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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
☒QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended SeptemberJune 30, 20192020
OR
☐TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
Commission File Number 000-19514
Gulfport Energy CorporationCorporation
(Exact Name of Registrant As Specified in Its Charter)
Delaware
73-1521290
Delaware73-1521290
(State or Other Jurisdiction of Incorporation or Organization)(IRS Employer Identification Number)
3001 Quail Springs Parkway
Oklahoma City,Oklahoma73134
(Address of Principal Executive Offices)(Zip Code)
(405) (405) 252-4600
(Registrant 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, par value $0.01 per shareGPORNasdaq Global Select Market
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     Yes  ý    No  ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or such shorter period that the registrant was required to submit such files).     Yes  ý    No  ¨
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 definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated filerý¨     Accelerated filer   ¨ý   
Non-accelerated filer  ¨    Smaller reporting company  ☐
Emerging growth 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. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐    No  ý
As of October 25, 2019, 159,709,221July 31, 2020, 160,115,829 shares of the registrant’s common stock were outstanding.



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GULFPORT ENERGY CORPORATION
TABLE OF CONTENTS
 
Page
Page
PART I FINANCIAL INFORMATION
Item 1.
2
2
3
4
5
76
87
Item 2.
37
Item 3.
5059
Item 4.
5261
Item 1.
62
Item 1.1A.
5464
Item 1A.2.
55
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
5565
Item 3.
5666
Item 4.
5666
Item 5.
5667
Item 6.
5668
5870




1
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GULFPORT ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, 2020December 31, 2019
(Unaudited)
(In thousands, except share data)
Assets
Current assets:
Cash and cash equivalents$2,817  $6,060  
Accounts receivable—oil and natural gas sales65,645  121,210  
Accounts receivable—joint interest and other19,389  47,975  
Prepaid expenses and other current assets10,862  4,431  
Short-term derivative instruments53,188  126,201  
Total current assets151,901  305,877  
Property and equipment:
Oil and natural gas properties, full-cost accounting, $1,564,189 and $1,686,666 excluded from amortization in 2020 and 2019, respectively10,730,992  10,595,735  
Other property and equipment96,838  96,719  
Accumulated depletion, depreciation, amortization and impairment(8,457,464) (7,228,660) 
Property and equipment, net2,370,366  3,463,794  
Other assets:
Equity investments13,052  32,044  
Long-term derivative instruments4,298  563  
Deferred tax asset—  7,563  
Operating lease assets3,640  14,168  
Operating lease assets—related parties—  43,270  
Other assets37,000  15,540  
Total other assets57,990  113,148  
Total assets$2,580,257  $3,882,819  
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities$315,575  $415,218  
Short-term derivative instruments8,540  303  
Current portion of operating lease liabilities3,356  13,826  
Current portion of operating lease liabilities—related parties—  21,220  
Current maturities of long-term debt649  631  
Total current liabilities328,120  451,198  
Long-term derivative instruments45,615  53,135  
Asset retirement obligation61,371  60,355  
Uncertain tax position liability3,209  3,127  
Non-current operating lease liabilities284  342  
Non-current operating lease liabilities—related parties—  22,050  
Long-term debt, net of current maturities1,910,318  1,978,020  
Total liabilities2,348,917  2,568,227  
Commitments and contingencies (Note 9)
Preferred stock, $0.01 par value; 5.0 million shares authorized (30 thousand authorized as redeemable 12% cumulative preferred stock, Series A), and NaN issued and outstanding—  —  
Stockholders’ equity:
Common stock - $0.01 par value, 200.0 million shares authorized, 160.1 million issued and outstanding at June 30, 2020 and 159.7 million at December 31, 20191,601  1,597  
Paid-in capital4,211,062  4,207,554  
Accumulated other comprehensive loss(54,991) (46,833) 
Accumulated deficit(3,926,332) (2,847,726) 
Total stockholders’ equity231,340  1,314,592  
Total liabilities and stockholders’ equity$2,580,257  $3,882,819  
 September 30, 2019 December 31, 2018
 (In thousands, except share data)
Assets   
Current assets:   
Cash and cash equivalents$10,124
 $52,297
Accounts receivable—oil and natural gas sales112,657
 210,200
Accounts receivable—joint interest and other41,327
 22,497
Prepaid expenses and other current assets5,658
 10,017
Short-term derivative instruments134,571
 21,352
Total current assets304,337
 316,363
Property and equipment:   
Oil and natural gas properties, full-cost accounting, $2,814,334 and $2,873,037 excluded from amortization in 2019 and 2018, respectively10,551,713
 10,026,836
Other property and equipment96,233
 92,667
Accumulated depletion, depreciation, amortization and impairment(5,063,413) (4,640,098)
Property and equipment, net5,584,533
 5,479,405
Other assets:   
Equity investments73,962
 236,121
Long-term derivative instruments23,419
 —
Deferred tax asset205,853
 —
Inventories7,022
 5,344
Operating lease assets13,920
 —
Operating lease assets - related parties48,449
 —
Other assets11,653
 13,803
Total other assets384,278
 255,268
Total assets$6,273,148
 $6,051,036
Liabilities and Stockholders’ Equity   
Current liabilities:   
Accounts payable and accrued liabilities$439,019
 $518,380
Short-term derivative instruments429
 20,401
Current portion of operating lease liabilities12,848
 —
Current portion of operating lease liabilities - related parties21,017
 —
Current maturities of long-term debt622
 651
Total current liabilities473,935
 539,432
Long-term derivative instruments72,040
 13,992
Asset retirement obligation—long-term59,819
 79,952
Uncertain tax position liability3,127
 3,127
Non-current operating lease liabilities1,072
 —
Non-current operating lease liabilities - related parties27,432
 —
Long-term debt, net of current maturities2,076,569
 2,086,765
Total liabilities2,713,994
 2,723,268
Commitments and contingencies (Note 8)

 

Preferred stock, $0.01 par value; 5,000,000 shares authorized (30,000 authorized as redeemable 12% cumulative preferred stock, Series A), and none issued and outstanding—
 —
Stockholders’ equity:   
Common stock - $0.01 par value, 200,000,000 shares authorized, 159,709,221 issued and outstanding at September 30, 2019 and 162,986,045 at December 31, 20181,597
 1,630
Paid-in capital4,205,158
 4,227,532
Accumulated other comprehensive loss(50,679) (56,026)
Accumulated deficit(596,922) (845,368)
Total stockholders’ equity3,559,154
 3,327,768
Total liabilities and stockholders’ equity$6,273,148
 $6,051,036

See accompanying notes to consolidated financial statements.

2
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GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
 Three months ended June 30,Six months ended June 30,
2020201920202019
(In thousands)
REVENUES:
Natural gas sales$86,797  $225,257  $195,344  $501,273  
Oil and condensate sales8,390  36,910  31,541  69,392  
Natural gas liquid sales10,252  25,687  27,165  57,812  
Net gain on natural gas, oil and NGL derivatives26,971  171,140  125,237  151,095  
Total Revenues132,410  458,994  379,287  779,572  
OPERATING EXPENSES:
Lease operating expenses15,686  22,388  31,672  42,195  
Production taxes3,605  8,098  8,404  16,019  
Midstream gathering and processing expenses59,974  72,015  117,870  142,297  
Depreciation, depletion and amortization64,790  124,951  142,818  243,384  
Impairment of oil and natural gas properties532,880  —  1,086,225  —  
General and administrative expenses10,470  11,727  26,639  21,784  
Accretion expense755  1,359  1,496  2,426  
Total Operating Expenses688,160  240,538  1,415,124  468,105  
(LOSS) INCOME FROM OPERATIONS(555,750) 218,456  (1,035,837) 311,467  
OTHER EXPENSE (INCOME):
Interest expense32,366  36,418  65,356  72,039  
Interest income(78) (159) (230) (311) 
Gain on debt extinguishment(34,257) —  (49,579) —  
Loss from equity method investments, net45  125,582  10,834  121,309  
Other expense7,242  990  9,098  563  
Total Other Expense5,318  162,831  35,479  193,600  
(LOSS) INCOME BEFORE INCOME TAXES(561,068) 55,625  (1,071,316) 117,867  
Income Tax Expense (Benefit)—  (179,331) 7,290  (179,331) 
NET (LOSS) INCOME$(561,068) $234,956  $(1,078,606) $297,198  
NET (LOSS) INCOME PER COMMON SHARE:
Basic$(3.51) $1.47  $(6.75) $1.85  
Diluted$(3.51) $1.47  $(6.75) $1.84  
Weighted average common shares outstanding—Basic159,934  159,325  159,847  161,065  
Weighted average common shares outstanding—Diluted159,934  159,507  159,847  161,590  

 Three months ended September 30, Nine months ended September 30,
 2019 2018 2019 2018
 (In thousands, except share data)
Revenues:       
Natural gas sales$213,227
 $271,167
 $714,500
 $753,261
Oil and condensate sales24,550
 45,682
 93,942
 140,687
Natural gas liquid sales20,324
 53,776
 78,136
 141,883
Net gain (loss) on natural gas, oil and NGLs derivatives27,074
 (9,663) 178,169
 (96,737)
 285,175
 360,962
 1,064,747
 939,094
Costs and expenses:
      
Lease operating expenses22,473
 22,325
 64,668
 64,143
Production taxes6,565
 9,348
 22,584
 23,861
Midstream gathering and processing expenses78,435
 78,913
 220,732
 214,546
Depreciation, depletion and amortization145,490
 119,915
 388,874
 352,848
Impairment of oil and natural gas properties35,647
 —
 35,647
 —
General and administrative expenses14,659
 15,848
 39,482
 42,955
Accretion expense747
 1,037
 3,173
 3,056
 304,016
 247,386
 775,160
 701,409
(LOSS) INCOME FROM OPERATIONS(18,841) 113,576
 289,587
 237,685
OTHER EXPENSE (INCOME):
      
Interest expense34,095
 33,253
 103,095
 100,922
Interest income(338) (92) (649) (162)
Gain on debt extinguishment(23,600) —
 (23,600) —
Gain on sale of equity method investments—
 (2,733) —
 (124,768)
Loss (income) from equity method investments, net43,082
 (12,858) 164,391
 (35,282)
Other expense3,194
 856
 3,757
 485
 56,433
 18,426
 246,994
 (58,805)
(LOSS) INCOME BEFORE INCOME TAXES(75,274) 95,150
 42,593
 296,490
INCOME TAX BENEFIT(26,522) —
 (205,853) (69)
NET (LOSS) INCOME$(48,752) $95,150
 $248,446
 $296,559
NET (LOSS) INCOME PER COMMON SHARE:       
Basic$(0.31) $0.55
 $1.55
 $1.69
Diluted$(0.31) $0.55
 $1.51
 $1.68
Weighted average common shares outstanding—Basic159,548,477
 173,057,538
 160,553,796
 175,776,312
Weighted average common shares outstanding—Diluted159,548,477
 173,304,914
 164,820,002
 176,440,461

See accompanying notes to consolidated financial statements.


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GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME
(Unaudited)
Three months ended September 30, Nine months ended September 30, Three months ended June 30,Six months ended June 30,
2019 2018 2019 20182020201920202019
(In thousands)(In thousands)
Net (loss) income$(48,752) $95,150
 $248,446
 $296,559
Net (loss) income$(561,068) $234,956  $(1,078,606) $297,198  
Foreign currency translation adjustment(2,064) 3,052
 5,347
 (5,815)Foreign currency translation adjustment6,872  3,610  (8,158) 7,411  
Other comprehensive (loss) income(2,064) 3,052
 5,347
 (5,815)
Other comprehensive income (loss)Other comprehensive income (loss)6,872  3,610  (8,158) 7,411  
Comprehensive (loss) income$(50,816) $98,202
 $253,793
 $290,744
Comprehensive (loss) income$(554,196) $238,566  $(1,086,764) $304,609  


See accompanying notes to consolidated financial statements.


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GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(Unaudited)


Paid-in
Capital		Accumulated
Other
Comprehensive (Loss) Income		Accumulated
Deficit		Total
Stockholders’
Equity
Common Stock
 SharesAmount
(In thousands)
Balance at January 1, 2020159,711  $1,597  $4,207,554  $(46,833) $(2,847,726) $1,314,592  
Net Loss—  —  —  —  (517,538) (517,538) 
Other Comprehensive Loss—  —  —  (15,030) —  (15,030) 
Stock Compensation—  —  2,104  —  —  2,104  
Shares Repurchased(80) (1) (78) —  —  (79) 
Issuance of Restricted Stock211  2  (2) —  —  —  
Balance at March 31, 2020159,842  $1,598  $4,209,578  $(61,863) $(3,365,264) $784,049  
Net Loss—  —  —  —  (561,068) (561,068) 
Other Comprehensive Income—  —  —  6,872  —  6,872  
Stock Compensation—  —  1,515  —  —  1,515  
Shares Repurchased(27) —  (28) —  —  (28) 
Issuance of Restricted Stock301  3  (3) —  —  —  
Balance at June 30, 2020160,116  $1,601  $4,211,062  $(54,991) $(3,926,332) $231,340  

    

Paid-in
Capital
 
Accumulated
Other
Comprehensive (Loss) Income
 
Accumulated
Deficit
 
Total
Stockholders’
Equity

Paid-in
Capital		Accumulated
Other
Comprehensive (Loss) Income		Accumulated
Deficit		Total
Stockholders’
Equity
Common Stock Common Stock
Shares Amount  SharesAmount
(In thousands, except share data)(In thousands)
Balance at January 1, 2019162,986,045
 $1,630
 $4,227,532
 $(56,026) $(845,368) $3,327,768
Balance at January 1, 2019162,986  $1,630  $4,227,532  $(56,026) $(845,368) $3,327,768  
Net Income—
 —
 —
 —
 62,242
 62,242
Net Income—  —  —  —  62,242  62,242  
Other Comprehensive Income—
 —
 —
 3,801
 —
 3,801
Other Comprehensive Income—  —  —  3,801  —  3,801  
Stock Compensation—
 —
 2,785
 —
 —
 2,785
Stock Compensation—  —  2,785  —  —  2,785  
Shares Repurchased(3,618,634) (37) (28,293) —
 —
 (28,330)Shares Repurchased(3,619) (37) (28,293) —  —  (28,330) 
Issuance of Restricted Stock54,554
 1
 (1) —
 —
 —
Issuance of Restricted Stock55  1  (1) —  —  —  
Balance at March 31, 2019159,421,965
 $1,594
 $4,202,023
 $(52,225) $(783,126) $3,368,266
Balance at March 31, 2019159,422  $1,594  $4,202,023  $(52,225) $(783,126) $3,368,266  
Net Income—
 —
 —
 —
 234,956
 234,956
Net Income—  —  —  —  234,956  234,956  
Other Comprehensive Income—
 —
 —
 3,610
 —
 3,610
Other Comprehensive Income—  —  —  3,610  —  3,610  
Stock Compensation—
 —
 2,846
 —
 —
 2,846
Stock Compensation—  —  2,846  —  —  2,846  
Shares Repurchased(296,587) (3) (2,267) —
 —
 (2,270)Shares Repurchased(297) (3) (2,267) —  —  (2,270) 
Issuance of Restricted Stock270,639
 3
 (3) —
 —
 —
Issuance of Restricted Stock271  3  (3) —  —  —  
Balance at June 30, 2019159,396,017
 $1,594
 $4,202,599
 $(48,615) $(548,170) $3,607,408
Balance at June 30, 2019159,396  $1,594  $4,202,599  $(48,615) $(548,170) $3,607,408  
Net Loss—
 —
 —
 —
 (48,752) (48,752)
Other Comprehensive Loss—
 —
 —
 (2,064) —
 (2,064)
Stock Compensation—
 —
 2,651
 —
 —
 2,651
Shares Repurchased(35,977) —
 (89) —
 —
 (89)
Issuance of Restricted Stock349,181
 3
 (3) —
 —
 —
Balance at September 30, 2019159,709,221
 $1,597
 $4,205,158
 $(50,679) $(596,922) $3,559,154
(Continued on next page)

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GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (continued)
(Unaudited)

     

Paid-in
Capital
 
Accumulated
Other
Comprehensive (Loss) Income
 
Accumulated
Deficit
 
Total
Stockholders’
Equity
 Common Stock    
 Shares Amount    
 (In thousands, except share data)
Balance at January 1, 2018183,105,910
 $1,831
 $4,416,250
 $(40,539) $(1,275,928) $3,101,614
Net Income—
 —
 —
 —
 90,090
 90,090
Other Comprehensive Loss—
 —
 —
 (5,503) —
 (5,503)
Stock Compensation—
 —
 2,685
 —
 —
 2,685
Shares Repurchased(9,692,356) (97) (99,900) —
 —
 (99,997)
Issuance of Restricted Stock109,933
 1
 (1) —
 —
 —
Balance at March 31, 2018173,523,487
 $1,735
 $4,319,034
 $(46,042) $(1,185,838) $3,088,889
Net Income—
 —
 —
 —
 111,319
 111,319
Other Comprehensive Loss—
 —
 —
 (3,364) —
 (3,364)
Stock Compensation—
 —
 3,355
 —
 —
 3,355
Shares Repurchased(412,516) (4) (4,996) —
 —
 (5,000)
Issuance of Restricted Stock191,084
 2
 (2) —
 —
 —
Balance at June 30, 2018173,302,055
 $1,733
 $4,317,391
 $(49,406) $(1,074,519) $3,195,199
Net Income—
 —
 —
 —
 95,150
 95,150
Other Comprehensive Income—
 —
 —
 3,052
 —
 3,052
Stock Compensation—
 —
 3,614
 —
 —
 3,614
Shares Repurchased(400,597) (4) (4,996) —
 —
 (5,000)
Issuance of Restricted Stock317,185
 3
 (3) —
 —
 —
Balance at September 30, 2018173,218,643
 $1,732
 $4,316,006
 $(46,354) $(979,369) $3,292,015

See accompanying notes to consolidated financial statements.

