibit B-1(a) (Dedication Area (Marcellus))
. Exhibit B-1(a) to the Original Agreement shall be replaced in its entirety with Exhibit B-1(a) attached hereto.
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6.
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Replacement of Exhibit B-1(b) (Dedication Area (Utica))
. Exhibit B-1(b) to the Original Agreement shall be replaced in its entirety with Exhibit B-1(b) attached hereto.
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7.
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Replacement of Exhibit B-3(b) (ACAA Fees)
. Exhibit B-3(b) to the Original Agreement shall be replaced in its entirety with Exhibit B-3(b) attached hereto.
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8.
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Replacement of Exhibit B-4 (Big Run Fees)
. Exhibit B-4 to the Original Agreement shall be replaced in its entirety with Exhibit B-4 attached hereto.
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9.
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Replacement of Exhibit B-5(b) (Crawford Fees)
. Exhibit B-5(b) to the Original Agreement shall be replaced in its entirety with Exhibit B-5(b) attached hereto.
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10.
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Replacement of Exhibit B-6(b) (Fallowfield Fees)
. Exhibit B-6(b) to the Original Agreement shall be replaced in its entirety with Exhibit B-6(b) attached hereto.
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11.
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Replacement of Exhibit B-7(b) (Majorsville Fees)
. Exhibit B-7(b) to the Original Agreement shall be replaced in its entirety with Exhibit B-7(b) attached hereto.
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12.
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Replacement of Exhibit B-8(b) (Mamont Fees)
. Exhibit B-8(b) to the Original Agreement shall be replaced in its entirety with Exhibit B-8(b) attached hereto.
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13.
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Replacement of Exhibit B-9 (Marchand Fees)
. Exhibit B-9 to the Original Agreement shall be replaced in its entirety with Exhibit B-9 attached hereto.
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14.
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Replacement of Exhibit B-10(b) (Marshall Fees)
. Exhibit B-10(b) to the Original Agreement shall be replaced in its entirety with Exhibit B-10(b) attached hereto.
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15.
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Replacement of Exhibit B-11(b) (McQuay Fees)
. Exhibit B-11(b) to the Original Agreement shall be replaced in its entirety with Exhibit B-11(b) attached hereto.
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16.
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Insertion of New Exhibit B-18 (Majorsville/Mamont Minimum Well Area)
. A new Exhibit B-18 shall be inserted into the Original Agreement immediately after Exhibit B-17 with Exhibit B-18 attached hereto.
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17.
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Replacement of Exhibit J-2 (Legacy Wells)
. Exhibit J-2 to the Original Agreement shall be replaced in its entirety with Exhibit J-2 attached hereto.
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18.
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Replacement of Exhibit P (Compression Curves for Certain Systems)
. Exhibit P to the Original Agreement shall be replaced in its entirety with Exhibit P attached hereto.
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19.
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Insertion of New Exhibit T (Majorsville/Mamont Surcharge Limitations)
. A new Exhibit T shall be inserted into the Original Agreement immediately after Exhibit S with Exhibit T attached hereto.
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20.
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Original Agreement
. Except as modified herein, the Original Agreement remains in full force and effect in accordance with its terms.
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21.
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Incorporation of Certain Terms
. Capitalized terms used but not otherwise defined herein shall have the meanings ascribed to such terms in the Original Agreement. Sections 10.1 and 16.7 of the Original Agreement are incorporated by reference herein,
mutatis mutandis
.
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Number of Wells included in Majorsville/Mamont Minimum Deficiency Obligation / receiving Majorsville/Mamont Credits
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Maximum Daily Quantity of Dedicated Gas Subject to Majorsville/Mamont Surcharge / Majorsville/Mamont Credit
(In BBtu/Day)
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1
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38
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2
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77
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3
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115
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4
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153
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5
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192
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6
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230
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7
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268
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8
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307
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9
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345
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10
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384
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11
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422
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12
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460
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13
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499
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14
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537
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15
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575
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16
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614
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17
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652
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18
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690
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19
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729
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20
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767
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21
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805
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22
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844
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23
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882
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24
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921
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25
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959
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By:
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CNX MIDSTREAM DEVCO I GP LLC
, its general partner
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By:
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CNX MIDSTREAM DEVCO II GP LLC
, its general partner
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By:
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CNX MIDSTREAM DEVCO III GP LLC
, its general partner
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1.
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I have reviewed this quarterly report on Form 10-Q of CNX Midstream Partners LP;
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2.
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Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
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3.
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Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
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4.
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The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
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(a)
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Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
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(b)
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Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
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(c)
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Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
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(d)
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Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
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5.
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The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
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(a)
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All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
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(b)
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Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
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Date:
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August 2, 2018
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/S/
Nicholas J. DeIuliis
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Nicholas J. DeIuliis
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Chief Executive Officer
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CNX Midstream GP LLC (the general partner of CNX Midstream Partners LP)
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(Principal Executive Officer)
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1.
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I have reviewed this quarterly report on Form 10-Q of CNX Midstream Partners LP;
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2.
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Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
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3.
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Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
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4.
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The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
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(a)
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Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
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(b)
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Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
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(c)
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Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
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(d)
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Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
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5.
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The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
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(a)
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All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
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(b)
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Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
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Date:
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August 2, 2018
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/S/
Donald W. Rush
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Donald W. Rush
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Chief Financial Officer
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CNX Midstream GP LLC (the general partner of CNX Midstream Partners LP)
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(Principal Financial Officer)
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Date:
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August 2, 2018
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/S/
Nicholas J. DeIuliis
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Nicholas J. DeIuliis
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Chief Executive Officer
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CNX Midstream GP LLC (the general partner of CNX Midstream Partners LP)
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(Principal Executive Officer)
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Date:
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August 2, 2018
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/S/
Donald W. Rush
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Donald W. Rush
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Chief Financial Officer
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CNX Midstream GP LLC (the general partner of CNX Midstream Partners LP)
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(Principal Financial Officer)
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