5
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GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine months ended September 30, Six months ended June 30,
2019 201820202019
(In thousands)(In thousands)
Cash flows from operating activities:   Cash flows from operating activities:
Net income$248,446
 $296,559
Adjustments to reconcile net income to net cash provided by operating activities:   
Accretion expense3,173
 3,056
Net (loss) incomeNet (loss) income$(1,078,606) $297,198  
Adjustments to reconcile net (loss) income to net cash provided by operating activities:Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depletion, depreciation and amortization388,874
 352,848
Depletion, depreciation and amortization142,818  243,384  
Impairment of oil and natural gas properties35,647
 —
Impairment of oil and natural gas properties1,086,225  —  
Stock-based compensation expense4,969
 5,792
Loss (income) from equity investments164,532
 (35,040)Loss (income) from equity investments10,834  121,449  
Gain on debt extinguishment(23,600) —
Gain on debt extinguishment(49,579) —  
Change in fair value of derivative instruments(97,425) 106,373
Deferred income tax benefit(205,853) (69)
Amortization of loan costs4,821
 4,554
Gain on sale of equity investments and other assets(178) (124,768)
Distributions from equity method investments2,457
 1,978
Net gain on derivative instrumentsNet gain on derivative instruments(125,237) (151,095) 
Net cash receipts (payments) on settled derivative instrumentsNet cash receipts (payments) on settled derivative instruments195,232  (1,494) 
Deferred income tax expenseDeferred income tax expense7,290  (179,331) 
Other, netOther, net9,844  11,341  
Changes in operating assets and liabilities:   Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable—oil and natural gas sales97,543
 (10,618)
Increase in accounts receivable—joint interest and other(18,830) (2,277)
Increase in accounts receivable—related parties—
 (79)
Decrease (increase) in prepaid expenses and other current assets4,359
 (4,830)
(Increase) decrease in other assets(30) 1,228
Increase in accounts payable, accrued liabilities and other8,567
 36,809
Settlement of asset retirement obligation(117) (719)
Decrease in accounts receivable—oil and natural gas salesDecrease in accounts receivable—oil and natural gas sales55,565  78,525  
Decrease (increase) in accounts receivable—joint interest and otherDecrease (increase) in accounts receivable—joint interest and other29,159  (24,148) 
(Decrease) increase in accounts payable and accrued liabilities(Decrease) increase in accounts payable and accrued liabilities(30,620) 3,220  
Other, netOther, net(5,703) 720  
Net cash provided by operating activities617,355
 630,797
Net cash provided by operating activities247,222  399,769  
Cash flows from investing activities:   Cash flows from investing activities:
Additions to other property and equipment(4,694) (7,134)
Additions to oil and natural gas properties(646,535) (777,104)Additions to oil and natural gas properties(274,851) (508,315) 
Proceeds from sale of oil and natural gas properties10,864
 4,820
Proceeds from sale of oil and natural gas properties45,185  745  
Additions to other property and equipmentAdditions to other property and equipment(575) (4,298) 
Proceeds from sale of other property and equipment204
 217
Proceeds from sale of other property and equipment151  130  
Proceeds from sale of equity method investments—
 226,487
Contributions to equity method investments(432) (2,318)Contributions to equity method investments—  (432) 
Distributions from equity method investments1,945
 446
Distributions from equity method investments—  1,945  
Net cash used in investing activities(638,648) (554,586)Net cash used in investing activities(230,090) (510,225) 
Cash flows from financing activities:   Cash flows from financing activities:
Principal payments on borrowings(550,500) (165,428)Principal payments on borrowings(323,322) (345,350) 
Borrowings on line of credit640,000
 225,000
Borrowings on line of credit326,000  455,000  
Repurchase of senior notes(79,480) —
Debt issuance costs and loan commitment fees(211) (772)
Payments for repurchase of stock(30,689) (109,997)
Net cash used in financing activities(20,880) (51,197)
Net (decrease) increase in cash, cash equivalents and restricted cash(42,173) 25,014
Repurchases of senior notesRepurchases of senior notes(22,827) —  
Payments for repurchases of stock under approved stock repurchase programPayments for repurchases of stock under approved stock repurchase program—  (30,000) 
Other, netOther, net(226) (714) 
Net cash (used in) provided by financing activitiesNet cash (used in) provided by financing activities(20,375) 78,936  
Net decrease in cash, cash equivalents and restricted cashNet decrease in cash, cash equivalents and restricted cash(3,243) (31,520) 
Cash, cash equivalents and restricted cash at beginning of period52,297
 99,557
Cash, cash equivalents and restricted cash at beginning of period6,060  52,297  
Cash, cash equivalents and restricted cash at end of period$10,124
 $124,571
Cash, cash equivalents and restricted cash at end of period$2,817  $20,777  
Supplemental disclosure of cash flow information:   Supplemental disclosure of cash flow information:
Interest payments$85,272
 $75,045
Interest payments$60,523  $67,472  
Income tax receipts$(1,794) $—
Income tax receipts$—  $(1,794) 
Supplemental disclosure of non-cash transactions:   Supplemental disclosure of non-cash transactions:
Capitalized stock-based compensation$3,313
 $3,862
Capitalized stock-based compensation$1,891  $2,252  
Asset retirement obligation capitalized$6,846
 $1,094
Asset retirement obligation capitalized$1,553  $6,230  
Asset retirement obligation removed due to divestiture$(30,035) $—
Asset retirement obligation removed due to divestiture$(2,033) $—  
Interest capitalized$2,782
 $3,956
Interest capitalized$710  $1,771  
Fair value of contingent consideration asset on date of divestiture$(1,137) $—
Fair value of contingent consideration asset on date of divestiture$23,090  $—  
Foreign currency translation gain (loss) on equity method investments$5,347
 $(5,815)
Foreign currency translation (loss) gain on equity method investmentsForeign currency translation (loss) gain on equity method investments$(8,158) $7,411  
 See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1.BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
1.BASIS OF PRESENTATION, SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND LIQUIDITY, MANAGEMENT'S PLANS AND GOING CONCERN
Basis of Presentation
TheseThe accompanying unaudited consolidated financial statements have been prepared by Gulfport Energy Corporation (the “Company” or “Gulfport”) without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”), and reflect all adjustments that, in the opinion of management, are necessary for a fair presentation of the results for the interim periods reported in all material respects, on a basis consistent with the annual audited consolidated financial statements. All such adjustments are of a normal, recurring nature. Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles ("GAAP") have been omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. These
The consolidated financial statements should be read in conjunction with the consolidated financial statements and the summary of significant accounting policies and notes included in the Company’s most recent annual report on Form 10-K. Results for the three and ninesix months ended SeptemberJune 30, 20192020 are not necessarily indicative of the results expected for the full year.
StatementsCOVID-19
In March 2020, the World Health Organization classified the outbreak of Cash FlowsCOVID-19 as a pandemic and recommended containment and mitigation measures worldwide. The measures have led to worldwide shutdowns and halting of commercial and interpersonal activity, as governments around the world have imposed regulations in efforts to control the spread of COVID-19 such as shelter-in-place orders, quarantines, executive orders and similar restrictions.
Gulfport remains focused on protecting the health and well-being of its employees and the communities in which it operates while assuring the continuity of its business operations. The Company implemented preventative measures and developed corporate and field response plans to minimize unnecessary risk of exposure and prevent infection. Additionally, the Company has a crisis management team for health, safety and environmental matters and personnel issues, and has established a COVID-19 Response Team to address various impacts of the situation, as they have been developing. Gulfport has modified certain business practices (including remote working for its corporate employees and restricted employee business travel) to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, the World Health Organization and other governmental and regulatory authorities. In May 2020, the Company began its phased transition back to the office for its corporate employees. As part of this transition, the Company put into place preventative measures to focus on social distancing and minimizing unnecessary risk of exposure. As of the date of this filing, Gulfport has transitioned approximately 60% of its corporate employees back to the corporate office. The Company will continue to monitor trends and governmental guidelines and may adjust its return to office plans accordingly to ensure the health and safety of its employees. As a result of its business continuity measures, the Company has not experienced significant disruptions in executing its business operations in 2020.
Gulfport is closely monitoring the impact of COVID-19 on all aspects of its business and the current commodity price environment and is unable to predict the impact it will have on its future financial position or operating results. In response to the current commodity price environment, the Company voluntarily shut-in a portion of its production during the second quarter of 2020 and announced tiered salary reduction for most employees, senior management team and the Board of Directors beginning in June 2020 with such measures expected to last through December 2020. Additionally, select furloughs were implemented to reduce costs and preserve liquidity.
On March 27, 2020, the U.S. government enacted the Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”). The CARES Act did not have a material impact on the Company’s consolidated financial statements.
Liquidity, Management's Plans and Going Concern
As noted above, decreased demand for oil and natural gas as a result of the COVID-19 pandemic and the accompanying decrease in commodity prices has significantly impaired the Company's ability to access capital markets and to refinance its
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existing indebtedness. Further, these conditions have made amendments or waivers to its revolving credit facility more difficult to obtain and available on terms less favorable to the Company. If depressed commodity prices persist or decline further, the borrowing base under the Company's revolving credit facility could be further reduced at its next scheduled redetermination date in November 2020. Any such reduction would constrain the Company's liquidity and may impair its ability to fund its planned capital expenditures and meet its obligations under its existing indebtedness. Further, a reduction in the Company's capital expenditures would decrease its production, revenues, operating cash flow and EBITDA, which could limit its ability to comply with the restrictive covenants in its revolving credit facility and other existing indebtedness. Finally, the Company's existing revolving credit facility matures in December 2021 and therefore will become a current liability at year end 2020 unless the Company is able to refinance the credit facility with a new credit facility or other financing. Considering the current state of the first lien market and the Company's elevated leverage profile, there is substantial risk that a refinancing will not be available to the Company on reasonable terms. A current liability under the revolving credit facility at year end 2020 may result in a qualified audit opinion which could result in a default under the terms of the current revolving credit facility. As a result of these uncertainties and other factors, management has concluded that there is substantial doubt about the Company's ability to continue as a going concern. Failure to meet the Company's obligations under its existing indebtedness or failure to comply with any of its covenants, if not waived, would result in an event of default under such indebtedness and result in the potential acceleration of outstanding indebtedness thereunder and, with respect to the revolving credit facility, the potential foreclosure on the collateral securing such debt, and could cause a cross-default under its other outstanding indebtedness.

In the current depressed commodity price environment and period of economic uncertainty, the Company has taken various steps over the last several months to improve its balance sheet and preserve liquidity including (1) exercising capital discipline by reducing 2020 capital spending by 50% as compared to 2019, (2) focusing on operational efficiencies to reduce operating costs as evidenced by the recent reductions in Development and Completion costs per lateral foot, (3) reducing corporate general and administrative costs significantly, (4) and repurchasing unsecured notes at a deep discount.

Although management’s actions listed above have helped to improve our liquidity and leverage profile, continued macro headwinds including the depressed state of energy capital markets and the extraordinarily low commodity price environments present significant risks to the Company's ability to fund its operations going forward. Accordingly, management has determined there is substantial doubt about its ability to continue as a going concern over the next twelve months from the issuance of these financial statements. The Company has engaged financial and legal advisors to assist with the evaluation of a range of liability management alternatives. Additionally, the Company maintains an active dialogue with its senior lenders and bondholders regarding liability management alternatives to improve its balance sheet. There can be no assurances that the Company will be able to successfully complete a liability management transaction that materially improves the Company’s leverage profile or liquidity position.

The consolidated financial statements (i) have been prepared on a going concern basis, which contemplates the realization of assets and satisfaction of liabilities and other commitments in the normal course of business and (ii) do not include any adjustments to reflect the possible future effects of the uncertainty on the recoverability or classification of recorded asset amounts or the amounts or classifications of liabilities.

Impact on Previously Reported Results
During the third quarter of 2019, the Company identified that certain activities were misclassified between cash flows from operating activities and cash flows from investing activities. These activities had been included in accounts payable, accrued liabilities and other and presented as cash flows from operating activities while they should have been presented as additions to oil and natural gas properties in cash flows from investing activities.  The Company corrected the previously presented statements of cash flows for these additions and in doing so, for the ninesix months ended SeptemberJune 30, 2018,2019 contained herein, the consolidated statements of cash flows and the condensed consolidating statements of cash flows were adjusted to increase net cash flows provided by operating activities by $21.8$90.8 million with a corresponding increase in net cash flows used in investing activities. The Company has evaluated the effect of the incorrectprevious presentation, both qualitatively and quantitatively, and concluded that it did not have a material impact on any previously filed annual or quarterly consolidated financial statements.
Recently IssuedAdopted Accounting PronouncementsStandards
In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-02, Leases (Topic 842). The standard supersedes the previous lease guidance by requiring lessees to recognize a right-to-use asset and lease liability on the balance sheet for all leases with lease terms of greater than one year while maintaining substantially similar classifications for financing and operating leases. Subsequent to ASU 2016-02, the FASB issued several related ASU’s to clarify the application of the lease standard. The Company adopted the new standard as ofOn January 1, 2019 on a prospective basis using2020, the simplified transition method permitted by ASU 2018-11, Leases (Topic 842): Targeted Improvements. The comparative information has not been restated and continues to be reported under the historic accounting standards in effect for those periods. See Note 13 for further discussion of the lease standard.
In June 2016, the FASB issuedCompany adopted ASU No. 2016-13, Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Instruments. This ASU amends guidance on reporting, which replaces the incurred loss impairment methodology with a methodology that reflects expected credit losses for assets held at amortized cost basis and available for sale debt securities. For assets held at amortized cost basis, this ASU eliminates the probable initial recognition threshold in current GAAPrequires consideration of a broader range of reasonable and instead, requires an entitysupportable information to reflect its current estimateinform credit loss estimates. The measurement of all expected credit losses. The amendmentslosses is based on relevant information about past events, including historical experience, current conditions and reasonable and supportable forecasts that affect loans, debt securities, trade receivables, net investments in leases, off balance sheet credit exposure, reinsurance receivables and any other financial assets not excluded from the scope that havecollectibility of the contractual right to receive cash. Additionally, in May 2019, the FASB issued ASU No. 2019-05,
8
Financial Instruments—Credit Losses (Topic 326): Targeted Transition Relief. The amendments in this update allow preparers to irrevocably elect the fair value option, on an instrument-by-instrument basis, for eligible financial assets measured at amortized cost basis upon adoptionTable of 2016-13. The guidance is effective for periods after December 15, 2019, with early adoption permitted.Contents

reported amount. The Company is in the process of designing processes and controls needed to comply with the requirements ofadopted the new standard. Althoughstandard using the standard will have an impact, the Company doesprospective transition method, and it did not currently anticipate the ASU to have a material effectimpact on itsthe Company's consolidated financial statements and related disclosures.


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In August 2018, the FASB issued ASU No. 2018-13, 2.Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement, which removes, modifies, and adds certain disclosure requirements on fair value measurements. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company does not anticipate the new standard to have a material effect on its consolidated financial statements and related disclosures.PROPERTY AND EQUIPMENT
In August 2018, the FASB also issued ASU No. 2018-15, Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, which aligns the accounting for costs associated with implementing a cloud computing arrangement in a hosting arrangement that is a service contract with the accounting for implementation costs incurred to develop or obtain internal-use software. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company does not anticipate the new standard to have a material effect on its consolidated financial statements and related disclosures.
In November 2018, the FASB issued ASU No. 2018-18, Collaborative Arrangements (Topic 808): Clarifying the Interaction Between Topic 808 and Topic 606, which provides guidance on how to assess whether certain transactions between participants in a collaborative arrangement should be accounted for within the ASU No. 2014-09 revenue recognition standard discussed above. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company does not anticipate the new standard to have a material effect on its consolidated financial statements and related disclosures.
In July 2019, the FASB issued ASU No. 2019-07, Codification Updates to SEC Sections, Amendments to SEC Paragraphs Pursuant to SEC Final Rule Releases No. 33-10532, Disclosure Update and Simplification, and Nos. 33-10231 and 33-10442, Investment Company Reporting Modernization, and Miscellaneous Updates. This ASU amends various SEC sections within the FASB Codification to align with the updated requirements of certain SEC final rules and includes miscellaneous updates to agree the language in the Codification to the electronic Code of Federal Regulations. ASU No. 2019-07 is effective upon issuance, and the Company has adopted the changes with no material impacts.
2.PROPERTY AND EQUIPMENT
The major categories of property and equipment and related accumulated depletion, depreciation, amortization ("DD&A") and impairment as of SeptemberJune 30, 20192020 and December 31, 20182019 are as follows:
June 30, 2020December 31, 2019
(In thousands)
Oil and natural gas properties$10,730,992  $10,595,735  
Accumulated DD&A and impairment(8,415,756) (7,191,957) 
Oil and natural gas properties, net2,315,236  3,403,778  
Other depreciable property and equipment91,317  91,198  
Land5,521  5,521  
Accumulated DD&A(41,708) (36,703) 
Other property and equipment, net55,130  60,016  
Property and equipment, net$2,370,366  $3,463,794  
 September 30, 2019 December 31, 2018
 (In thousands)
Oil and natural gas properties$10,551,713
 $10,026,836
Other depreciable property and equipment90,712
 87,146
Land5,521
 5,521
Total property and equipment10,647,946
 10,119,503
Accumulated depletion, depreciation, amortization and impairment(5,063,413) (4,640,098)
Property and equipment, net$5,584,533
 $5,479,405


Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the Company's oil and natural gas properties. At SeptemberJune 30, 2019,2020, the net book value of the Company's oil and gas properties, less related deferred income taxes, was above the calculated ceiling primarily as a result of reduced commodity prices for the period leading up to SeptemberJune 30, 2019.2020. As a result, the Company was required to record an impairmentimpairments of its oil and natural gas properties under the full cost method of accounting in the amount of $35.6$532.9 million and $1.1 billion for the three and ninesix months ended SeptemberJune 30, 2019.2020, respectively. NaN impairment wasimpairments were required for oil and natural gas properties for the three and six months ended June 30, 2019.
Based on prices for the last nine months ended September 30, 2018. Additionaland the short-term pricing outlook for the third quarter of 2020, the Company expects to recognize additional full cost impairments in the third quarter of oil and natural gas properties are expected to occur in upcoming quarters should commodity prices continue below the average of the previous 12 months. However, the2020. The amount of any future impairments is difficult to predict as it depends on changes infuture commodity prices, production rates, proved reserves, evaluation of costs excluded from amortization, future development costs and production costs.
Included in oil and natural gas properties at September 30, 2019 is the cumulative capitalization of $229.6 million in general and administrative costs incurred and capitalized Any future full cost impairments are not expected to have an impact to the full cost pool. Company's future cash flows or liquidity.
General and administrative costs capitalized to

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the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing exploration and development activities. All general and administrative costs not directly associated with exploration and development activities wereare charged to expense as they wereare incurred. Capitalized general and administrative costs were approximately $9.8$8.2 million and $26.3 million for the three and nine months ended September 30, 2019, respectively, and $10.6 million and $28.8$13.6 million for the three and ninesix months ended SeptemberJune 30, 2018,2020, respectively, and $8.8 million and $16.5 million for the three and six months ended June 30, 2019, respectively.
The average depletion rate per Mcfe, which is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented, was $1.01$0.73 and $0.94$1.00 per Mcfe for the ninesix months ended SeptemberJune 30, 20192020 and 2018,2019, respectively.
The following table summarizes the Company’s non-producingunevaluated properties excluded from amortization by area at SeptemberJune 30, 2019:2020:
June 30, 2020
(In thousands)
Utica$874,886 
MidContinent687,169 
Other2,134 
$1,564,189 
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 September 30, 2019
 (In thousands)
Utica$1,464,803
MidContinent1,349,191
Other340
 $2,814,334

At December 31, 2018,2019, approximately $2.9$1.7 billion of non-producing leasehold costs wasunevaluated properties were not subject to amortization.
The Company evaluates the costs excluded from its amortization calculation at least annually. SubjectIndividually insignificant unevaluated properties are grouped for evaluation and periodically transferred to industry conditions and the level of the Company’s activities, the inclusion of most of the above referenced costs into the Company’s amortization calculation typically occurs within three to five years. However, the majority of the Company’s non-producing leases in the Utica Shale have five-year extension terms which could extend this time frame beyond five years.
Divestitures
In December of 2018, the Company entered into an agreement to sell its non-core assets located in the West Cote Blanche Bay ("WCBB") and Hackberry fields of Louisiana to an undisclosed third party forevaluated properties over a purchase price of approximately $19.7 million. The sale closed on July 3, 2019, subject to customary post-closing terms and conditions,timeframe consistent with an effective date of August 15, 2018. The Company received approximately $9.2 million in cash and retained contingent overriding royalty interests. In addition, the Company could also receive contingent payments based on commodity prices exceeding specified thresholds over the two years following the closing date. See Note 9 for further discussion of the contingent consideration arrangement, which was determined to be an embedded derivative. The buyer assumed all plugging and abandonment liabilities associated with these assets which totaled approximately $30.0 million at the divestiture date.their expected development schedule.

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Asset Retirement Obligation
A reconciliation of the Company’s asset retirement obligation for the ninesix months ended SeptemberJune 30, 20192020 and 20182019 is as follows:
September 30, 2019 September 30, 2018June 30, 2020June 30, 2019
(In thousands)(In thousands)
Asset retirement obligation, beginning of period$79,952
 $75,100
Asset retirement obligation, beginning of period$60,355  $79,952  
Liabilities incurred5,769
 1,468
Liabilities incurred1,553  5,153  
Liabilities settled(117) (719)Liabilities settled—  (117) 
Liabilities removed due to divestitures(30,035) —
Liabilities removed due to divestitures(2,033) —  
Accretion expense3,173
 3,056
Accretion expense1,496  2,426  
Revisions in estimated cash flows1,077
 (374)Revisions in estimated cash flows—  1,077  
Asset retirement obligation as of end of period59,819
 78,531
Asset retirement obligation as of end of period61,371  88,491  
Less current portion—
 120
Asset retirement obligation, long-term$59,819
 $78,411

3.EQUITY INVESTMENTS
3.DIVESTITURES
Sale of Water Infrastructure Assets
On January 2, 2020, the Company closed on the sale of its SCOOP water infrastructure assets to a third-party water service provider. The Company received $50.0 million in cash proceeds upon closing and has an opportunity to earn potential additional incentive payments over the next 15 years, subject to the Company's ability to meet certain thresholds which will be driven by, among other things, the Company's future development program and water production levels. The agreement contained no minimum volume commitments. The fair value of the contingent consideration as of the closing date was $23.1 million. The divested assets were included in the amortization base of the full cost pool and 0 gain or loss was recognized in the accompanying consolidated statements of operations as a result of the sale.

4.EQUITY INVESTMENTS
Investments accounted for by the equity method consist of the following as of SeptemberJune 30, 20192020 and December 31, 2018:2019:
   Carrying value Loss (income) from equity method investments
 Approximate ownership % September 30, 2019 December 31, 2018 Three months ended September 30, Nine months ended September 30,
    2019 2018 2019 2018
   (In thousands)
Investment in Tatex Thailand II, LLC23.5% $—
 $—
 $—
 $(137) $(2,085) $(241)
Investment in Grizzly Oil Sands ULC24.9999% 49,546
 44,259
 41
 275
 380
 833
Investment in Timber Wolf Terminals LLC(1)
—% —
 —
 —
 —
 —
 536
Investment in Windsor Midstream LLC22.5% 39
 39
 —
 —
 —
 (9)
Investment in Mammoth Energy Services, Inc.21.8% 24,377
 191,823
 43,041
 (12,996) 166,096
 (35,708)
Investment in Strike Force Midstream LLC(2)
—% —
 —
 —
 —
 —
 (693)
   $73,962

$236,121

$43,082
 $(12,858) $164,391
 $(35,282)

(1)
On June 5, 2018, the Company received its final distribution from Timber Wolf Terminals LLC ("Timber Wolf"). See below under Timber Wolf Terminals LLC for information regarding the subsequent dissolution of Timber Wolf.
(2)
On May 1, 2018, the Company sold its 25% interest in Strike Force Midstream LLC ("Strike Force") to EQT Midstream Partners, LP. See below under Strike Force Midstream LLC for information regarding this transaction.

Carrying value(Loss) income from equity method investments
Approximate ownership %June 30, 2020December 31, 2019Three months ended June 30,Six months ended June 30,
2020201920202019
(In thousands)
Investment in Grizzly Oil Sands ULC24.6 %$13,013  $21,000  $(45) $54  (188) $(339) 
Investment in Mammoth Energy Services, Inc.21.5 %—  11,005  —  (127,581) (10,646) (123,055) 
Investment in Windsor Midstream LLC22.5 %39  39  —  —  —  —  
Investment in Tatex Thailand II, LLC23.5 %—  —  —  1,945  —  2,085  
$13,052  $32,044  $(45) $(125,582) $(10,834) $(121,309) 
The tables below summarize financial information for the Company’s equity investments as of SeptemberJune 30, 20192020 and December 31, 2018.2019.

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Summarized balance sheet information:
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 September 30, 2019 December 31, 2018
  
 (In thousands)
Current assets$427,643
 $471,733
Noncurrent assets$1,309,729
 $1,302,488
Current liabilities$130,465
 $239,975
Noncurrent liabilities$176,145
 $94,575

June 30, 2020December 31, 2019
(In thousands)
Current assets$434,966  $421,326  
Noncurrent assets$1,107,221  $1,260,075  
Current liabilities$115,281  $132,569  
Noncurrent liabilities$172,478  $163,241  
Summarized results of operations: 
 Three months ended September 30, Nine months ended September 30,
 2019 2018 2019 2018
 (In thousands)
Gross revenue$113,417
 $384,043
 $557,375
 $1,451,580
Net (loss) income$(35,730) $68,414
 $(15,046) $181,884

Tatex Thailand II, LLC
 Three months ended June 30,Six months ended June 30,
 2020201920202019
(In thousands)
Gross revenue$60,109  $179,114  $157,492  $443,958  
Net (loss) income$(14,922) $(4,072) $(99,953) $20,684  
The Company has an indirect ownership interest in Tatex Thailand II, LLC ("Tatex II"). Tatex II held an 8.5% interest in APICO, LLC (“APICO”), an international oil and gas exploration company, before selling its interest in June 2019. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately 108,000 acres which includes the Phu Horm Field. The Company received $2.1 million in distributions from Tatex II during the nine months ended September 30, 2019, of which $1.9 million related to proceeds from the sale of its interest in APICO.
Grizzly Oil Sands ULC
The Company, through its wholly owned subsidiary Grizzly Holdings Inc. (“Grizzly Holdings”), owns an approximate 24.9999%24.6% interest in Grizzly Oil Sands ULC (“Grizzly”), a Canadian unlimited liability company. The remaining interest in Grizzly is owned by Grizzly Oil Sands Inc. (“Oil Sands”). As of SeptemberJune 30, 2019,2020, Grizzly had approximately 830,000 acres under lease in the Athabasca, Peace River and Cold Lake oil sands regions of Alberta, Canada. The Company reviewed its investment in Grizzly for impairment at SeptemberJune 30, 20192020 and 20182019 and determined 0 impairment was required. If commodity prices decline in the future however, impairment of the Company's investment in Grizzly may be necessary. During the nine months ended September 30, 2019, GulfportThe Company paid $0.4 million in cash calls during the six months ended June 30, 2019 prior to its election to cease funding further capital calls. Grizzly’s functional currency is the Canadian dollar. The Company’s investment in Grizzly wasincreased by $6.9 million as a result of a foreign currency translation gain and decreased by $7.8 million as a $2.0 millionresult of a foreign currency translation loss and increased by a $5.2 million foreign currency translation gain for the three and ninesix months ended SeptemberJune 30, 2019,2020, respectively. The Company's investment in Grizzly was increased by a $2.9$3.5 million foreign currency translation gain and decreased by a $5.7$7.3 million foreign currency translation loss for the three and ninesix months ended SeptemberJune 30, 2018, respectively.2019, respectively, as a result of a foreign currency translation gain.
Timber Wolf Terminals LLCMammoth Energy Services, Inc.
During 2012,At June 30, 2020, the Company investedowned 9,829,548 shares, or approximately 21.5%, of the outstanding common stock of Mammoth Energy Services, Inc. ("Mammoth Energy"). The approximate fair value of the Company's investment in Timber Wolf. Timber WolfMammoth Energy at June 30, 2020 was formed$11.6 million based on the quoted market price of Mammoth Energy's common stock
At March 31, 2020, the Company's share of net loss of Mammoth was in excess of the carrying value of its investment. As such, the Company's investment value was reduced to operatezero at March 31, 2020. During the second quarter of 2020, the Company's share of net loss of Mammoth continued to be in excess of the carrying value of its investment and, therefore, the Company's investment value remained at 0 at June 30, 2020.
The Company received 0 distributions from Mammoth Energy during the six months ended June 30, 2020 and distributions of $2.5 million during the six months ended June 30, 2019 as a crude/condensate terminalresult of $0.125 per share dividends in February 2019 and a sand transloading facilityMay 2019. The loss (income) from equity method investments presented in Ohio. Timber Wolf was dissolved in 2018.the table above reflects any intercompany profit eliminations.
Windsor Midstream LLC
At SeptemberJune 30, 2019,2020, the Company held a 22.5% interest in Windsor Midstream LLC (“Midstream”), an entity controlled and managed by an unrelated third party. The Company received 0 distributions from Midstream during the ninesix months ended SeptemberJune 30, 2019.2020.
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Tatex Thailand II, LLC
The Company has determined that Midstream is a variable interest entity ("VIE") but that the Company is not the primary beneficiary because it does not have a controlling financialan indirect ownership interest in Midstream. This entity is considered a VIE becauseTatex Thailand II, LLC ("Tatex") and received 0 distributions and $2.1 million in distributions from Tatex during the limited partners lack substantive kick-out or participating rights over the general partner. The general partner has power to direct the activities that most significantly impact Midstream's economic performance. The Company accounts for its investment in

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VIEs following the equity method of accounting. The carrying amounts of the Company’s equity investments are classified as other non-current assets on the accompanying consolidated balance sheets. The Company’s maximum exposure to loss as a result of its involvement with VIEs is based on the Company’s capital contributions and the economic performance of the VIEs, and is equal to the carrying value of the Company’s investments which is the maximum loss the Company could be required to record in the consolidated statements of operations.
Mammoth Energy Services, Inc.
At September 30, 2019, the Company owned 9,829,548 shares, or approximately 21.8%, of the outstanding common stock of Mammoth Energy Services, Inc. ("Mammoth Energy"). The Company reviewed its investment in Mammoth Energy as of September 30, 2019 for impairment based on certain qualitative and quantitative factors. As a result of the calculated fair values and other qualitative factors, the Company concluded that an other than temporary impairment was indicated. This resulted in recording an impairment loss of $35.5 million and $160.8 million for the three and ninesix months ended SeptemberJune 30, 2020 and 2019, which is includedrespectively. Tatex previously held an 8.5% interest in loss (income) from equity method investments, netAPICO, LLC (“APICO”), an international oil and gas exploration company, before selling its interest in the accompanying consolidated statements of operations. If Mammoth Energy's common stock continues to trade below the Company's carrying value forJune 2019. APICO has a prolonged period of time, further impairment of the Company's investmentreserve base located in Mammoth Energy may be necessary. The Company’s investment in Mammoth Energy was decreased by a $0.1 million foreign currency loss and increased by a $0.1 million foreign currency gain resulting from Mammoth Energy's foreign subsidiary for the three and nine months ended September 30, 2019, respectively. The Company’s investment in Mammoth Energy was increased by a $0.1 million foreign currency gain and decreased by a $0.2 million foreign currency loss resulting from Mammoth Energy’s foreign subsidiary for the three and nine months ended September 30, 2018, respectively. During the nine months ended September 30, 2019, Gulfport received distributions of $2.5 million from Mammoth Energy as a result of $0.125 per share dividends in February 2019 and May 2019. The approximate fair value of the Company's investment in Mammoth Energy's common stock at September 30, 2019 was $24.4 million based on the quoted market price of Mammoth Energy's common stock. The loss (income) from equity method investments presented in the table above reflects any intercompany profit eliminations.
Strike Force Midstream LLC
In February 2016, the Company,Southeast Asia through its wholly owned subsidiary Gulfport Midstream Holdings, LLC (“Midstream Holdings”), entered into an agreement with Rice Midstream Holdings LLC (“Rice”), then a subsidiaryownership of Rice Energy Inc., to develop natural gas gathering assets in eastern Belmont County and Monroe County, Ohio through Strike Force. In 2017, Rice was acquired by EQT Corporation ("EQT"). The Company owned a 25% interest in Strike Force,concessions covering approximately 108,000 acres which was sold to EQT Midstream Partners, LP in May 2018. The loss (income) from equity method investments presented inincludes the table above reflects any intercompany profit eliminations.Phu Horm Field.

4.LONG-TERM DEBT
5.LONG-TERM DEBT
Long-term debt consisted of the following items as of SeptemberJune 30, 20192020 and December 31, 2018:2019:
 September 30, 2019 December 31, 2018
 (In thousands)
Revolving credit agreement(1) 
$135,000
 $45,000
6.625% senior unsecured notes due 2023340,000
 350,000
6.000% senior unsecured notes due 2024630,796
 650,000
6.375% senior unsecured notes due 2025577,268
 600,000
6.375% senior unsecured notes due 2026397,529
 450,000
Net unamortized debt issuance costs(2)
(26,052) (30,733)
Construction loan22,650
 23,149
Less: current maturities of long term debt(622) (651)
Debt reflected as long term$2,076,569
 $2,086,765

June 30, 2020December 31, 2019
(In thousands)
Revolving credit agreement(1)
$123,000  $120,000  
6.625% senior unsecured notes due 2023324,583  329,467  
6.000% senior unsecured notes due 2024579,568  603,428  
6.375% senior unsecured notes due 2025507,870  529,525  
6.375% senior unsecured notes due 2026374,617  397,529  
Net unamortized debt issuance costs(2)
(20,802) (23,751) 
Construction loan22,131  22,453  
Less: current maturities of long term debt(649) (631) 
Debt reflected as long term$1,910,318  $1,978,020  
(1) The Company has entered into a senior secured revolving credit facility, as amended (the "revolving credit facility"), with The Bank of Nova Scotia, as the lead arranger and administrative agent and other lenders. The credit agreement provides for a maximum facility of $1.5 billion and matures on December 13, 2021. On June 3, 2019,May 1, 2020, the Company further amended itsentered into the fifteenth amendment to the Amended and Restated Credit Agreement. As part of the amendment, the Company's borrowing base and elected commitment were reduced from $1.2 billion and $1.0 billion, respectively, to $700.0 million. Additionally, the amendment added a requirement to maintain a ratio of Net Secured Debt to EBITDAX (as defined under the revolving credit facilityagreement) not exceeding 2.00 to 1.00, deferred the requirement to maintain a ratio of Net Funded Debt to EBITDAX of 4.00 to 1.00 until September 30, 2021 and added a limitation on the repurchase of unsecured notes, among other things, allowamendments.
On July 27, 2020, the Company entered into the sixteenth amendment to the Amended and Restated Credit Agreement. The sixteenth amendment allows for the Company to designateissue up to $750 million in second lien debt subject to certain of its subsidiaries

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conditions. See Note 16Table of Contents for further information on this amendment.


as unrestricted subsidiaries and to include LIBOR replacement provisions. Additionally, the borrowing base was reaffirmed at $1.4 billion, and the Company’s elected commitment amount remained at $1.0 billion.
As of SeptemberJune 30, 2019, $135.02020, $123.0 million was outstanding under the revolving credit facility and the total availability for future borrowings under this facility, after giving effect to an aggregate of $248.6$324.1 million letters of credit, was $616.4$252.9 million. The Company’s wholly owned subsidiaries have guaranteed the obligations of the Company under the revolving credit facility.
At SeptemberJune 30, 2019,2020, amounts borrowed under the revolving credit facility bore interest at a weighted average rate of 3.52%2.44%.
The Company was in compliance with its financial covenants under the revolving credit facility at SeptemberJune 30, 2019.2020.
(2) Loan issuance costs related to the 6.625% Senior Notes due 2023 (the "2023 Notes"), the 6.000% Senior Notes due 2024 (the "2024 Notes"), the 6.375% Senior Notes due 2025 (the "2025 Notes") and the 6.375% Senior Notes due 2026 (the "2026 Notes") (collectively the “Notes”) have been presented as a reduction to the principal amount of the Notes. At SeptemberJune 30, 2019,2020, total unamortized debt issuance costs were $3.6$2.8 million for the 2023 Notes, $7.5$6.1 million for the 2024 Notes, $10.8$8.5 million for the 2025 Notes and $4.0$3.4 million for the 2026 Notes. In addition, loan commitment fee costs for the Company's construction loan agreement were $0.1 million at SeptemberJune 30, 2019.2020.
The Company capitalized approximately $1.0$0.5 million and $2.8$0.7 million in interest expense to undevelopedits unevaluated oil and natural gas properties during the three and ninesix months ended SeptemberJune 30, 2019,2020, respectively. The Company capitalized approximately $1.6 $1.0
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million and $4.0$1.8 million in interest expense to undevelopedits unevaluated oil and natural gas properties during the three and ninesix months ended SeptemberJune 30, 2018,2019, respectively.
Debt Repurchases
DuringIn 2019, the three months ended September 30, 2019,Company's Board of Directors authorized $200 million of cash to be used to repurchase its senior notes in the open market at discounted values to par. The Company used borrowings under its revolving credit facility to repurchase in the open market approximately $104.4$47.5 million and $73.3 million aggregate principal amount of its outstanding Notes for $80.3 million. This$12.6 million and $22.8 million during the three and six months ended June 30, 2020, respectively. For the three months ended June 30, 2020, this included approximately $10.0$4.9 million principal amount of the 2023 Notes, $19.2$16.3 million principal amount of the 2024 Notes, $22.7$13.5 million principal amount of the 2025 Notes, and $52.5$12.8 million principal amount of the 2026 Notes. The Company recognized a $23.6$34.3 million and $49.6 million gain on debt extinguishment, which included retirement of unamortized issuance costs and fees associated with the repurchased debt.debt, during the three and six months ended June 30, 2020, respectively. This gain is included in gain on debt extinguishment in the accompanying consolidated statements of operations.
5.COMMON STOCK AND CHANGES IN CAPITALIZATION
Stock Repurchase Program
In January 2018, As of May 1, 2020, further repurchases under this program are limited due to the board of directors ofagreements entered into under the Company approved a stock repurchase programfifteenth amendment to acquire up to $100 millionthe Amended and Restated Credit Agreement of the Company's credit facility.
Fair Value of Debt
At June 30, 2020, the carrying value of the outstanding stock during 2018. In May 2018,debt represented by the Company's boardNotes was approximately $1.8 billion. Based on the quoted market prices (Level 1), the fair value of directors authorized the expansion of its stock repurchase program, authorizing the CompanyNotes was determined to acquire up to an additional $100be approximately $930.2 million of its outstanding common stock during 2018 for a total of up to $200 million. The repurchase program did not require the Company to acquire any specific number of shares. This repurchase program was authorized to extend through December 31, 2018 and the Company repurchased 20.7 million shares of common stock in 2018 for $200.0 million in aggregate consideration.at June 30, 2020.

6.CHANGES IN CAPITALIZATION
Stock Repurchases
In January 2019, the boardCompany's Board of directors of the CompanyDirectors approved a new stock repurchase program to acquire a portion of the Company's outstanding common stock within a 24 month24-month period. Purchases underThe program was suspended in the repurchase program may be made from timefourth quarter of 2019, and the May 1, 2020 amendment to time in open market or privately negotiated transactions,the Company's revolving credit facility prohibits further stock repurchases.
For the three and are subject to market conditions, applicable legal requirements, contractual obligations and other factors. The repurchase program does not requiresix months ended June 30, 2019, the Company to acquire any specific number of shares. This repurchase program is authorized to extend through December 31, 2020repurchased 0.2 million and may be suspended, modified, extended or discontinued by the board of directors at any time. The Company did not repurchase any shares under the program during the three months ended September 30, 2019, and repurchased approximately 3.8 million shares for a cost of approximately $1.8 million and $30.0 million, during the nine months ended September 30, 2019. respectively, under this repurchase program.
Additionally, during each of the three and ninesix months ended SeptemberJune 30, 2020, the Company repurchased approximately 27,000 and 107,000 shares, respectively, for a cost of $28 thousand and $0.1 million, respectively, to satisfy tax withholding requirements incurred upon the vesting of restricted stock. During the three and six months ended June 30, 2019, the Company repurchased approximately 0.1 million72,000 and 87,000 shares, respectively, for a cost of approximately $0.1$0.5 million and $0.7$0.6 million, respectively, to satisfy tax withholding requirements incurred upon the vesting of restricted stock. All repurchased shares have been canceled and returned to the status of authorized but unissued shares.

6.STOCK-BASED COMPENSATION

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STOCK-BASED COMPENSATION
The Company has granted restricted stock units to employees and directors pursuant to the 2019 Amended and Restated Incentive Stock Plan ("2019 Plan"), as discussed below. During the three and ninesix months ended SeptemberJune 30, 2019,2020, the Company’s stock-based compensation cost was $2.7$2.2 million and $8.3$4.3 million, respectively, of which the Company capitalized $1.1$1.0 million and $3.3$1.9 million, respectively, relating to its exploration and development efforts. During the three and ninesix months ended SeptemberJune 30, 2018,2019, the Company'sCompany’s stock-based compensation cost was $3.6$2.8 million and $9.7$5.6 million, respectively, of which the Company capitalized $1.4$1.1 million and $3.9$2.3 million, respectively, relating to its exploration and development efforts. Stock compensation costs, net of the amounts capitalized, are included in general and administrative expenses in the accompanying consolidated statements of operations.
The following table summarizes restricted stock unit activity for the ninesix months ended SeptemberJune 30, 2019:2020:
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Number of
Unvested
Restricted Stock Units
 
Weighted
Average
Grant Date
Fair Value
 
Number of
Unvested
Performance Vesting Restricted Stock Units
 
Weighted
Average
Grant Date
Fair Value
Unvested shares as of January 1, 20191,535,811
 $11.57
 $—
 $—
Granted4,011,073
 3.74
 2,009,144
 2.85
Vested(674,374) 12.86
 —
 —
Forfeited(289,610) 7.83
 (112,742) 1.98
Unvested shares as of September 30, 20194,582,900
 $4.76
 1,896,402
 $2.91

Number of
Unvested
Restricted Stock Units		Weighted
Average
Grant Date
Fair Value		Number of
Unvested
Performance Vesting Restricted Stock Units		Weighted
Average
Grant Date
Fair Value
Unvested shares as of January 1, 20204,098,318  $4.73  1,783,660  $2.96  
Granted1,985,452  0.67  —  —  
Vested(512,283) 7.19  —  —  
Forfeited(979,929) 3.82  (830,323) 1.98  
Unvested shares as of June 30, 20204,591,558  $3.00  953,337  $3.82  
Restricted Stock Units
Restricted stock units awarded under the 2019 Plan generally vest over a period of one year in the case of directors and three years in the case of employees and vesting is dependent upon the recipient meeting applicable service requirements. Stock-based compensation costs are recorded ratably over the service period. The grant date fair value of restricted stock units represents the closing market price of the Company's common stock on the date of grant. Unrecognized compensation expense as of SeptemberJune 30, 20192020 related to restricted stock units was $19.0 million.$9.4 million. The expense is expected to be recognized over a weighted average period of 2.281.75 years.
Performance Vesting Restricted Stock Units
During the nine months ended September 30, 2019, theThe Company has awarded performance vesting units to certain of its executive officers under the 2019 Plan. The number of shares of common stock issued pursuant to the award will be based on relative total shareholder return ("RTSR"). RTSR is an incentive measure whereby participants will earn from 0% to 200% of the target award based on the Company’s RTSR ranking compared to the RTSR of the companies in the Company’s designated peer group at the end of the performance period. Awards will be earned and vested over a performance period measured from January 1, 2019 to December 31, 2021, subject to earlier termination of the performance period in the event of a change in control. The grant date fair value was determined using the Monte Carlo simulation method and is being recorded ratably over the performance period. Expected volatilities utilized in the Monte Carlo model were estimated using a historical period consistent with the remaining performance period of approximately two years. The risk-free interest rates were based on the U.S. Treasury rate for a term commensurate with the expected life of the grant. The Company assumed a range of risk-free interest rates of 1.56% to 2.42% and a range of expected volatilities of 29.1% to 85.1% to estimate the fair value of performance vesting units granted during the nine months ended September 30, 2019. Unrecognized compensation expense as of SeptemberJune 30, 20192020 related to performance vesting restricted shares was $4.9$2.2 million. The expense is expected to be recognized over a weighted average period of 1.78 years.
Cash Incentive Awards
On March 16, 2020, the Board of Directors of the Company approved the Company's 2020 Incentive Plan (the "2020 Incentive Plan"). The 2020 Incentive Plan provides for incentive compensation opportunities ("Incentive Awards") for select employees of the Company that are tied to the achievement of one or more performance goals relating to certain financial and operational metrics over a period of time. The earning of an Incentive Award and payout opportunity is contingent upon meeting the Incentive Award's applicable threshold performance levels. If such threshold performance levels are satisfied, the payout amount varies for performance above or below the pre-established target performance levels.
During the six months ended June 30, 2020, the Company awarded Incentive Awards to certain of its executive officers under the 2020 Incentive Plan. The cash amount of each award ultimately received is based on the attainment of certain financial, operational and total shareholder return performance targets and is subject to the recipient's continuous employment. Each Incentive Award is subject to a Performance Period of January 1, 2020 to December 31, 2020, and different vesting periods apply to separate one-third portions of each Incentive Award, with a different tranche vesting each on December 31, 2020, 2021, and 2022. The Incentive Awards are considered liability awards as the ultimate amount of the award is based, at least in part, on the price of the Company's shares, and as such, are remeasured to fair value at the end of each reporting period. The fair value of the Incentive Awards at June 30, 2020 was $3.0 million. Unrecognized compensation expense as of June 30, 2020 related to Incentive Awards was $2.4 million. The expense is expected to be recognized over a weighted average period of 2.641.62 years.

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Table of Contents8.EARNINGS PER SHARE


7.EARNINGS PER SHARE
Reconciliations of the components of basic and diluted net income per common share are presented in the tables below:
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 Three months ended September 30,
 2019 2018
 Loss Shares 
Per
Share
 Income Shares 
Per
Share
 (In thousands, except share data)
Basic:           
Net (loss) income$(48,752) 159,548,477
 $(0.31) $95,150
 173,057,538
 $0.55
Effect of dilutive securities:
 
 
 
 
 
Stock options and awards—
 —
 
 —
 247,376
 
Diluted:
 
 
 
 
 
Net (loss) income$(48,752) 159,548,477
 $(0.31) $95,150
 173,304,914
 $0.55

Three months ended June 30,
 20202019
LossSharesPer
Share		IncomeSharesPer
Share
(In thousands, except share data)
Basic:
Net (loss) income$(561,068) 159,933,739  $(3.51) $234,956  159,324,909  $1.47  
Effect of dilutive securities:
Stock awards—  —  —  181,917  
Diluted:
Net (loss) income$(561,068) 159,933,739  $(3.51) $234,956  159,506,826  $1.47  
Nine months ended September 30,Six months ended June 30,
2019 201820202019
Income Shares Per
Share		 Income Shares Per
Share		LossSharesPer
Share		IncomeSharesPer
Share
(In thousands, except share data)(In thousands, except share data)
Basic:           Basic:
Net income$248,446
 160,553,796
 $1.55
 $296,559
 175,776,312
 $1.69
Net (loss) incomeNet (loss) income$(1,078,606) 159,846,981  $(6.75) $297,198  161,064,787  $1.85  
Effect of dilutive securities:
 
 
   
 
Effect of dilutive securities:
Stock options and awards—
 4,266,206
 
 —
 664,149
 
Stock options and awards—  —  —  525,300  
Diluted:
 
 
   
 
Diluted:
Net income$248,446
 164,820,002
 $1.51
 $296,559
 176,440,461
 $1.68
Net (loss) incomeNet (loss) income$(1,078,606) 159,846,981  $(6.75) $297,198  161,590,087  $1.84  


There were 2,073,6381,281,773 and 1,610,572 shares of common stock that were considered anti-dilutive for the three and six months ended SeptemberJune 30, 2019.2020, respectively. There were 0 potential shares of common stock that were considered anti-dilutive for the ninethree and six months ended SeptemberJune 30, 2019 or the three and nine months ended September 30, 2018.2019.

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Table of Contents9.COMMITMENTS AND CONTINGENCIES


8.COMMITMENTS AND CONTINGENCIES
Future Firm Transportation and Sales Commitments
The table below presents theCompany has entered into various firm sales contracts to deliver and sell natural gas. The Company expects to fulfill its delivery commitments by year:primarily with production from proved developed reserves. The Company's proved reserves have generally been sufficient to satisfy its delivery commitments during the three most recent years, and it expects such reserves will continue to be the primary means of fulfilling its future commitments. However, where the Company's proved reserves are not sufficient to satisfy its delivery commitments, it can and may use spot market purchases to satisfy the commitments.
A summary of these commitments at June 30, 2020 are set forth in the table below:
(MMBtu per day)
Remaining 2020311,000  
2021192,000  
202270,000  
202317,000  
Total590,000
Future Firm Transportation Commitments
The Company has contractual commitments with pipeline carriers for future transportation of natural gas from the Company's production areas to downstream markets. Commitments related to future firm transportation agreements are not
  (MMBtu per day)
Remaining 2019 424,000
2020 314,000
2021 192,000
2022 70,000
2023 17,000
Thereafter —
Total 1,017,000
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Therecorded as obligations in the accompanying consolidated balance sheets; however, the costs associated with these commitments are reflected in the Company's estimates of proved reserves and future net revenues.
A summary of these commitments at June 30, 2020 are set forth in the table below presentsbelow:
Total MMBtu(In thousands)
Remaining 2020267,720,000  $138,495  
2021531,075,000  285,779  
2022531,075,000  286,616  
2023515,775,000  282,936  
2024489,490,000  265,558  
Thereafter3,767,959,000  2,160,634  
Total6,103,094,000  $3,420,018  
As of June 30, 2020, the Company had entered into firm transportation commitments by year:
  (In thousands)
Remaining 2019 $65,763
2020 287,627
2021 286,665
2022 286,665
2023 282,981
Thereafter 2,410,866
Total $3,620,567

contracts to deliver approximately 1,455,000 MMBtu per day for the remainder of 2020 and 2021, respectively. Under these firm transportation contracts, the Company is obligated to deliver minimum daily volumes or pay fees for any deficiencies in deliveries. As a result of the reduced production from the Company's Utica Shale or SCOOP acreage due to decreased developmental activities, taking into consideration the current low commodity price environment, the Company expects that it will be unable to meet its obligations under the existing firm transportation contracts, resulting in fees, which may be significant and may have a material adverse effect on its operations.
Other Commitments
Effective October 1, 2014, the Company entered into a Sand Supply Agreement with Muskie Proppant LLC (“Muskie”), a subsidiary of Mammoth Energy and a related party. Pursuant to this agreement, as amended effective August 3, 2018, the Company has agreed to purchase annual and monthly amounts of proppant sand subject to exceptions specified in the agreement at agreed pricing plus agreed costs and expenses through 2021. Failure by either Muskie or the Company to deliver or accept the minimum monthly amount results in damages calculated per ton based on the difference between the monthly obligation amount and the amount actually delivered or accepted, as applicable. The Company incurred $0.02$1.9 million and $0.4$3.8 million in non-utilization fees under this agreement during the three and ninesix months ended SeptemberJune 30, 2019,2020, respectively. The Company incurred $1.3 million and $1.5 million indid not incur any non-utilization fees under this agreement during the three and nine months ended SeptemberJune 30, 2018.2019 and incurred $0.3 million of such fees during the six months ended June 30, 2019.
Future minimum commitments under this agreement at SeptemberJune 30, 20192020 are:
(In thousands)
Remaining 2020$3,750  
20217,500  
Total$11,250  
 (In thousands)
Remaining 2019$6,000
202024,000
202124,000
Total$54,000


Litigation and Regulatory Proceedings
The Company is involved in a number of litigation and regulatory proceedings including those described below. Many of these proceedings are in early stages, and many of them seek or may seek damages and penalties, the amount of which is

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indeterminate. The Company's total accrued liabilities in respect of litigation and regulatory proceedings is determined on a case-by-case basis and represents an estimate of probable losses after considering, among other factors, the progress of each case or proceeding, its experience and the experience of others in similar cases or proceedings, and the opinions and views of legal counsel. Significant judgment is required in making these estimates and their final liabilities may ultimately be materially different.
The Company, along with a number of other oil and gas companies, has been named as a defendant in two2 separate complaints, one filed by the State of Louisiana and the Parish of Cameron in the 38th Judicial District Court for the Parish of Cameron on February 9, 2016 and the other filed by the State of Louisiana and the District Attorney for the 15th Judicial
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District of the State of Louisiana in the 15th Judicial District Court for the Parish of Vermilion on July 29, 2016 (together, the "Complaints"). The Complaints allege that certain of the defendants’ operations violated the State and Local Coastal Resources Management Act of 1978, as amended, and the rules, regulations, orders and ordinances adopted thereunder (the "CZM Laws") by causing substantial damage to land and waterbodies located in the coastal zone of the relevant Parish. The plaintiffs seek damages and other appropriate relief under the CZM Laws, including the payment of costs necessary to clear, re-vegetate, detoxify and otherwise restore the affected coastal zone of the relevant Parish to its original condition, actual restoration of such coastal zone to its original condition, and the payment of reasonable attorney fees and legal expenses and interest. The United States District Court for the Western District of Louisiana issued orders remanding the cases to their respective state court, and the defendants have appealed the remand orders to the 5th Circuit Court of Appeals.
In July 2019, Pigeon Land Company, Inc., a successor in interest to certain of the Company’s legacy Louisiana properties, filed an action against the Company and a number ofmany other oil and gas companies in the 16th Judicial District Court for the Parish of Iberia in Louisiana. The suit alleges negligence, strict liability and various violations of Louisiana statutes relating to property damage in connection with the historic development of the Company’s Louisiana properties and seeks unspecified damages (including punitive damages), an injunction to return the affected property to its original condition, and the payment of reasonable attorney fees and legal expenses and interest.
In September 2019, a stockholder of Mammoth Energy filed a derivative action on behalf of Mammoth Energy against members of Mammoth Energy’s board of directors, including a director designated by the Company, and its significant stockholders, including the Company, in the United States District Court for the Western District of Oklahoma. The complaint alleges, among other things, that the members of Mammoth Energy’s board of directors breached their fiduciary duties and violated the Securities Exchange Act of 1934, as amended, in connection with Mammoth Energy’s activities in Puerto Rico following Hurricane Maria. The complaint seeks unspecified damages, the payment of reasonable attorney fees and legal expenses and interest and to force Mammoth Energy and its board of directors to make specified corporate governance reforms.
In October 2019, Saydee Resources, LLC, on behalf of itself and a class of similarly situated royalty holders, filed an action against the Company in the District Court of Grady County Oklahoma. The suit alleges that the Company underpaid royalty holders and seeks unspecified damages for breach of contract, tortious breach of contract, fraud and unjust enrichment.
In October 2019, Kelsie Wagner, in her capacity as trustee of various trusts and on behalf of the trusts and other similarly situated royalty owners, filed an action against the Company in the District Court of Grady County, Oklahoma.  The suit alleges that the Company underpaid royalty owners and seeks unspecified damages for violations of the Oklahoma Production Revenue Standards Act and fraud.
In March 2020, Robert F. Woodley, individually and on behalf of all others similarly situated, filed a federal securities class action against the Company, David M. Wood, Keri Crowell and Quentin R. Hicks in the United States District Court for the Southern District of New York. The complaint alleges that the Company made materially false and misleading statements regarding the Company’s business and operations in violation of the federal securities laws and seeks unspecified damages, the payment of reasonable attorneys’ fees, expert fees and other costs, pre-judgment and post-judgment interest, and such other and further relief that may be deemed just and proper.
In June 2020, Sam L. Carter, derivatively on behalf of the Company, filed an action against certain of our current and former executive officers and directors in the United States District Court for the District of Delaware. The complaint alleges that the defendants breached their fiduciary duties to the Company in connection with certain alleged materially false and misleading statements regarding our business and operations in violation of the federal securities laws. The complaint seeks to recover unspecified damages from the defendants, the implementation of specified corporate governance reforms, reasonable attorneys’ and experts’ fees, costs and expenses, and such other relief as may be deemed just and proper.

In December 2019, the Company filed a lawsuit against Stingray Pressure Pumping LLC, a subsidiary of Mammoth Energy (“Stingray”), for breach of contract and to terminate the Master Services Agreement for pressure pumping services, effective as of October 1, 2014, as amended (the “Master Services Agreement”), between Stingray and the Company. In March 2020, Stingray filed a counterclaim against the Company in the Superior Court of the State of Delaware. The counterclaim alleges that the Company has breached the Master Services Agreement. The counterclaim seeks actual damages, which the complaint calculates to be approximately $28.0 million as of June 2020 (such amount to increase each month), the payment of reasonable attorney fees and legal expenses and pre- and post-judgment interest as allowed, and such other and further relief which it may be justly entitled.
In April 2020, Bryon Lefort, individually and on behalf of similarly situated individuals, filed an action against the Company in the United States District Court for the Southern District of Ohio Eastern Division. The complaint alleges that the Company violated the Fair Labor Standards Act (“FLSA”), the Ohio Wage Act and the Ohio Prompt Pay Act by classifying the plaintiffs as independent contractors and paying them a daily rate with no overtime compensation for hours worked in excess of 40 hours per week. The complaint seeks to recover unpaid regular and overtime wages, liquidated damages in an amount equal
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to 6 of all unpaid overtime compensation, the payment of reasonable attorney fees and legal expenses and pre-judgment and post-judgment interest, and such other damages that may be owed to the workers.
These cases are still in their early stages. As a result, the Company has not had the opportunity to evaluate the allegations made in the plaintiffs' complaints and intends to vigorously defend the suits.
The Company filed an action against TH Exploration, LLC ("TH") in Tarrant County, Texas. The suit alleges breach of purchase and sale agreement providing for the Company's disposition of certain oil and gas properties in Ohio to TH. The Company is seeking specific performance, related to TH's obligations to close the transaction and tender the purchase price, along with any additional relief available to the Company.
SEC Investigation
The SEC has commenced an investigation with respect to certain actions by former Company management, including alleged improper personal use of Company assets, and potential violations by former management and the Company of the Sarbanes-Oxley Act of 2002 in connection with such actions. The Company has fully cooperated and intends to continue to cooperate fully with the SEC’s investigation. Although it is not possible to predict the ultimate resolution or financial liability

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with respect to this matter, the Company believes that the outcome of this matter will not have a material effect on the Company’s business, financial condition or results of operations.
Business Operations
The Company is involved in various lawsuits and disputes incidental to its business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions.
Environmental Contingencies
The nature of the oil and gas business carries with it certain environmental risks for Gulfport and its subsidiaries. They have implemented various policies, programs, procedures, training and audits to reduce and mitigate such environmental risks. They conduct periodic reviews, on a company-wide basis, to assess changes in their environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. The Company manages its exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the extent of an identified environmental concern, they may, among other things, exclude a property from the transaction, require the seller to remediate the property to their satisfaction in an acquisition or agree to assume liability for the remediation of the property.
The Company received several Finding of Violation (“FOVs”) from the United States Environmental Protection Agency ("USEPA") alleging violations of the Clean Air Act at approximately 1217 locations in Ohio. The first FOV for 1 site was dated December 11, 2013.  Two subsequent FOVs incorporated and expanded the scope on January 4, 2017 and April 15, 2019.  The Company has exchanged information with the USEPA and is engaged in discussions aimed at resolving the allegations. Resolution of the matter may resultresulted in monetary sanctions of more than $100,000. approximately $1.7 million.
In October 2018, the company submitted a Voluntary Disclosure document to the Oklahoma Department of Environmental Quality (ODEQ) stemming from improper air permitting at several sites in Midcon between 2014 and 2017. The sites were permitted by Vitruvian prior to the Company's purchase of those assets. The sites were permitted utilizing the “permit by rule” regulation but actually required Title V air permits. The Company has agreed in a draft Consent Order to obtain the proper permits and to pay the costs from not having the proper permits in place in the amount of $180,000 to the ODEQ. The Order received final approval at the ODEQ and is expected to be finalized in the third quarter of 2020.
Other Matters
Based on management’s current assessment, they are of the opinion that no pending or threatened lawsuit or dispute relating to its business operations is likely to have a material adverse effect on their future consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.
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9.DERIVATIVE INSTRUMENTS

10.DERIVATIVE INSTRUMENTS
Natural Gas, Oil and Natural Gas Liquids Derivative Instruments
The Company seeks to reduce its exposure to unfavorable changes in natural gas, oil and natural gas liquids ("NGLs"NGL") prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps, costless collars and various types of option contracts. These contracts allow the Company to predict with greater certainty the effective natural gas, oil and NGLsNGL prices to be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided in the contracts. However, the Company will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production.
Fixed price swaps are settled monthly based on differences between the fixed price specified in the contract and the referenced settlement price. When the referenced settlement price is less than the price specified in the contract, the Company receives an amount from the counterparty based on the price difference multiplied by the volume. Similarly, when the referenced settlement price exceeds the price specified in the contract, the Company pays the counterparty an amount based on the price difference multiplied by the volume. The prices contained in these fixed price swaps are based on the NYMEX Henry Hub for natural gas, the NYMEX West Texas Intermediate for oil and Mont Belvieu for propane, pentane and ethane. Below is a summary of the Company’s open fixed price swap positions as of SeptemberJune 30, 2019.2020. 
 LocationDaily Volume (MMBtu/day) Weighted
Average Price
Remaining 2019NYMEX Henry Hub1,380,000
 $2.81
2020NYMEX Henry Hub519,000
 $2.88

LocationDaily Volume
(MMBtu/day)		Weighted
Average Price
Remaining 2020NYMEX Henry Hub357,000  $2.86  

LocationDaily Volume
(Bbls/day)		Weighted
Average Price
Remaining 2020NYMEX WTI3,000  $35.49  
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 LocationDaily Volume
(Bbls/day)		 Weighted
Average Price
Remaining 2019NYMEX WTI6,000
 $60.81
2020NYMEX WTI6,000
 $59.82
 LocationDaily Volume
(Bbls/day)		 Weighted
Average Price
Remaining 2019Mont Belvieu C21,000
 $18.48
Remaining 2019Mont Belvieu C34,000
 $29.02
Remaining 2019Mont Belvieu C51,000
 $53.71

LocationDaily Volume
(Bbls/day)		Weighted
Average Price
Remaining 2020Mont Belvieu C31,500  $20.27  
The Company sold call options in exchange for a premium, and used the associated premiums to enhance the fixed price for a portion of the fixed price natural gas swaps primarily for 2020 listed above. Each call option has an established ceiling price. When the referenced settlement price is above the price ceiling established by these call options, the Company pays its counterparty an amount equal to the difference between the referenced settlement price and the price ceiling multiplied by the hedged contract volumes.
 LocationDaily Volume (MMBtu/day) Weighted Average Price
Remaining 2019NYMEX Henry Hub30,000
 $3.10
2022NYMEX Henry Hub628,000
 $2.90
2023NYMEX Henry Hub628,000
 $2.90

LocationDaily Volume
(MMBtu/day)		Weighted Average Price
2022NYMEX Henry Hub628,000  $2.90  
2023NYMEX Henry Hub628,000  $2.90  
ForThe Company entered into costless collars based off the NYMEX Henry Hub natural gas index. Each two-way price collar has a portionset floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the natural gas fixed price swaps listed above,ranges set by the counterparty had the option to extend the original terms for an additional twelve months for the period of January 2019 through December 2019. In December 2018, the counterparties chose to exercise all natural gas fixed price swaps, resulting in an additional 100,000 MMBtu per day at a weighted average price of $3.05 per MMBtu, which is includedfloor and ceiling prices in the natural gas fixed price swaps listed above.various collars, the Company will cash-settle the difference with the counterparty.
LocationDaily Volume (MMBtu/day)Weighted Average Floor PriceWeighted Average Ceiling Price
2021NYMEX Henry Hub250,000  $2.46  $2.81  
In addition, the Company entered into natural gas basis swap positions. As of SeptemberJune 30, 2019,2020, the Company had the following natural gas basis swap positions open:
 Gulfport PaysGulfport ReceivesDaily Volume (MMBtu/day) Weighted Average Fixed Spread
Remaining 2019Transco Zone 4NYMEX Plus Fixed Spread60,000
 $(0.05)
2020Transco Zone 4NYMEX Plus Fixed Spread60,000
 $(0.05)
2020Fixed SpreadONEOK Minus NYMEX10,000
 $(0.54)
Gulfport PaysGulfport ReceivesDaily Volume
(MMBtu/day)		Weighted Average Fixed Spread
Remaining 2020Transco Zone 4NYMEX Plus Fixed Spread60,000  $(0.05) 
Remaining 2020Fixed SpreadONEOK Minus NYMEX10,000  $(0.54) 
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During the three months ended June 30, 2020, we early terminated oil fixed price swaps which represented approximately 6,000 BBls of oil per day for the remainder of 2020. The early termination resulted in a cash settlement of $40.5 million.
Contingent Consideration Arrangement
The purchase and sale agreement for the sale of the Company'sCompany sold its non-core assets located in the WCBBWest Cote Blanche Bay and Hackberry fields of Louisiana in July 2019. The sale price included a contingent consideration arrangement that entitlesthe potential for the Company to receive bonuscontingent payments ifbased on commodity prices exceedexceeding specified thresholds. The calculated fair value of thisthresholds over the two years following the closing date. This contingent paymentconsideration arrangement was approximately $1.1 million as of the closing date of the divestiture.determined to be an embedded derivative. See below for threshold and potential payment amounts.
Period
Threshold(1)
Payment to be received(2)
July 2020 - June 2021Greater than or equal to $60.65$150,000
 Between $52.62 - $60.65
Calculated Value(3)

 Less than or equal to $52.62$—
(1)Period
Threshold(1)
Payment to be received(2)
July 2020 - June 2021Greater than or equal to $60.65$150,000 
Between $52.62 - $60.65
Calculated Value(3)
Less than or equal to $52.62$— 
(1)Based on the "WTI NYMEX + Argus LLS Differential," as published by Argus Media.
(2)Payment will be assessed monthly from July 2020 through June 2021. If threshold is met, payment shall be received within five business days after the end of each calendar month.
(3)If average daily price, as defined in (1), is greater than $52.62 but less than $60.65, payment received will be $150,000 multiplied by a fraction, the numerator of which is the amount determined by subtracting $52.62 from such average daily price, and the denominator of which is $8.03.


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Balance Sheet Presentation
The Company reports the fair value of derivative instruments on the consolidated balance sheets as derivative instruments under current assets, noncurrent assets, current liabilities and noncurrent liabilities on a gross basis. The Company determines the current and noncurrent classification based on the timing of expected future cash flows of individual trades. The following table presents the fair value of the Company’s derivative instruments on a gross basis at SeptemberJune 30, 20192020 and December 31, 2018:2019:
 September 30, 2019 December 31, 2018
 (In thousands)
Commodity derivative instruments$134,511
 $21,352
Contingent consideration arrangement60
 —
Total short-term derivative instruments - asset$134,571
 $21,352
    
Commodity derivative instruments$23,375
 $—
Contingent consideration arrangement44
 —
Total long-term derivative instruments - asset$23,419
 $—
    
Total short-term derivative instruments - liability$429
 $20,401
    
Total long-term derivative instruments - liability$72,040
 $13,992

June 30, 2020December 31, 2019
(In thousands)
Commodity Contracts:
Short-term derivative asset$53,188  $125,383  
Long-term derivative asset4,298  —  
Short-term derivative liability(8,540) (303) 
Long-term derivative liability(45,615) (53,135) 
Total commodity derivative position$3,331  $71,945  
Contingent consideration arrangement:
Short-term derivative asset$—  $818  
Long-term derivative asset—  563  
Total contingent consideration derivative position$—  $1,381  
Total net asset derivative position$3,331  $73,326  
Gains and Losses
The following table presents the gain and loss recognized in net gain (loss) on natural gas, oil and NGLsNGL derivatives in the accompanying consolidated statements of operations for the three and ninesix months ended SeptemberJune 30, 20192020 and 2018.2019.
 Net gain (loss) on derivative instruments
 Three months ended September 30, Nine months ended September 30,
 2019 2018 2019 2018
 (In thousands)
Natural gas derivatives$11,731
 $14,101
 $147,774
 $(26,789)
Oil derivatives12,736
 (11,610) 24,153
 (45,176)
NGLs derivatives3,641
 (12,154) 7,276
 (24,772)
Contingent consideration arrangement(1,034) —
 (1,034) —
Total$27,074
 $(9,663) $178,169
 $(96,737)
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Net gain (loss) on derivative instruments
Three months ended June 30,Six months ended June 30,
2020201920202019
(In thousands)
Natural gas derivatives$35,689  $152,475  $81,542  $136,044  
Oil derivatives(7,937) 11,871  44,937  11,417  
NGL derivatives(781) 6,794  139  3,634  
Contingent consideration arrangement—  —  (1,381) —  
Total$26,971  $171,140  $125,237  $151,095  
Offsetting of Derivative Assets and Liabilities
As noted above, the Company records the fair value of derivative instruments on a gross basis. The following table presents the gross amounts of recognized derivative assets and liabilities in the consolidated balance sheets and the amounts that are subject to offsetting under master netting arrangements with counterparties, all at fair value.
As of June 30, 2020
Gross Assets (Liabilities)Gross Amounts
Presented in theSubject to MasterNet
Consolidated Balance SheetsNetting AgreementsAmount
(In thousands)
Derivative assets$57,486  $(48,761) $8,725  
Derivative liabilities$(54,155) $48,761  $(5,394) 
 As of September 30, 2019
 Gross Assets (Liabilities) Gross Amounts  
 Presented in the Subject to Master Net
 Consolidated Balance Sheets Netting Agreements Amount
 (In thousands)
Derivative assets$157,990
 $(72,469) $85,521
Derivative liabilities$(72,469) $72,469
 $—

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 As of December 31, 2018
 Gross Assets (Liabilities) Gross Amounts  
 Presented in the Subject to Master Net
 Consolidated Balance Sheets Netting Agreements Amount
 (In thousands)
Derivative assets$21,352
 $(19,289) $2,063
Derivative liabilities$(34,393) $19,289
 $(15,104)

As of December 31, 2019
Gross Assets (Liabilities)Gross Amounts
Presented in theSubject to MasterNet
Consolidated Balance SheetsNetting AgreementsAmount
(In thousands)
Derivative assets$126,764  $(53,438) $73,326  
Derivative liabilities$(53,438) $53,438  $—  
Concentration of Credit Risk
By using derivative instruments that are not traded on an exchange, the Company is exposed to the credit risk of its counterparties. Credit risk is the risk of loss from counterparties not performing under the terms of the derivative instrument. When the fair value of a derivative instrument is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, it is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The Company’s derivative contracts are with multiple counterparties to lessen its exposure to any individual counterparty. Additionally, the Company uses master netting agreements to minimize credit risk exposure. The creditworthiness of the Company’s counterparties is subject to periodic review. None of the Company’s derivative instrument contracts contain credit-risk related contingent features. Other than as provided by the Company’s revolving credit facility, the Company is not required to provide credit support or collateral to any of its counterparties under its derivative instruments, nor are the counterparties required to provide credit support to the Company.
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10.FAIR VALUE MEASUREMENTS

11.FAIR VALUE MEASUREMENTS
The Company records certain financial and non-financial assets and liabilities on the balance sheet at fair value. Fair value is the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. Fair value measurements are classified and disclosed in one of the following categories:
Level 1 – Quoted prices in active markets for identical assets and liabilities.
Level 2 – Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active and model-derived valuations whose inputs are observable or whose significant value drivers are observable.
Level 3 – Significant inputs to the valuation model are unobservable.
Valuation techniques that maximize the use of observable inputs are favored. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter.
The following tables summarize the Company’s financial and non-financial assets and liabilities by valuation level as of SeptemberJune 30, 20192020 and December 31, 2018:2019:
June 30, 2020
Level 1Level 2Level 3
(In thousands)
Assets:
Derivative Instruments$— $57,486 $— 
Liabilities:
Derivative Instruments$— $54,155 $— 
 September 30, 2019
 Level 1 Level 2 Level 3
 (In thousands)
Assets:     
Derivative Instruments$—
 $157,990
 $—
Liabilities:     
Derivative Instruments$—
 $72,469
 $—
December 31, 2019
Level 1Level 2Level 3
(In thousands)
Assets:
Derivative Instruments$— $126,764 $— 
Liabilities:
Derivative Instruments$— $53,438 $— 


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 December 31, 2018
 Level 1 Level 2 Level 3
 (In thousands)
Assets:     
Derivative Instruments$—
 $21,352
 $—
Liabilities:     
Derivative Instruments$—
 $34,393
 $—

The Company estimates the fair value of all derivative instruments using industry-standard models that consider various assumptions, including current market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data.
As discussed in Note 3, the water infrastructure sale included a contingent consideration arrangement. As of June 30, 2020, the fair value of the contingent consideration was $19.8 million, of which $0.8 million is included in prepaid expenses and other assets and $19.0 million is included in other assets in the accompanying consolidated balance sheets. The fair value of the contingent consideration arrangement is calculated using discounted cash flow techniques and is based on internal estimates of the Company's investmentfuture development program and water production levels. Given the unobservable nature of the inputs, the fair value measurement of the contingent consideration arrangement is deemed to use Level 3 inputs. The Company has elected the fair value option for this contingent consideration arrangement and, therefore, records changes in Mammoth Energy asfair value in earnings. The Company recognized a loss of September$3.2 million and $3.0 million on changes in fair value of the contingent consideration during the three and six months ended June 30, 2019 was estimated using Level 1 inputs, as 2020, respectively, which is included in other expense (income) in
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the price per share was a quoted price in an active market for identical Mammoth Energy common shares.accompanying consolidated statements of operations. Settlements under the contingent consideration arrangement totaled $0.3 million during the six months ended June 30, 2020.
The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 2 for further discussion of the Company’s asset retirement obligations. Asset retirement obligations incurred during the ninesix months ended SeptemberJune 30, 20192020 were approximately $5.8 million.$1.6 million.
Fair value of financial instruments
11.FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts on the accompanying consolidated balance sheet for cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, and current debt are carried at cost, which approximates market value due to their short-term nature. Long-term debt related to the Company's construction loan is carried at cost, which approximates market value based on the borrowing rates currently available to the Company with similar terms and maturities.
At September 30, 2019, the carrying value of the outstanding debt represented by the Notes was approximately $1.9 billion, including the unamortized debt issuance cost of approximately $3.6 million related to the 2023 Notes, approximately $7.5 million related to the 2024 Notes, approximately $10.8 million related to the 2025 Notes and approximately $4.0 million related to the 2026 Notes. Based on the quoted market price, the fair value of the Notes was determined to be approximately $1.4 billion at September 30, 2019.
12.REVENUE FROM CONTRACTS WITH CUSTOMERS
12.REVENUE FROM CONTRACTS WITH CUSTOMERS
Revenue Recognition
The Company’s revenues are primarily derived from the sale of natural gas, oil and condensate and NGLs.NGL. Sales of natural gas, oil and condensate and NGLsNGL are recognized in the period that the performance obligations are satisfied. The Company generally considers the delivery of each unit (MMBtu or Bbl) to be separately identifiable and represents a distinct performance obligation that is satisfied at the time control of the product is transferred to the customer. Revenue is measured based on consideration specified in the contract with the customer, and excludes any amounts collected on behalf of third parties. These contracts typically include variable consideration that is based on pricing tied to market indices and volumes delivered in the current month. As such, this market pricing may be constrained (i.e., not estimable) at the inception of the contract but will be recognized based on the applicable market pricing, which will be known upon transfer of the goods to the customer. The payment date is usually within 30 days of the end of the calendar month in which the commodity is delivered.
Transaction Price Allocated to Remaining Performance Obligations
A significant number of the Company's product sales are short-term in nature generally through evergreen contracts with contract terms of one year or less,less. These contracts typically automatically renew under the same provisions. For those contracts, the Company has utilized the practical expedient allowed in the new revenue accounting standard that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.
For product sales that have a contract term greater than one year, the Company has utilized the practical expedient that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Currently, the Company's product sales that have a contractual term greater than one year have no long-term fixed consideration.
Contract Balances
Receivables from contracts with customers are recorded when the right to consideration becomes unconditional, generally when control of the product has been transferred to the customer. Receivables from contracts with customers were $112.7

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million$65.6 and $210.2$121.2 million as of SeptemberJune 30, 20192020 and December 31, 2018,2019, respectively, and are reported in accounts receivable - oil and natural gas sales on the consolidated balance sheets. The Company currently has no assets or liabilities related to its revenue contracts, including no upfront or rights to deficiency payments.
Prior-Period Performance Obligations
The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain sales may be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to
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estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The differences between the estimates and the actual amounts for product sales is recorded in the month that payment is received from the purchaser. For the ninesix months ended SeptemberJune 30, 2019,2020, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

13.LEASES
Effective January 1, 2019, the Company adopted ASU No. 2016-02, 13.Leases (Topic 842). The new standard supersedes the previous lease guidance by requiring lessees to recognize a right-of-use asset and lease liability on the balance sheet for all leases with lease terms of greater than one year while maintaining substantially similar classifications for financing and operating leases. The Company adopted the new standard on a prospective basis using the simplified transition method permitted by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements. Offsetting right-of-use assets and corresponding lease liabilities recognized by the Company on the adoption date totaled approximately $110 million, representing minimum payment obligations associated with identified leases with contractual durations exceeding one year. NaN cumulative-effect adjustment to retained earnings was required upon adoption of the new standard. The Company elected the package of practical expedients permitted under the new standard, which among other things, allows for lease and non-lease components in a contract to be accounted for as a single lease component for all asset classes and the carry forward of historical lease classifications.LEASES
Nature of Leases
The Company has operating leases associated with drilling rig commitments, pressure pumping services, field offices and other equipment with remaining lease terms with contractual durations in excess of one year. Short-term leases that have an initial term of one year or less are not capitalized.
The Company has entered into contractsa contract for a drilling rigsrig with a third partiesparty to ensure rig availability in its key operating areas.availability. The Company has concluded its drilling rig contracts are operating leases as the assets are identifiable and the evaluation that the Company has the right to control the identified assets. The Company's drilling rig commitments are typically structured with an initial term of one to two years, and expire at various dates through 2021. These agreements typically include renewal options at the end of the initial term. Due to the nature of the Company's drilling schedules and potential volatility in commodity prices, the Company is unable to determine at commencement with reasonable certainty if the renewal options will be exercised; therefore, renewal options are not considered in the lease term for drilling contracts. The operating lease liabilitiesliability associated with theseits rig commitments arecommitment is based on the minimum contractual obligations,obligation, primarily standby rates,rate, and dodoes not include variable amounts based on actual activity in a given period. The Company has also entered into several drilling rig commitments with an initial term less than one year. The costs for these short-term rig commitments are included in the short-term lease cost for the period as shown below. Pursuant to the full cost method of accounting, these costs are capitalized as part of oil and natural gas properties on the accompanying consolidated balance sheets. A portion of these costs are borne by other interest owners.
Effective October 1, 2014, the Company entered into an Amended and Restated Master Services Agreement for pressure pumping services with Stingray Pressure Pumping LLC (“Stingray Pressure”), a subsidiary of Mammoth Energy and a related party. Pursuant to this agreement, as amended effective July 1, 2018, Stingray Pressure has agreed to provide hydraulic fracturing, stimulation and related completion and rework services to the Company through 2021 and the Company has agreed to pay Stingray Pressure a monthly service fee plus the associated costs of the services provided. TheAs discussed further in Note 9, the Company has terminated the Master Services Agreement for pressure pumping with Stingray Pressure. As a result, in the first quarter of 2020, Gulfport has removed the related right to suspend services of one crewuse assets and only one crew at any point in time without payment, fee or other obligationlease liabilities associated with the suspended crew, given appropriate notification of suspension. The Company has determined that the agreement with Stingray Pressure is an operating lease due to the implicit identification of assets and the evaluation that the Company has the right to control the identified assets. The operating lease liability associated with this agreement is based on the minimum contractual obligations, which is the monthly service fee for one crew, and does not include variable amounts based on actual activity in a given period. Pursuant to the full cost method of accounting, these costs are capitalized as part of oil and natural gas properties on the accompanying consolidated balance sheets. A portion of these costs are borne by other interest owners.terminated contract.

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The Company rents office space for its field locations and certain other equipment from third parties, which expire at various dates through 2024. These agreements are typically structured with non-cancelable terms of one to five years. The Company has determined these agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. The Company has included any renewal options that it has determined are reasonably certain of exercise in the determination of the lease terms.
Discount Rate
As most of the Company's leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The Company's incremental borrowing rate reflects the estimated rate of interest that it would pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment.
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Maturities of operating lease liabilities as of SeptemberJune 30, 20192020 were as follows:
  (In thousands)
Remaining 2019 $10,190
2020 31,460
2021 22,731
2022 115
2023 90
Thereafter 30
Total lease payments $64,616
Less: Imputed interest (2,247)
Total $62,369

(In thousands)
Remaining 2020$3,321  
2021129  
2022115  
202390  
202430  
Total lease payments$3,685  
Less: Imputed interest(45) 
Total$3,640  
Lease cost for the three and ninesix months ended SeptemberJune 30, 2020 and 2019 consisted of the following:
 Three months ended September 30, Nine months ended September 30,
 2019 2019
 (In thousands)
Operating lease cost$4,551
 $20,835
Operating lease cost - related party5,610
 16,830
Variable lease cost105
 1,065
Variable lease cost - related party5,357
 64,968
Short-term lease cost224
 407
Total lease cost(1)
$15,847
 $104,105
Three months ended June 30,Six months ended June 30,
2020201920202019
(In thousands)
Operating lease cost$2,196  $7,748  $6,278  $16,284  
Operating lease cost—related party—  5,610  —  11,220  
Variable lease cost235  531  460  960  
Variable lease cost—related party—  28,158  —  59,611  
Short-term lease cost2,629  183  5,439  183  
Total lease cost(1)
$5,060  $42,230  $12,177  $88,258  
(1)The majority of the Company's total lease cost was capitalized to the full cost pool, and the remainder was included in general and administrative expenses in the accompanying consolidated statements of operations.
Supplemental cash flow information for the ninesix months ended SeptemberJune 30, 2020 and 2019 related to leases was as follows:
Cash paid for amounts included in the measurement of lease liabilities (In thousands)
     Operating cash flows from operating leases $146
     Investing cash flow from operating leases $18,998
     Investing cash flow from operating leases - related party $78,518


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Six months ended June 30,
20202019
Cash paid for amounts included in the measurement of lease liabilities(In thousands)
     Operating cash flows from operating leases$72  $120  
     Investing cash flow from operating leases$7,727  $12,288  
     Investing cash flow from operating leases—related party$6,800  $43,925  
The weighted-average remaining lease term as of SeptemberJune 30, 20192020 was 1.820.83 years. The weighted-average discount rate used to determine the operating lease liability as of SeptemberJune 30, 20192020 was 3.66%2.47%.
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14.INCOME TAXES

14.INCOME TAXES
The Company records its quarterly tax provision based on an estimate of the annual effective tax rate expected to apply to continuing operations for the various jurisdictions in which it operates. The tax effects of certain items, such as tax rate changes, significant unusual or infrequent items, and certain changes in the assessment of the realizability of deferred taxes, are recognized as discrete items in the period in which they occur and are excluded from the estimated annual effective tax rate.

For the three and six months ended June 30, 2020, the Company's estimated annual effective tax rate before discrete items remained near zero as a result of the valuation allowance on its deferred tax assets. During the first quarter of 2020, the Company recognized $7.3 million of income tax expense discretely in the quarter as a result of the sale of assets and a corresponding adjustment to the valuation allowance on remaining state net operating loss carryforwards.

The Company anticipates remaining in a net deferred tax position based on the analysis performed for three and six months ended June 30, 2020. The Company expects a full valuation allowance against its deferred tax assets based on its conclusion, considering all available evidence (both positive and negative), that it was more likely than not that the deferred tax assets would not be realized. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. To assess that likelihood, the Company uses estimates and judgment regarding future taxable income, and considers the tax laws in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities and tax planning strategies as well as the current and forecasted business economics of the oil and gas industry.

On March 27, 2020, the CARES Act was enacted in response to the COVID-19 pandemic. The Act includes several significant provisions for corporations including allowing companies to carryback certain NOLs, increasing the amount of NOLs that corporations can use to offset income, and increasing the amount of deductible interest under section 163(j). The Company does not expect to be materially impacted by the CARES Act provision and does not anticipate the CARES Act to have a material effect on its ability to realized deferred tax assets.

The Company’s ability to utilize NOL carryforwards and other tax attributes to reduce future federal taxable income is subject to potential limitations under Internal Revenue Code Section 382 (“Section 382”) and its related tax regulations. The utilization of these attributes may be limited if certain ownership changes by 5% stockholders (as defined in Treasury regulations pursuant to Section 382) and the effects of stock issuances by the Company during any three-year period result in a cumulative change of more than 50% in the beneficial ownership of Gulfport. The Company updates its Section 382 analysis to determine if an ownership change has occurred at each reporting period. If it is determined that an ownership change has occurred under these rules, the Company would generally be subject to an annual limitation on the use of pre-ownership change NOL carryforwards and certain other losses and/or credits. In addition, certain future transactions regarding the Company's equity, including the cumulative effects of small transactions as well as transactions beyond the Company’s control, could cause an ownership change and therefore a potential limitation on the annual utilization of its deferred tax assets.
For On April 30, 2020, the three month period ended March 31, 2019,board of directors of the Company maintainedadopted a full valuation allowancetax benefits preservation plan in order to protect against its deferred tax assets baseda possible limitation on its conclusion, considering all available evidence (both positive and negative), that it was more likely than not that the deferred tax assets would not be realized. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. To assess that likelihood, the Company uses estimates and judgment regarding future taxable income, and considers the tax laws in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities and tax planning strategies as well as the current and forecasted business economics of the oil and gas industry.

As of June 30, 2019, in part because in the current year the Company achieved more than three years of cumulative pretax income in the U.S. federal tax jurisdiction and the Company determined that an ownership change under Internal Revenue Code Section 382 did not occur that would further limit its ability to utilize net operating loss carryforwards, management determined that there was sufficient positive evidence to conclude that it is more likely than not that additional deferred taxes of $207.4 million are realizable.

For the three and nine months ended September 30, 2019, the Company recognized $28.0 million and $207.4 million as a discrete tax benefit in the respective periods. It therefore reduced the valuation allowance accordingly and maintains a valuation allowance of $4.8 million related to foreign tax credits, general business credits and net operating losses in jurisdictions for which it has determined that it is more likely than not that deferred tax assets would not be realized before expiration.

As of each reporting date, management considers new evidence, both positive and negative, that could affect its view of the future realization of deferred tax assets. This assessment relies upon a number of areas of management’s judgment regarding forecast of results in subsequent years. Changes in those judgments could require the Company to establish a valuation allowance for currently recognized deferred tax assets in a subsequent reporting period. In addition, if the Company incurred an Internal Revenue Code Section 382 ownership change it would significantly limit the Company’s ability to utilizeuse its tax net operating loss carryforwardslosses and certain other tax attributes.

For the three and nine months ended September 30, 2019, the Company's estimated annual effectivebenefits to reduce potential future U.S. federal income tax rates were approximately 273.4% and (62.1)%, respectively.obligations. The effective tax rate variesTax Benefits Preservation Plan is intended to prevent against such an ownership change by deterring any person or group from the expected statutory tax rateacquiring beneficial ownership of 21% primarily because4.9% or more of the release of the valuation allowance of $207.4 million for the nine months ended September 30, 2019. The Company also recognized tax expense of $1.6 million and $1.7 million for the three and nine months ended September 30, 2019, respectively, related to equity compensation book amounts that exceed the tax deduction.Company’s securities.

15.CONDENSED CONSOLIDATING FINANCIAL INFORMATION

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15.CONDENSED CONSOLIDATING FINANCIAL INFORMATION
The 2023 Notes, the 2024 Notes, the 2025 Notes and the 2026 Notes are guaranteed on a senior unsecured basis by all existing consolidated subsidiaries that guarantee the Company’s secured revolving credit facility or certain other debt (the “Guarantors”). The Notes are not guaranteed by Grizzly Holdings or Mule Sky LLC ("Mule Sky") (the “Non-Guarantors”). The Guarantors are 100% owned by Gulfport (the “Parent”), and the guarantees are full, unconditional, joint and several. There are no significant restrictions on the ability of the Parent or the Guarantors to obtain funds from each other in the form of a dividend or loan. Effective June 1, 2019, the Parent contributed interests in certain oil and gas assets and related liabilities to certain of the Guarantors.
The following condensed consolidating balance sheets, statements of operations, statements of comprehensive income and statements of cash flows are provided for the Parent, the Guarantors and the Non-Guarantors and include the consolidating adjustments and eliminations necessary to arrive at the information for the Company on a condensed consolidated basis. The information has been presented using the equity method of accounting for the Parent’s ownership of the Guarantors and the Non-Guarantors.


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CONDENSED CONSOLIDATING BALANCE SHEETS
(Amounts in thousands)
 September 30, 2019
 Parent Guarantors Non-Guarantors Eliminations Consolidated
Assets         
Current assets:         
Cash and cash equivalents$6,279
 $3,715
 $130
 $—
 $10,124
Accounts receivable - oil and natural gas sales857
 111,800
 —
 —
 112,657
Accounts receivable - joint interest and other6,909
 34,418
 —
 —
 41,327
Accounts receivable - intercompany953,446
 625,306
 —
 (1,578,752) —
Prepaid expenses and other current assets3,886
 1,697
 75
 —
 5,658
Short-term derivative instruments134,571
 —
 —
 —
 134,571
Total current assets1,105,948
 776,936
 205
 (1,578,752) 304,337
          
Property and equipment:         
Oil and natural gas properties, full-cost accounting1,312,715
 9,239,581
 146
 (729) 10,551,713
Other property and equipment92,163
 751
 3,319
 —
 96,233
Accumulated depletion, depreciation, amortization and impairment(1,416,261) (3,646,931) (221) —
 (5,063,413)
Property and equipment, net(11,383) 5,593,401
 3,244
 (729) 5,584,533
Other assets:         
Equity investments and investments in subsidiaries5,106,904
 —
 49,545
 (5,082,487) 73,962
Long-term derivative instruments23,419
 —
 —
 —
 23,419
Deferred tax asset205,853
 —
 —
 —
 205,853
Inventories94
 6,928
 —
 —
 7,022
Operating lease assets13,920
 —
 —
 —
 13,920
Operating lease assets - related parties48,449
 —
 —
 —
 48,449
Other assets11,333
 320
 —
 —
 11,653
Total other assets5,409,972
 7,248
 49,545
 (5,082,487) 384,278
Total assets$6,504,537
 $6,377,585
 $52,994
 $(6,661,968) $6,273,148
          
Liabilities and Stockholders’ Equity
         
Current liabilities:         
Accounts payable and accrued liabilities$69,863
 $369,129
 $27
 $—
 $439,019
Accounts payable - intercompany660,364
 914,401
 3,987
 (1,578,752) —
Short-term derivative instruments429
 —
 —
 —
 429
Current portion of operating lease liabilities12,848
 —
 —
 —
 12,848
Current portion of operating lease liabilities - related parties21,017
 —
 —
 —
 21,017
Current maturities of long-term debt622
 —
 —
 —
 622
Total current liabilities765,143
 1,283,530
 4,014
 (1,578,752) 473,935
Long-term derivative instruments72,040
 —
 —
 —
 72,040
Asset retirement obligation - long-term—
 59,819
 —
 —
 59,819
Uncertain tax position liability3,127
 —
 —
 —
 3,127
Non-current operating lease liabilities1,072
 —
 —
 —
 1,072
Non-current operating lease liabilities - related parties27,432
 —
 —
 —
 27,432
Long-term debt, net of current maturities2,076,569
 —
 —
 —
 2,076,569
Total liabilities2,945,383
 1,343,349
 4,014
 (1,578,752) 2,713,994
          
Stockholders’ equity:         
Common stock1,597
 —
 —
 —
 1,597
Paid-in capital4,205,158
 4,170,573
 262,061
 (4,432,634) 4,205,158
Accumulated other comprehensive loss(50,679) —
 (48,548) 48,548
 (50,679)
(Accumulated deficit) retained earnings(596,922) 863,663
 (164,533) (699,130) (596,922)
Total stockholders’ equity3,559,154
 5,034,236
 48,980
 (5,083,216) 3,559,154
Total liabilities and stockholders’ equity
$6,504,537
 $6,377,585
 $52,994
 $(6,661,968) $6,273,148


June 30, 2020
ParentGuarantorsNon-GuarantorsEliminationsConsolidated
Assets
Current assets:
Cash and cash equivalents$823  $1,748  $246  $—  $2,817  
Accounts receivable - oil and natural gas sales860  64,785  —  —  65,645  
Accounts receivable - joint interest and other2,949  16,440  —  —  19,389  
Accounts receivable - intercompany1,482,102  1,150,631  —  (2,632,733) —  
Prepaid expenses and other current assets10,781  5  76  —  10,862  
Short-term derivative instruments53,188  —  —  —  53,188  
Total current assets1,550,703  1,233,609  322  (2,632,733) 151,901  
Property and equipment:
Oil and natural gas properties, full-cost accounting1,247,631  9,478,228  5,862  (729) 10,730,992  
Other property and equipment92,768  51  4,019  —  96,838  
Accumulated depletion, depreciation, amortization and impairment(1,423,539) (7,032,075) (1,850) —  (8,457,464) 
Property and equipment, net(83,140) 2,446,204  8,031  (729) 2,370,366  
Other assets:
Equity investments and investments in subsidiaries1,930,479  6,332  13,013  (1,936,772) 13,052  
Long-term derivative instruments4,298  —  —  —  4,298  
Operating lease assets3,640  —  —  —  3,640  
Other assets29,216  7,784  —  —  37,000  
Total other assets1,967,633  14,116  13,013  (1,936,772) 57,990  
Total assets$3,435,196  $3,693,929  $21,366  $(4,570,234) $2,580,257  
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities$46,085  $269,490  $—  $—  $315,575  
Accounts payable - intercompany1,185,800  1,442,144  4,789  (2,632,733) —  
Short-term derivative instruments8,540  —  —  —  8,540  
Current portion of operating lease liabilities3,356  —  —  —  3,356  
Current maturities of long-term debt649  —  —  —  649  
Total current liabilities1,244,430  1,711,634  4,789  (2,632,733) 328,120  
Long-term derivative instruments45,615  —  —  —  45,615  
Asset retirement obligation - long-term—  61,371  —  —  61,371  
Uncertain tax position liability3,209  —  —  —  3,209  
Non-current operating lease liabilities284  —  —  —  284  
Long-term debt, net of current maturities1,910,318  —  —  —  1,910,318  
Total liabilities3,203,856  1,773,005  4,789  (2,632,733) 2,348,917  
Stockholders’ equity:
Common stock1,601  —  —  —  1,601  
Paid-in capital4,211,062  4,171,409  267,559  (4,438,968) 4,211,062  
Accumulated other comprehensive loss(54,991) —  (52,562) 52,562  (54,991) 
Accumulated deficit(3,926,332) (2,250,485) (198,420) 2,448,905  (3,926,332) 
Total stockholders’ equity231,340  1,920,924  16,577  (1,937,501) 231,340  
Total liabilities and stockholders’ equity
$3,435,196  $3,693,929  $21,366  $(4,570,234) $2,580,257  
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CONDENSED CONSOLIDATING BALANCE SHEETS
(Amounts in thousands)
 December 31, 2018
 Parent Guarantors Non-Guarantor Eliminations Consolidated
Assets         
Current assets:         
Cash and cash equivalents$25,585
 $26,711
 $1
 $—
 $52,297
Accounts receivable - oil and natural gas sales146,075
 64,125
 —
 —
 210,200
Accounts receivable - joint interest and other16,212
 6,285
 —
 —
 22,497
Accounts receivable - intercompany671,633
 319,464
 —
 (991,097) —
Prepaid expenses and other current assets7,843
 2,174
 —
 —
 10,017
Short-term derivative instruments21,352
 —
 —
 —
 21,352
Total current assets888,700
 418,759
 1
 (991,097) 316,363
          
Property and equipment:         
Oil and natural gas properties, full-cost accounting,7,044,550
 2,983,015
 —
 (729) 10,026,836
Other property and equipment91,916
 751
 —
 —
 92,667
Accumulated depletion, depreciation, amortization and impairment(4,640,059) (39) —
 —
 (4,640,098)
Property and equipment, net2,496,407
 2,983,727
 —
 (729) 5,479,405
Other assets:         
Equity investments and investments in subsidiaries2,856,988
 —
 44,259
 (2,665,126) 236,121
Inventories4,210
 1,134
 —
 —
 5,344
Other assets12,624
 1,178
 —
 1
 13,803
Total other assets2,873,822
 2,312
 44,259
 (2,665,125) 255,268
  Total assets$6,258,929
 $3,404,798
 $44,260
 $(3,656,951) $6,051,036
          
Liabilities and Stockholders’ Equity
         
Current liabilities:         
Accounts payable and accrued liabilities$419,107
 $99,273
 $—
 $—
 $518,380
Accounts payable - intercompany320,259
 670,708
 130
 (991,097) —
Short-term derivative instruments20,401
 —
 —
 —
 20,401
Current maturities of long-term debt651
 —
 —
 —
 651
Total current liabilities760,418
 769,981
 130
 (991,097) 539,432
Long-term derivative instruments13,992
 —
 —
 —
 13,992
Asset retirement obligation - long-term66,859
 13,093
 —
 —
 79,952
Uncertain tax position liability3,127
 —
 —
 —
 3,127
Long-term debt, net of current maturities2,086,765
 —
 —
 —
 2,086,765
Total liabilities2,931,161

783,074

130

(991,097)
2,723,268
          
Stockholders’ equity:         
Common stock1,630
 —
 —
 —
 1,630
Paid-in capital4,227,532
 1,915,598
 261,626
 (2,177,224) 4,227,532
Accumulated other comprehensive loss(56,026) —
 (53,783) 53,783
 (56,026)
(Accumulated deficit) retained earnings(845,368) 706,126
 (163,713) (542,413) (845,368)
Total stockholders’ equity3,327,768
 2,621,724
 44,130
 (2,665,854) 3,327,768
  Total liabilities and stockholders’ equity
$6,258,929
 $3,404,798
 $44,260
 $(3,656,951) $6,051,036


December 31, 2019
ParentGuarantorsNon-GuarantorEliminationsConsolidated
Assets
Current assets:
Cash and cash equivalents$2,768  $3,097  $195  $—  $6,060  
Accounts receivable - oil and natural gas sales859  120,351  —  —  121,210  
Accounts receivable - joint interest and other5,279  42,696  —  —  47,975  
Accounts receivable - intercompany1,065,593  843,223  —  (1,908,816) —  
Prepaid expenses and other current assets4,047  308  76  —  4,431  
Short-term derivative instruments126,201  —  —  —  126,201  
Total current assets1,204,747  1,009,675  271  (1,908,816) 305,877  
Property and equipment:
Oil and natural gas properties, full-cost accounting,1,314,933  9,273,681  7,850  (729) 10,595,735  
Other property and equipment92,650  50  4,019  —  96,719  
Accumulated depletion, depreciation, amortization and impairment(1,418,888) (5,808,254) (1,518) —  (7,228,660) 
Property and equipment, net(11,305) 3,465,477  10,351  (729) 3,463,794  
Other assets:
Equity investments and investments in subsidiaries3,064,503  6,332  21,000  (3,059,791) 32,044  
Long-term derivative instruments563  —  —  —  563  
Deferred tax asset7,563  —  —  —  7,563  
Operating lease assets14,168  —  —  —  14,168  
Operating lease assets - related parties43,270  —  —  —  43,270  
Other assets10,026  5,514  —  —  15,540  
Total other assets3,140,093  11,846  21,000  (3,059,791) 113,148  
  Total assets$4,333,535  $4,486,998  $31,622  $(4,969,336) $3,882,819  
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities$48,006  $367,088  $124  $—  $415,218  
Accounts payable - intercompany878,283  1,026,249  4,285  (1,908,817) —  
Short-term derivative instruments303  —  —  —  303  
Current portion of operating lease liabilities13,826  —  —  —  13,826  
Current portion of operating lease liabilities - related parties21,220  —  —  —  21,220  
Current maturities of long-term debt631  —  —  —  631  
Total current liabilities962,269  1,393,337  4,409  (1,908,817) 451,198  
Long-term derivative instruments53,135  —  —  —  53,135  
Asset retirement obligation - long-term—  58,322  2,033  —  60,355  
Uncertain tax position liability3,127  —  —  —  3,127  
Non-current operating lease liabilities342  —  —  —  342  
Non-current operating lease liabilities - related parties22,050  —  —  —  22,050  
Long-term debt, net of current maturities1,978,020  —  —  —  1,978,020  
Total liabilities3,018,943  1,451,659  6,442  (1,908,817) 2,568,227  
Stockholders’ equity:
Common stock1,597  —  —  —  1,597  
Paid-in capital4,207,554  4,171,408  267,557  (4,438,965) 4,207,554  
Accumulated other comprehensive loss(46,833) —  (44,763) 44,763  (46,833) 
Accumulated deficit(2,847,726) (1,136,069) (197,614) 1,333,683  (2,847,726) 
Total stockholders’ equity1,314,592  3,035,339  25,180  (3,060,519) 1,314,592  
  Total liabilities and stockholders’ equity
$4,333,535  $4,486,998  $31,622  $(4,969,336) $3,882,819  

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CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(Amounts in thousands)
Three months ended June 30, 2020
ParentGuarantorsNon-GuarantorsEliminationsConsolidated
Total revenues$26,970  $105,440  $—  $—  $132,410  
Costs and expenses:
Lease operating expenses—  15,686  —  —  15,686  
Production taxes—  3,605  —  —  3,605  
Midstream gathering and processing expenses—  59,974  —  —  59,974  
Depreciation, depletion and amortization2,388  62,236  166  —  64,790  
Impairment of oil and natural gas properties—  532,880  —  —  532,880  
General and administrative expenses21,731  (11,374) 113  —  10,470  
Accretion expense—  755  —  —  755  
Total Operating Expenses24,119  663,762  279  —  688,160  
INCOME (LOSS) FROM OPERATIONS2,851  (558,322) (279) —  (555,750) 
OTHER EXPENSE (INCOME):
Interest expense32,825  (459) —  —  32,366  
Interest income(28) (50) —  —  (78) 
Gain on debt extinguishment(34,257) —  —  —  (34,257) 
Loss from equity method investments and investments in subsidiaries562,502  —  45  (562,502) 45  
Other expense2,877  4,365  —  —  7,242  
Total Other Expense563,919  3,856  45  (562,502) 5,318  
LOSS BEFORE INCOME TAXES(561,068) (562,178) (324) 562,502  (561,068) 
INCOME TAX EXPENSE—  —  —  —  —  
NET LOSS$(561,068) $(562,178) $(324) $562,502  $(561,068) 
 Three months ended September 30, 2019
 Parent Guarantors Non-Guarantors Eliminations Consolidated
          
Total revenues$27,358
 $257,817
 $—
 $—
 $285,175
          
Costs and expenses:         
Lease operating expenses(231) 22,704
 —
 —
 22,473
Production taxes36
 6,529
 —
 —
 6,565
Midstream gathering and processing expenses—
 78,435
 —
 —
 78,435
Depreciation, depletion and amortization2,699
 142,625
 166
 —
 145,490
Impairment of oil and natural gas properties—
 35,647
 —
 —
 35,647
General and administrative expenses27,218
 (12,675) 116
 —
 14,659
Accretion expense—
 747
 —
 —
 747
 29,722

274,012

282

—

304,016
          
LOSS FROM OPERATIONS(2,364)
(16,195)
(282)
—

(18,841)
          
OTHER EXPENSE (INCOME):         
Interest expense35,105
 (1,010) —
 —
 34,095
Interest income(187) (151) —
 —
 (338)
Gain on debt extinguishment(23,600) —
 —
 —
 (23,600)
Loss from equity method investments and investments in subsidiaries62,760
 —
 40
 (19,718) 43,082
Other (income) expense(1,168) 3,362
 —
 1,000
 3,194
 72,910

2,201

40

(18,718)
56,433
          
LOSS BEFORE INCOME TAXES(75,274) (18,396) (322) 18,718
 (75,274)
INCOME TAX BENEFIT(26,522) —
 —
 —
 (26,522)
          
NET LOSS$(48,752)
$(18,396)
$(322)
$18,718

$(48,752)



30
Table of Contents


CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(Amounts in thousands)

Three months ended June 30, 2019
ParentGuarantorsNon-GuarantorEliminationsConsolidated
Total revenues$280,291  $178,703  $—  $—  $458,994  
Costs and expenses:
Lease operating expenses12,256  10,132  —  —  22,388  
Production taxes2,820  5,278  —  —  8,098  
Midstream gathering and processing expenses28,121  43,894  —  —  72,015  
Depreciation, depletion and amortization80,132  44,764  55  —  124,951  
General and administrative expenses15,207  (3,583) 103  —  11,727  
Accretion expense438  921  —  —  1,359  
Total Operating Expenses138,974  101,406  158  —  240,538  
INCOME (LOSS) FROM OPERATIONS141,317  77,297  (158) —  218,456  
OTHER EXPENSE (INCOME):
Interest expense37,373  (955) —  —  36,418  
Interest income(120) (39) —  —  (159) 
Loss (income) from equity method investments and investments in subsidiaries47,449  —  (54) 78,187  125,582  
Other expense990  —  —  —  990  
Total Other Expense (Income)85,692  (994) (54) 78,187  162,831  
INCOME (LOSS) BEFORE INCOME TAXES55,625  78,291  (104) (78,187) 55,625  
INCOME TAX BENEFIT(179,331) —  —  —  (179,331) 
NET INCOME (LOSS)$234,956  $78,291  $(104) $(78,187) $234,956  
 Three months ended September 30, 2018
 Parent Guarantors Non-Guarantor Eliminations Consolidated
          
Total revenues$235,683
 $125,279
 $—
 $—
 $360,962
          
Costs and expenses:         
Lease operating expenses16,502
 5,823
 —
 —
 22,325
Production taxes4,505
 4,843
 —
 —
 9,348
Midstream gathering and processing expenses54,397
 24,516
 —
 —
 78,913
Depreciation, depletion and amortization119,914
 1
 —
 —
 119,915
General and administrative expenses16,314
 (467) 1
 —
 15,848
Accretion expense812
 225
 —
 —
 1,037
 212,444

34,941

1

—

247,386
          
INCOME (LOSS) FROM OPERATIONS23,239

90,338

(1)
—

113,576
          
OTHER (INCOME) EXPENSE:         
Interest expense34,254
 (1,001) —
 —
 33,253
Interest income(86) (6) —
 —
 (92)
Gain on sale of equity method investments(2,733) —
 —
 —
 (2,733)
(Income) loss from equity method investments and investments in subsidiaries(104,226) (1) 275
 91,094
 (12,858)
Other expense (income)880
 (24) —
 —
 856
 (71,911) (1,032) 275
 91,094
 18,426
          
INCOME (LOSS) BEFORE INCOME TAXES95,150

91,370

(276)
(91,094)
95,150
INCOME TAX BENEFIT—
 —
 —
 —
 —
          
NET INCOME (LOSS)$95,150
 $91,370
 $(276) $(91,094) $95,150



31
Table of Contents


CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(Amounts in thousands)

Six months ended June 30, 2020
ParentGuarantorsNon-GuarantorsEliminationsConsolidated
Total revenues$125,238  $254,049  $—  $—  $379,287  
Costs and expenses:
Lease operating expenses—  31,672  —  —  31,672  
Production taxes—  8,404  —  —  8,404  
Midstream gathering and processing expenses—  117,870  —  —  117,870  
Depreciation, depletion, and amortization4,890  137,596  332  —  142,818  
Impairment of oil and gas properties—  1,086,225  —  —  1,086,225  
General and administrative expenses46,377  (20,024) 286  —  26,639  
Accretion expense—  1,496  —  —  1,496  
Total Operating Expenses51,267  1,363,239  618  —  1,415,124  
INCOME (LOSS) FROM OPERATIONS73,971  (1,109,190) (618) —  (1,035,837) 
OTHER EXPENSE (INCOME):
Interest expense66,002  (646) —  —  65,356  
Interest income(87) (143) —  —  (230) 
Gain on debt extinguishment(49,579) —  —  —  (49,579) 
Loss from equity method investments and investments in subsidiaries1,125,868  —  188  (1,115,222) 10,834  
Other expense3,083  6,015  —  —  9,098  
Total Other Expense1,145,287  5,226  188  (1,115,222) 35,479  
LOSS BEFORE INCOME TAXES(1,071,316) (1,114,416) (806) 1,115,222  (1,071,316) 
INCOME TAX EXPENSE7,290  —  —  —  7,290  
NET LOSS$(1,078,606) $(1,114,416) $(806) $1,115,222  $(1,078,606) 
 Nine months ended September 30, 2019
 Parent Guarantors Non-Guarantors Eliminations Consolidated
          
Total revenues$493,895
 $570,852
 $—
 $—
 $1,064,747
          
Costs and expenses:         
Lease operating expenses26,918
 37,750
 —
 —
 64,668
Production taxes6,117
 16,467
 —
 —
 22,584
Midstream gathering and processing expenses71,420
 149,312
 —
 —
 220,732
Depreciation, depletion, and amortization201,263
 187,390
 221
 —
 388,874
Impairment of oil and gas properties—
 35,647
 —
 —
 35,647
General and administrative expenses56,195
 (16,933) 220
 —
 39,482
Accretion expense1,389
 1,784
 —
 —
 3,173
 363,302
 411,417
 441
 —
 775,160
          
INCOME (LOSS) FROM OPERATIONS130,593
 159,435
 (441) —
 289,587
          
OTHER EXPENSE (INCOME):         
Interest expense105,364
 (2,269) —
 —
 103,095
Interest income(454) (195) —
 —
 (649)
Gain on debt extinguishment(23,600) —
 —
 —
 (23,600)
Loss from equity method investments and investments in subsidiaries7,295
 —
 379
 156,717
 164,391
Other (income) expense(605) 3,362
 —
 1,000
 3,757
 88,000
 898
 379
 157,717
 246,994
          
INCOME (LOSS) BEFORE INCOME TAXES42,593
 158,537
 (820) (157,717) 42,593
INCOME TAX BENEFIT(205,853) —
 —
 —
 (205,853)
          
NET INCOME (LOSS)$248,446
 $158,537
 $(820) $(157,717) $248,446



32
Table of Contents


CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(Amounts in thousands)

Six months ended June 30, 2019
ParentGuarantorsNon-GuarantorEliminationsConsolidated
Total revenues$466,537  $313,035  $—  $—  $779,572  
Costs and expenses:
Lease operating expenses27,149  15,046  —  —  42,195  
Production taxes6,081  9,938  —  —  16,019  
Midstream gathering and processing expenses71,420  70,877  —  —  142,297  
Depreciation, depletion, and amortization198,564  44,765  55  —  243,384  
General and administrative expenses25,938  (4,258) 104  —  21,784  
Accretion expense1,389  1,037  —  —  2,426  
Total Operating Expenses330,541  137,405  159  —  468,105  
INCOME (LOSS) FROM OPERATIONS135,996  175,630  (159) —  311,467  
OTHER EXPENSE (INCOME):
Interest expense73,298  (1,259) —  —  72,039  
Interest income(267) (44) —  —  (311) 
(Income) loss from equity method investments and investments in subsidiaries(55,465) —  339  176,435  121,309  
Other expense563  —  —  —  563  
Total Other Expense (Income)18,129  (1,303) 339  176,435  193,600  
INCOME (LOSS) BEFORE INCOME TAXES117,867  176,933  (498) (176,435) 117,867  
INCOME TAX BENEFIT(179,331) —  —  —  (179,331) 
NET INCOME (LOSS)$297,198  $176,933  $(498) $(176,435) $297,198  
 Nine months ended September 30, 2018
 Parent Guarantors Non-Guarantor Eliminations Consolidated
          
Total revenues$596,018
 $343,076
 $—
 $—
 $939,094
          
Costs and expenses:         
Lease operating expenses46,926
 17,217
 —
 —
 64,143
Production taxes13,309
 10,552
 —
 —
 23,861
Midstream gathering and processing expenses152,605
 61,941
 —
 —
 214,546
Depreciation, depletion, and amortization352,846
 2
 —
 —
 352,848
General and administrative expenses45,100
 (2,148) 3
 —
 42,955
Accretion expense2,397
 659
 —
 —
 3,056
 613,183
 88,223
 3
 —
 701,409
          
(LOSS) INCOME FROM OPERATIONS(17,165) 254,853
 (3) —
 237,685
          
OTHER (INCOME) EXPENSE:         
Interest expense103,310
 (2,388) —
 —
 100,922
Interest income(144) (18) —
 —
 (162)
Gain on sale of equity method investments(28,349) (96,419) —
 —
 (124,768)
(Income) loss from equity method investments and investments in subsidiaries(387,991) (694) 833
 352,570
 (35,282)
Other (income) expense(481) (34) —
 1,000
 485
 (313,655) (99,553) 833
 353,570
 (58,805)
          
INCOME (LOSS) BEFORE INCOME TAXES296,490
 354,406
 (836) (353,570) 296,490
INCOME TAX BENEFIT(69) —
 —
 —
 (69)
          
NET INCOME (LOSS)$296,559
 $354,406
 $(836) $(353,570) $296,559



33
Table of Contents


CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Amounts in thousands)
Three months ended June 30, 2020
ParentGuarantorsNon-GuarantorsEliminationsConsolidated
Net loss$(561,068) $(562,178) $(324) $562,502  $(561,068) 
Foreign currency translation adjustment6,872  —  6,872  (6,872) 6,872  
Other comprehensive loss6,872  —  6,872  (6,872) 6,872  
Comprehensive loss$(554,196) $(562,178) $6,548  $555,630  $(554,196) 
 Three months ended September 30, 2019
 Parent Guarantors Non-Guarantors Eliminations Consolidated
          
Net loss$(48,752) $(18,396) $(322) $18,718
 $(48,752)
Foreign currency translation adjustment(2,064) (43) (2,021) 2,064
 (2,064)
Other comprehensive loss(2,064) (43) (2,021) 2,064
 (2,064)
Comprehensive loss$(50,816) $(18,439) $(2,343) $20,782
 $(50,816)


Three months ended June 30, 2019
ParentGuarantorsNon-GuarantorEliminationsConsolidated
Net income (loss)$234,956  $78,291  $(104) $(78,187) $234,956  
Foreign currency translation adjustment3,610  61  3,549  (3,610) 3,610  
Other comprehensive income3,610  61  3,549  (3,610) 3,610  
Comprehensive income$238,566  $78,352  $3,445  $(81,797) $238,566  

 Three months ended September 30, 2018
 Parent Guarantors Non-Guarantor Eliminations Consolidated
          
Net income (loss)$95,150
 $91,370
 $(276) $(91,094) $95,150
Foreign currency translation adjustment3,052
 103
 2,949
 (3,052) 3,052
Other comprehensive income3,052
 103
 2,949
 (3,052) 3,052
Comprehensive income$98,202
 $91,473
 $2,673
 $(94,146) $98,202


Six months ended June 30, 2020
ParentGuarantorsNon-GuarantorsEliminationsConsolidated
Net loss$(1,078,606) $(1,114,416) $(806) $1,115,222  $(1,078,606) 
Foreign currency translation adjustment(8,158) (360) (7,798) 8,158  (8,158) 
Other comprehensive loss(8,158) (360) (7,798) 8,158  (8,158) 
Comprehensive loss$(1,086,764) $(1,114,776) $(8,604) $1,123,380  $(1,086,764) 

 Nine months ended September 30, 2019
 Parent Guarantors Non-Guarantors Eliminations Consolidated
          
Net income (loss)$248,446
 $158,537
 $(820) $(157,717) $248,446
Foreign currency translation adjustment5,347
 112
 5,235
 (5,347) 5,347
Other comprehensive income5,347
 112
 5,235
 (5,347) 5,347
Comprehensive income$253,793
 $158,649
 $4,415
 $(163,064) $253,793


Six months ended June 30, 2019
ParentGuarantorsNon-GuarantorEliminationsConsolidated
Net income (loss)$297,198  $176,933  $(498) $(176,435) $297,198  
Foreign currency translation adjustment7,411  155  7,256  (7,411) 7,411  
Other comprehensive income7,411  155  7,256  (7,411) 7,411  
Comprehensive income$304,609  $177,088  $6,758  $(183,846) $304,609  

 Nine months ended September 30, 2018
 Parent Guarantors Non-Guarantor Eliminations Consolidated
  
Net income (loss)$296,559
 $354,406
 $(836) $(353,570) $296,559
Foreign currency translation adjustment(5,815) (70) (5,745) 5,815
 (5,815)
Other comprehensive loss(5,815) (70) (5,745) 5,815
 (5,815)
Comprehensive income (loss)$290,744
 $354,336
 $(6,581) $(347,755) $290,744


34
Table of Contents


CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Amounts in thousands)
Six months ended June 30, 2020
ParentGuarantorsNon-GuarantorsEliminationsConsolidated
Net cash provided by (used in) operating activities$18,854  $228,317  $(384) $435  $247,222  
Net cash used in investing activities(424) (229,666) —  —  (230,090) 
Net cash (used in) provided by financing activities(20,375) —  435  (435) (20,375) 
Net (decrease) increase in cash, cash equivalents and restricted cash(1,945) (1,349) 51  —  (3,243) 
Cash, cash equivalents and restricted cash at beginning of period2,768  3,097  195  —  6,060  
Cash, cash equivalents and restricted cash at end of period$823  $1,748  $246  $—  $2,817  
 Nine months ended September 30, 2019
 Parent Guarantors Non-Guarantors Eliminations Consolidated
          
Net cash (used in) provided by operating activities$(7,604) $621,511
 $3,445
 $3
 $617,355
          
Net cash provided by (used in) investing activities9,178
 (644,507) (3,751) 432
 (638,648)
          
Net cash (used in) provided by financing activities(20,880) —
 435
 (435) (20,880)
          
Net (decrease) increase in cash, cash equivalents and restricted cash(19,306) (22,996) 129
 —
 (42,173)
          
Cash, cash equivalents and restricted cash at beginning of period25,585
 26,711
 1
 —
 52,297
          
Cash, cash equivalents and restricted cash at end of period$6,279
 $3,715
 $130
 $—
 $10,124



Six months ended June 30, 2019
ParentGuarantorsNon-GuarantorEliminationsConsolidated
Net cash provided by (used in) operating activities$312,267  $84,146  $3,355  $1  $399,769  
Net cash used in investing activities(405,848) (101,058) (3,751) 432  (510,225) 
Net cash (used in) provided by financing activities78,936  —  433  (433) 78,936  
Net decrease in cash, cash equivalents and restricted cash(14,645) (16,912) 37  —  (31,520) 
Cash, cash equivalents and restricted cash at beginning of period25,585  26,711  1  —  52,297  
Cash, cash equivalents and restricted cash at end of period$10,940  $9,799  $38  $—  $20,777  
 Nine months ended September 30, 2018
 Parent Guarantors Non-Guarantor Eliminations Consolidated
          
Net cash provided by (used in) operating activities$427,351
 $203,446
 $(1) $1
 $630,797
          
Net cash (used in) provided by investing activities(354,848) (199,738) (2,318) 2,318
 (554,586)
          
Net cash (used in) provided by financing activities(51,197) —
 2,319
 (2,319) (51,197)
          
Net increase in cash, cash equivalents and restricted cash21,306
 3,708
 —
 —
 25,014
          
Cash, cash equivalents and restricted cash at beginning of period67,908
 31,649
 —
 —
 99,557
          
Cash, cash equivalents and restricted cash at end of period$89,214
 $35,357
 $—
 $—
 $124,571
35
Table of Contents

16.SUBSEQUENT EVENTS
Amendment to Credit Facility


On July 27, 2020, Gulfport entered into a Sixteenth Amendment to the Amended and Restated Credit Agreement. Among other changes, the Sixteenth Amendment amends the Credit Agreement to: (i) require that, in the event of any issuances of Senior Notes, including Second Lien Notes, after the effective date, the then effective borrowing base will be reduced by a variable amount prescribed in the Credit Agreement to the extent the proceeds are not used to satisfy previously issued senior notes within 90 days of such issuance; (ii) require that each Loan Notice specify the amount of the then effective Borrowing Base and Pro Forma Borrowing Base, the Aggregate Elected Commitment Amount, and the current Total Outstandings, both with and without regard to the requested Borrowing; (iii) permit the Borrower or any Restricted Subsidiary to enter into obligations in connection with a Permitted Bond Hedge Transaction or Permitted Warrant Transaction; (iv) permit the Borrower to make any payments of Senior Notes and Subordinated Obligation prior to their scheduled maturity, in any event not to exceed $750,000,000 or, if lesser, the net cash proceeds of any Senior Notes issued within 90 days before such payment; (v) require that the Senior Notes have a stated maturity date of no earlier than March 13, 2024, as well as not require payment of principal prior to such date, in order for the Borrower to be permitted to secure indebtedness under the Senior Notes; (vi) permit certain additional liens securing obligations in respect of the incurrence or issuance of any Permitted Refinancing Notes (as such term is defined in the Credit Agreement) not to exceed $750,000,000, subject to the terms of an intercreditor agreement; and (vii) amend and restate the Applicable Rate Gridto provide as follows:

35
Applicable Rate
Applicable Usage LevelCommitment feeEurodollar Rate Loans and Letters of CreditBase Rate Loans
Level 10.375%2.00%1.00%
Level 20.375%2.25%1.25%
Level 30.50%2.50%1.50%
Level 40.50%2.75%1.75%
Level 50.50%3.00%2.00%
Table of Contents


16.SUBSEQUENT EVENTS
Derivatives
In October 2019,August 2020, the Company early terminated some of itsentered into natural gas fixed price swapsswap contracts for oil and natural gas scheduled to settle during the fourth quarter of 2019 covering approximately 1,000 BBls of oil per day and 120,000 MMBtu of natural gas per day. The value of these early terminations was used to enhance the fixed price for new natural gas swaps for 2020 covering approximately 28,000100,000 MMBtu of natural gas per day at a weightedan average swap price of $2.85$2.38 per MMBtu.




36
Table of Contents


ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section and audited consolidated financial statements and related notes included in our Annual Report on Form 10-K and with the unaudited consolidated financial statements and related notes thereto presented in this Quarterly Report on Form 10-Q.

Cautionary Note Regarding Forward-Looking Statements
This report includes “forward-looking statements”Form 10-Q may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended ("the Securities(the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended ("(the "Exchange Act"), and the Exchange Act"). When used in this Quarterly Report,Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the words "could", "believe", "anticipate", "intend", "estimate", "expect", "project"forward-looking statements. In some cases, you can identify forward looking statements by terms such as “may,” “will,” “should,” “could,” “would,” “expects,” “plans,” “anticipates,” “intends,” “believes,” “estimates,” “projects,” “predicts,” “potential” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
statements. All statements, other than statements of historical facts, included in this reportForm 10-Q that address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as the expected impact of the COVID-19 pandemic on our business, our industry and the global economy, estimated future net revenues from oil and natural gas reserves and the present value thereof, future capital expenditures (including the amount and nature thereof), the effect of our remediation plan for a material weakness, business strategy and measures to implement strategy, competitive strengths,strength, goals, expansion and growth of our business and operations, plans, references to future success, referencesreference to intentions as to future matters and other such matters are forward-looking statements.
These forward-looking statements are largely based on certain assumptions and analysis made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate in the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subjectbeliefs concerning future events, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control.
Although we believe our estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties including general economic, marketthat are beyond our control. In addition, management's assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this Form 10-Q are not guarantees of future performance, and we cannot assure any reader that those statements will be realized or business conditions; commodity prices; the opportunities (or lack thereof) thatforward-looking events and circumstances will occur. Actual results may be presenteddiffer materially from those anticipated or implied in the forward-looking statements due to and pursued by us; competitive actions by other oil and natural gas companies; adverse developments or losses from pending or future litigation and regulatory proceedings; our ability to identify, complete and integrate acquisitions of properties and businesses; changesthe factors listed in laws or regulations; adverse weather conditions and natural disasters such as hurricanes and other factors, including those listed under Item 1A,1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2018,2019 and elsewhere in this Quarterly Report on Form 10-Q and in our other filings with the SEC, many of which are beyond our control and may cause our actual results, performance or achievements to differ materially from anticipated future results, performance or achievements expressed or implied by such10-Q. All forward-looking statements. Should one or morestatements speak only as of the risks or uncertainties described indate of this Quarterly Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.Form 10-Q.
All forward‑lookingforward-looking statements, expressed or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward‑lookingforward-looking statements that we or persons acting on our behalf may issueissue.
Except as otherwise required by applicable law, we disclaim any duty to update any forward‑lookingforward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report.

Investors should note that Gulfport announceswe announce financial information in SEC filings, press releases and public conference calls. GulfportWe may use the Investors section of itsour website (www.gulfportenergy.com)(www.gulfportenergy.com) to communicate with investors. It is possible that the financial and other information posted there could be deemed to be material information. The information on Gulfport’sour website is not part of this Quarterly Report on Form 10-Q.

Overview
We are an independent oil and natural gasgas-weighted exploration and production company focused on the exploration, exploitation, acquisition and production of natural gas, crude oil and natural gas liquids ("NGLs"NGL") in the United States. Our corporate strategy is to internally identify prospects, acquire lands encompassing those prospectsStates with primary focus in the
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Appalachia and evaluate those prospects using subsurface geology and geophysical data and exploratory drilling. Using this strategy, we have developed an oil and natural gas portfolio of proved reserves, as well as development and exploratory drilling opportunities on high potential conventional and unconventional oil and natural gas prospects.Mid-Continent basins. Our principal properties are located in the Utica Shale primarily in Eastern Ohio targeting the Utica formation and in central Oklahoma targeting the SCOOP Woodford and SCOOP Springer playsformations.

COVID-19
In March 2020, the World Health Organization classified the outbreak of COVID-19 as a pandemic and recommended containment and mitigation measures worldwide. The measures have led to worldwide shutdowns and halting of commercial and interpersonal activity, as governments around the world imposed regulations in Oklahoma.efforts to control the spread of COVID-19 such as shelter-in-place orders, quarantines, executive orders and similar restrictions.
We remain focused on protecting the health and well-being of our employees and the communities in which we operate while assuring the continuity of our business operations. We have implemented preventative measures and developed corporate and field response plans to minimize unnecessary risk of exposure and prevent infection. We have a crisis management team for health, safety and environmental matters and personnel issues, and we have established a COVID-19 Response Team to address various impacts of the situation, as they have been developing. We also have modified certain business practices (including remote working for our corporate employees and restricted employee business travel) to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, the World Health Organization and other governmental and regulatory authorities.
On May 18, 2020, we began our phased transition back to the office for our corporate employees. As part of this transition, we have put into place preventative measures to focus on social distancing and minimizing unnecessary risk of exposure. Such measures include, but are not limited to, daily health surveys, protective masks in public areas of the building, no outside visitors, limiting the number of employees on elevators, additional sanitizing and 100% of the corporate employees working remotely on Fridays to provide additional time for deep cleaning. As of the date of this filing, we have transitioned approximately 60% of our corporate employees back to the corporate office. We will continue to monitor trends and governmental guidelines and may adjust our return to office plans accordingly to ensure the health and safety of our employees.
As a result of our business continuity measures, we have not experienced significant disruptions in executing our business operations in the first and second quarters of 2020. While we have not experienced significant disruptions to our operations in 2020, we are unable to predict the impact on our business, including our cash flows, liquidity, and results of operations in future periods due to numerous uncertainties. There is considerable uncertainty regarding the extent to which COVID-19 will continue to spread and the extent and duration of governmental and other measures implemented to slow the spread of the virus, such as large-scale travel bans and restrictions, quarantines, shelter-in-place orders and business and government shutdowns. Restrictions of this nature may cause, us, our suppliers and other business counterparties to experience operational delays, or delays in the delivery of materials and supplies. We expect the principal areas of operational risk for us are the availability of service providers and supply chain disruption. The operations of our midstream service providers, on whom we rely for the transmission, gathering and processing of a significant portion of our produced natural gas, NGL and oil, may be disrupted or suspended in response to containing the outbreak, or the difficult economic environment may lead to the bankruptcy or closing of the facilities and infrastructure of our midstream service providers. This may result in substantial discount in the prices we receive for our produced natural gas, NGL and oil or result in the shut-in of producing wells or the delay or discontinuance of development plans for our properties.
One of the impacts of the pandemic has been a significant reduction in global demand for oil and natural gas. The significant decline in demand has been met with a sharp decline in oil prices following the announcement of price reductions and production increases in March 2020 by members of the Organization of Petroleum Exporting Countries, and other foreign, oil-exporting countries. The resulting supply/demand imbalance is having disruptive impacts on the oil and natural gas exploration and production industry and on other industries that serve exploration and production companies. These industry conditions, coupled with those resulting from the COVID-19 pandemic, could lead to significant global economic contraction generally and in our industry in particular. We expect to see continued volatility in oil and natural gas prices for the foreseeable future, which may, over the long term, adversely impact our business. A significant decline in demand or prices for oil and natural gas would have a material adverse effect on our business, cash flows, liquidity, financial condition and results of operations.
Because of the sharp decline in oil prices since early March 2020, we chose to shut in a portion of our operated low margin, liquids-weighted production during the second quarter of 2020, largely consisting of legacy vertical production in the SCOOP. We also experienced shut ins across both the SCOOP and Utica from our non-operated partners. Nearly all liquids-weighted volumes on both our operated assets and those of our non-operated partners have returned to production. A sharp decline in prices or a pro-longed depressed environment may result in additional future shut ins. In addition, among other interests, we hold an acreage

the COVID-19 pandemic
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creates risks of delays in new drilling and completion activities that could negatively impact us, our non-operated partners or our service providers.
positionWe cannot predict the full impact that COVID-19 or the significant disruption and volatility currently being experienced in the Alberta oil sandsand natural gas markets will have on our business, cash flows, liquidity, financial condition and results of operations at this time, due to numerous uncertainties. The ultimate impacts will depend on future developments, including, among others, the ultimate geographic spread of the virus, the consequences of governmental and other measures designed to prevent the spread of the virus, the development of effective treatments, the duration of the outbreak, actions taken by members of OPEC and other foreign, oil-exporting countries, governmental authorities, customers, suppliers and other thirds parties, workforce availability, and the timing and extent to which normal economic and operating conditions resume. For additional discussion regarding risks associated with the COVID-19 pandemic, see Item 1A “Risk Factors” in Canadathis report.
Also, in response to the current commodity price environment, we announced tiered salary reduction for most employees, senior management team and our Board of Directors with such measures expected to last through December 2020. In addition, select furloughs were implemented to reduce costs and preserve liquidity. We continue to evaluate ways to reduce our interestcost structure in Grizzly Oil Sands ULC ("Grizzly"),an effort to improve profitability during this economic and commodity price downturn.
As noted above, decreased demand for oil and natural gas as a result of the COVID-19 pandemic and the accompanying decrease in commodity prices has significantly reduced our ability to access capital markets and to refinance our existing indebtedness. Further, these conditions have made amendments or waivers to our revolving credit facility more difficult to obtain and available on terms less favorable to us. If depressed commodity prices persist or decline further, the borrowing base under our revolving credit facility could be further reduced at our next scheduled redetermination date in November 2020. Any such reduction would constrain our liquidity and may impair our ability to fund our planned capital expenditures and meet our obligations under our existing indebtedness. Further, a reduction in our capital expenditures would decrease our production, revenues, operating cash flow and EBITDA, which could limit our ability to comply with the restrictive covenants in our revolving credit facility and other existing indebtedness. Finally, our existing revolving credit facility matures in December 2021 and therefore will become a current liability at year end 2020 unless we are able to refinance the credit facility with a new credit facility or other financing. Considering the current state of the first lien market and our elevated leverage profile, there is substantial risk that a refinancing will not be available to us on reasonable terms. A current liability under the revolving credit facility at year end 2020 may result in a qualified audit opinion which could result in a default under the terms of the current revolving credit facility. As a result of these uncertainties and other factors, management has concluded that there is substantial doubt about our ability to continue as a going concern. Failure to meet our obligations under our existing indebtedness or failure to comply with any of our covenants, if not waived, would result in an approximate 21.8% equity interestevent of default under such indebtedness and result in Mammoth Energy Services, Inc. ("Mammoth Energy"), an energy services company listedthe potential acceleration of outstanding indebtedness thereunder and, with respect to the revolving credit facility, the potential foreclosure on the Nasdaq Global Select Market (TUSK). We seekcollateral securing such debt, and could cause a cross-default under our other outstanding indebtedness.
As of June 30, 2020, we had entered into firm transportation contracts to achieve reserve growthdeliver approximately 1,455,000 MMBtu per day for the remainder of 2020 and increase2021, respectively. Under these firm transportation contracts, we are obligated to deliver minimum daily volumes or pay fees for any deficiencies in deliveries. As a result of the reduced production from our cash flow throughUtica Shale or SCOOP acreage due to decreased developmental activities, taking into consideration the current low commodity price environment, we expect that we will be unable to meet our annual drilling programs.obligations under the existing firm transportation contracts, resulting in fees, which may be significant and may have a material adverse effect on our operations.
20192020 Operational and OtherFinancial Highlights
Despite the challenges our company and the entire upstream energy industry faces from low commodity prices, we have remained committed to the execution of our strategy and to position Gulfport for long-term success. During the ninethree and six months ended SeptemberJune 30, 2020, we had the following notable achievements:
•Continued our efforts to improve our balance sheet by reducing long-term debt by approximately $70 million as compared to December 31, 2019 primarily through discounted bond repurchases.
•Continued to improve operational efficiencies and reduce drilling and completion costs in both our SCOOP and Utica operating areas. In the Utica, our average spud to rig release time was 18.5 days in the first half of 2020, which was a 6% improvement from full year 2019 levels. In the SCOOP, our average spud to rig release time was 37 days, representing a 32% improvement compared to full year 2019 levels.
•Closed on the sale of our SCOOP water infrastructure assets on January 2, 2020. We received $50.0 million in cash upon closing and have an opportunity to earn additional incentive payments over the next 15 years, subject to our
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ability to meet certain thresholds which will be driven by, among other things, our future development program and future water production levels. Proceeds from the divestiture were used to reduce our outstanding revolver balance.


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2020 Production and Drilling Activity
Production Volumes
Three months ended June 30,
2020% of Total2019% of TotalChange% Change
($ In thousands)
Natural gas (Mcf/day)
Utica Shale775,070  83 %1,014,302  83 %(239,232) (24)%
SCOOP158,813  17 %211,898  17 %(53,085) (25)%
Other53  — %205  — %(152) (74)%
Total933,936  1,226,405  (292,469) (24)%
Oil and condensate (Bbls/day)
Utica Shale308  7 %621  9 %(313) (50)%
SCOOP4,186  91 %4,899  69 %(713) (15)%
Other83  2 %1,614  22 %(1,531) (95)%
Total4,577  7,134  (2,557) (36)%
NGL (Gal/day)
Utica Shale106,333  23 %228,871  36 %(122,538) (54)%
SCOOP353,252  77 %399,368  64 %(46,116) (12)%
Other72  — %208  — %(136) (65)%
Total459,657  628,447  (168,790) (27)%
Combined (Mcfe/day)
Utica Shale792,106  77 %1,050,724  77 %(258,618) (25)%
SCOOP234,396  23 %298,343  22 %(63,947) (21)%
Other563  — %9,922  1 %(9,359) (94)%
Total1,027,065  1,358,989  (331,924) (24)%
Our total net production averaged approximately 1,027.1 MMcfe per day during the three months ended June 30, 2020, as compared to 1,359.0 MMcfe per day during the same period in 2019. The 24% decrease in production is largely the result of a decrease in development activities of our Utica Shale and SCOOP operating areas beginning in the third and fourth quarters of 2019. Additionally, in response to sharp declines in commodity prices resulting from COVID-19 uncertainties, beginning in March 2020, we chose to shut in a portion of our operated low margin, liquids-weighted production during the second quarter of 2020, largely consisting of legacy vertical production in the SCOOP. We also experienced shut ins across both the SCOOP and Utica from our non-operated partners. Nearly all liquids-weighted volumes on both our operated assets and those of our non-operated partners have returned to production.
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Six months ended June 30,
2020% of Total2019% of TotalChange% Change
($ In thousands)
Natural gas (Mcf/day)
Utica Shale780,426  83 %983,436  83 %(203,010) (21)%
SCOOP159,349  17 %196,955  17 %(37,606) (19)%
Other46  — %173  — %(127) (73)%
Total939,821  1,180,564  (240,743) (20)%
Oil and condensate (Bbls/day)
Utica Shale450  9 %675  10 %(225) (33)%
SCOOP4,680  90 %4,661  67 %19  — %
Other81  1 %1,630  23 %(1,549) (95)%
Total5,211  6,966  (1,755) (25)%
NGL (Gal/day)
Utica Shale120,313  25 %243,995  39 %(123,682) (51)%
SCOOP365,073  75 %380,234  61 %(15,161) (4)%
Other34  — %186  — %(152) (82)%
Total485,420  624,415  (138,995) (22)%
Combined (Mcfe/day)
Utica Shale800,313  77 %1,022,341  78 %(222,028) (22)%
SCOOP239,583  23 %279,243  21 %(39,660) (14)%
Other536  — %9,983  1 %(9,447) (95)%
Total1,040,432  1,311,567  (271,135) (21)%
Our total net production averaged approximately 1,040.4 MMcfe per day during the six months ended June 30, 2020, as compared to 1,311.6 MMcfe per day during the same period in 2019. The 21% decrease in production is largely the result of a decrease in development activities of our Utica Shale and SCOOP operating areas beginning in the third and fourth quarters of 2019. Additionally, in response to sharp declines in commodity prices resulting from COVID-19 uncertainties, beginning in March 2020, we chose to shut in a portion of our operated low margin, liquids-weighted production during the second quarter of 2020, largely consisting of legacy vertical production in the SCOOP. We also experienced shut ins across both the SCOOP and Utica from our non-operated partners. Nearly all liquids-weighted volumes on both our operated assets and those of our non-operated partners have returned to production.
Utica Shale. From January 1, 2020 through June 30, 2020, we spud 1312 gross (11.4(11.1 net) wells in the Utica Shale, of which one was being drilled and participated11 were in fivevarious stages of operations at June 30, 2020. In addition, we completed 22 gross and net operated wells. We did not participate in any additional gross (0.9 net) wells that were drilled by other operators on our Utica Shale acreage. In addition, during the nine months ended September 30, 2019, we spud eight gross (6.7 net) wells in the SCOOP and participated in an additional 36 gross (0.8 net) wells that were drilled by other operators on our SCOOP acreage. Of the 21 new wells we spud, at September 30, 2019, 13 were in various stages of completion, six were turned-to-sales and two were being drilled. In addition, 47 gross (41.5 net) operated wells were turned-to-sales in our Utica Shale operating area and nine gross (8.7 net) operated wells were turned-to-sales in our SCOOP operating area during the nine months ended September 30, 2019.
In January 2019, our board of directors approved a new stock repurchase program to acquire a portion of our outstanding common stock within a 24 month period, which we believe underscores the confidence we have in our business model, financial performance and asset base. As of October 25, 2019, we have repurchased approximately 3.8 million shares of our outstanding common stock pursuant to the plan for total consideration of approximately $30.0 million.

During the three months ended September 30, 2019, we used borrowings under our revolving credit facility to repurchase in the open market approximately $104.4 million aggregate principal amount of our outstanding 6.625% Senior Notes due 2023 ("2023 Notes"), 6.000% Senior Notes due 2024 ("2024 Notes"), 6.375% Senior Notes due 2025 ("2025 Notes"), and 6.375% Senior Notes due 2026 ("2026 Notes") (collectively the "Notes"), for $80.3 million. We recognized a $23.6 million gain on debt extinguishment, which included retirement of unamortized issuance costs and fees associated with the repurchased debt.

In December of 2018, we entered into an agreement to sell our non-core assets located in the West Cote Blanche Bay ("WCBB") and Hackberry fields of Louisiana to an undisclosed third party for a purchase price of approximately $19.7 million. The sale closed on July 3, 2019, subject to customary post-closing terms and conditions, with an effective date of August 15, 2018. We received approximately $9.2 million in cash and retained contingent overriding royalty interests. In addition, we could also receive contingent payments based on commodity prices exceeding specified thresholds over the two years following the closing date. See Note 9 for further discussion of the contingent consideration arrangement, which was determined to be an embedded derivative. The buyer assumed all plugging and abandonment liabilities associated with these assets which totaled approximately $30.0 million at the divestiture date.


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2019 Production and Drilling Activity
During the three months ended September 30, 2019, our total net production was 130,071,046 thousand cubic feet ("Mcf") of natural gas, 474,407 barrels of oil and 52,950,681 gallons of NGLs for a total of 140,482 million cubic feet of natural gas equivalent ("MMcfe") as compared to 116,993,594 Mcf of natural gas, 664,633 barrels of oil and 72,427,030 gallons of NGLs, or 131,328 MMcfe, for the three months ended September 30, 2018. Our total net production averaged approximately 1,527.0 MMcfe per day during the three months ended September 30, 2019, as compared to 1,427.5 MMcfe per day during the same period in 2018. The 7% increase in production is largely the result of the continuing development of our Utica Shale and SCOOP acreage.
Utica Shale. From January 1, 2019 through September 30, 2019, we spud 13 gross (11.4 net) wells in the Utica Shale, of which six were turned-to-sales, one was being drilled and six were in various stages of completion at September 30, 2019. We also participated in five additional gross (0.9 net) wells that were drilled by other operators on our Utica Shale acreage. From October 1, 2019 through October 25, 2019, we spud one gross and net well in the Utica Shale.
As of October 25, 2019,July 31, 2020, we had one operated drilling rig running in the Utica Shale. We currently intendplay and expect to spud a totalcontinue with this level of 16 gross (14.4 net) horizontal wells, and commence sales from a totalactivity through the third quarter of 47 gross (41.5 net) horizontal wells, on our Utica Shale acreage in 2019. We also anticipate an additional two to three net horizontal wells will be drilled, and sales commenced from two to three net horizontal wells, on our Utica Shale acreage by other operators during 2019.2020.
Aggregate net production from our Utica Shale acreage during the three months ended SeptemberJune 30, 20192020 was approximately 114,45972,082 MMcfe, or an average of 1,244.1792.1 MMcfe per day, of which 98% was natural gas and 2% was oil and NGLs.NGL.
SCOOP. From January 1, 20192020 through SeptemberJune 30, 2019,2020, we spud eightsix gross (6.7(5.2 net) wells in the SCOOP, of which one was being drilled and sevenfive were in various stages of completionoperations at SeptemberJune 30, 2019.2020. In addition. we completed 4 gross (3.8 net) operated wells. We also participated in an additional 36five gross (0.8 net) wells that were drilled by other operators on our SCOOP acreage. From October 1, 2019 through October 25, 2019, we did not spud any wells on our SCOOP acreage.
As of October 25, 2019,July 31, 2020, we had one operated drilling rig running on our SCOOP acreage. We currently intendin the play and expect to spud a totalcontinue with this level of nine gross (7.7 net) horizontal wells, and commence sales from a totalactivity for the remainder of 14 gross (12.6 net) horizontal wells, on our SCOOP acreage in 2019. We also anticipate one to two net wells will be drilled, and sales commenced from one to two net wells on our SCOOP acreage by other operators during 2019.2020. 
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Aggregate net production from our SCOOP acreage during the three months ended SeptemberJune 30, 20192020 was approximately 25,89721,330 MMcfe, or an average of 281.5234.4 MMcfe per day, of which 71%68% was from natural gas and 29%32% was from oil and NGLs.NGL.
RESULTS OF OPERATIONS
Comparison of the Three Month Periods Ended June 30, 2020 and 2019
We reported a net loss of $561.1 million for the three months ended June 30, 2020 as compared to net income of $235.0 million for the three months ended June 30, 2019. Included in the loss for the three months ended June 30, 2020 was a $532.9 million non-cash impairment of our oil and natural gas properties, which primarily resulted from a significant decrease in the trailing twelve month first of month prices of natural gas, oil and NGL, and was the main driver of the change in our net (loss) income during the period. Additionally, pricing for all of our commodities decreased significantly during the second quarter of 2020, resulting in a $182.4 million decrease in natural gas, oil and NGL sales and a $144.2 million decrease in gain on natural gas, oil and NGL derivatives. This increase in loss is partially offset by a $125.5 million decrease in loss from equity method investments, a $60.2 million decrease in DD&A, a $34.3 million gain on debt extinguishment, a $12.0 million decrease in midstream gathering and processing expenses, a $6.7 million decrease in lease operating expenses and a $4.5 million decrease in production taxes for the three months ended June 30, 2020 as compared to the three months ended June 30, 2019.
Natural Gas, Oil and NGL Sales
Three months ended June 30,
20202019change
($ In thousands)
Natural gas86,797  225,257  (61)%
Oil and condensate8,390  36,910  (77)%
NGL10,252  25,687  (60)%
Natural gas, oil and NGL sales$105,439  $287,854  (63)%
The decrease in natural gas sales without the impact of derivatives was due to a 49% decrease in realized natural gas prices and a 24%decrease in natural gas sales volumes.
The decrease in oil and condensate sales without the impact of derivatives was due to a 65% decrease in realized oil and condensate prices and a 36% decrease in oil and condensate sales volumes.
The decrease in NGL sales without the impact of derivatives was due to a 45% decreasein realized NGL prices and a 27% decrease in NGL sales volumes.
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South Louisiana
Natural Gas, Oil and NGL Derivatives
Three months ended June 30,
20202019
($ In thousands)
Natural gas derivatives - fair value (losses) gains$(48,146) $132,760  
Natural gas derivatives - settlement gains83,835  19,715  
Total gains on natural gas derivatives35,689  152,475  
Oil and condensate derivatives - fair value (losses) gains(48,386) 11,501  
Oil and condensate derivatives - settlement gains40,449  370  
Total (losses) gains on oil and condensate derivatives(7,937) 11,871  
NGL derivatives - fair value (losses) gains(997) 3,537  
NGL derivatives - settlement gains216  3,257  
Total (losses) gains on NGL derivatives(781) 6,794  
Contingent consideration arrangement - fair value losses—  —  
Total gains on natural gas, oil and NGL derivatives$26,971  $171,140  
See . From January 1,Note 10 to our consolidated financial statements for further discussion of our derivative activity.
Natural Gas, Oil and NGL Production and Pricing
The following table summarizes our oil and condensate, natural gas and NGL production and related pricing for the three months ended June 30, 2020, as compared to such data for the three months ended June 30, 2019:
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 Three months ended June 30,
 20202019
($ In thousands)
Natural gas sales
Natural gas production volumes (MMcf)84,988  111,603  
Total natural gas sales$86,797  $225,257  
Natural gas sales without the impact of derivatives ($/Mcf)$1.02  $2.02  
Impact from settled derivatives ($/Mcf)$0.99  $0.18  
Average natural gas sales price, including settled derivatives ($/Mcf)$2.01  $2.20  
Oil and condensate sales
Oil and condensate production volumes (MBbls)417  649  
Total oil and condensate sales$8,390  $36,910  
Oil and condensate sales without the impact of derivatives ($/Bbl)$20.14  $56.85  
Impact from settled derivatives ($/Bbl)$97.12  $0.57  
Average oil and condensate sales price, including settled derivatives ($/Bbl)$117.26  $57.42  
NGL sales
NGL production volumes (MGal)41,829  57,189  
Total NGL sales$10,252  $25,687  
NGL sales without the impact of derivatives ($/Gal)$0.25  $0.45  
Impact from settled derivatives ($/Gal)$—  $0.06  
Average NGL sales price, including settled derivatives ($/Gal)$0.25  $0.51  
Natural gas, oil and condensate and NGL sales
Natural gas equivalents (MMcfe)93,463  123,668  
Total natural gas, oil and condensate and NGL sales$105,439  $287,854  
Natural gas, oil and condensate and NGL sales without the impact of derivatives ($/Mcfe)$1.13  $2.33  
Impact from settled derivatives ($/Mcfe)$1.33  $0.19  
Average natural gas, oil and condensate and NGL sales price, including settled derivatives ($/Mcfe)$2.46  $2.52  
Production Costs:
Average lease operating expenses ($/Mcfe)$0.17  $0.18  
Average production taxes ($/Mcfe)$0.04  $0.07  
Average midstream gathering and processing ($/Mcfe)$0.64  $0.58  
Total lease operating expenses, midstream costs and production taxes ($/Mcfe)$0.85  $0.83  
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Lease Operating Expenses
Three months ended June 30,
20202019change
($ In thousands, except per unit)
Lease operating expenses
Utica$12,996  $13,646  (5)%
SCOOP2,551  4,143  (38)%
Other(1)
139  4,599  (97)%
Total lease operating expenses$15,686  $22,388  (30)%
Lease operating expenses per Mcfe
Utica$0.18  $0.14  26 %
SCOOP0.12  0.15  (22)%
Other(1)
2.72  5.09  (47)%
Total lease operating expenses per Mcfe$0.17  $0.18  (7)%
 _____________________
(1) Includes WCBB, Hackberry, Niobrara and Bakken.
The decrease in total lease operating expenses ("LOE") for the three months ended June 30, 2020 as compared to the three months ended June 30, 2019 through July 3,was primarily the result of our 24% decrease in production and ongoing well optimization and cost initiatives. Per unit LOE was relatively flat for the three months ended June 30, 2020 as compared to the three months ended June 30, 2019.
Production Taxes
Three months ended June 30,
20202019change
($ In thousands, except per unit)
Production taxes$3,605  $8,098  (55)%
Production taxes per Mcfe$0.04  $0.07  (41)%
The decrease in production taxes was primarily related to a decrease in realized prices and production for the three months ended June 30, 2020 as compared to the three months ended June 30, 2019.
Midstream Gathering and Processing Expenses
Three months ended June 30,
20202019change
($ In thousands, except per unit)
Midstream gathering and processing expenses$59,974  $72,015  (17)%
Midstream gathering and processing expenses per Mcfe$0.64  $0.58  10 %
The decrease in midstream gathering and processing expenses was primarily related to our 24% decrease in our production for the three months ended June 30, 2020 as compared to the three months ended June 30, 2019. The increase in per unit midstream gathering and processing expenses for the three months ended June 30, 2020 as compared to the three months ended June 30, 2019 we did not spud any new wells or recomplete any wells inis primarily related to Utica Shale production volumes falling below a minimum volume commitment and the South Louisiana fields. Our aggregate net production from the South Louisiana fieldsresulting deficiency payments during the three months ended SeptemberJune 30, 2019 was approximately 38.3 MMcfe, or an average2020.
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Table of 416.2 Mcfe per day, all of which was from oil. On July 3, 2019, we closed on the sale of all of our South Louisiana assets.Contents
We had no further capital obligations
Depreciation, Depletion and Amortization
Three months ended June 30,
20202019change
($ In thousands, except per unit)
Depreciation, depletion and amortization$64,790  $124,951  (48)%
Depreciation, depletion and amortization per Mcfe$0.69  $1.01  (32)%
Depreciation, depletion and amortization ("DD&A") expense consisted of $62.2 million in depletion of oil and natural gas properties and $2.6 million in depreciation of other property and equipment, compared to $122.5 million in depletion of oil and natural gas properties and $2.5 million in depreciation of other property and equipment for the three months ended June 30, 2019. The decrease in DD&A was due to both a decrease in our depletion rate as a result of a decrease in our amortization base from full cost ceiling test impairments recorded during 2019 and the first quarter of 2020, as well as a decrease in our production.
Impairment of Oil and Gas Properties. During the three months ended June 30, 2020, we incurred a$532.9 million oil and natural gas properties impairment charge related primarily to the South Louisiana fields after July 3, 2019.
Niobrara Formation. From January 1, 2019 through October 25, 2019, there weredecline in the twelve month trailing first of month average price for natural gas, oil and NGL, compared to no wells spud on our Niobrara Formation acreage. Aggregate net production was approximately 26.0 MMcfe, or an averageimpairment charge of 282.4 Mcfe per dayoil and gas properties during the three months ended SeptemberJune 30, 2019, all2019.
Based on prices for the last nine months and the short-term pricing outlook for the third quarter of which was2020, we expect to recognize an additional full cost impairment in the third quarter of 2020. The amount of any future impairments is difficult to predict as it depends on changes in commodity prices, production rates, proved reserves, evaluation of costs excluded from oil.
Bakken. As of September 30, 2019, we had an interest in 18 wells amortization, future development costs and overriding royalty interests in certain existing and future wells. Aggregate net production from this acreage during the three months ended September 30, 2019 was approximately 60.6 MMcfe, or an average of 658.3 Mcfe per day, of which 96% was from oil and 4% was from natural gas and natural gas liquids.costs.

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Equity Investments
Mammoth Energy Services, Inc.
Three months ended June 30,
20202019change
($ In thousands, except per unit)
Loss from equity method investments, net$45  $125,582  (100)%
In connection with the preparation of financial statements forThe decrease in loss from equity method investments is primarily related to a $125.4 million impairment charge recorded during the three months ended SeptemberJune 30, 2019, we reviewed our investment in Mammoth Energy for impairment based on certain qualitative and quantitative factors.2019. As a result of the calculated fair values and other qualitative factors, we concluded that an other than temporary impairment was indicated. This resulted in recording an aggregate impairment loss of $35.5 million and $160.8 million for the three and nine months ended September 30, 2019, respectively, which is included in loss (income) from equity method investments, net in the accompanying consolidated statements of operations. If Mammoth Energy's common stock continues to trade below the carrying value for a prolonged period of time, further impairment of our investment in Mammoth Energy may be necessary.was reduced to zero during the first quarter of 2020, we did not record any similar impairment charges during the three months ended June 30, 2020. See Note 4 to our consolidated financial statements for further discussion on our equity investments.
General and Administrative Expenses
RESULTS OF OPERATIONS
Three months ended June 30,
20202019change
($ In thousands, except per unit)
General and administrative expenses, gross$21,655  $23,539  (8)%
Reimbursed from third parties$(3,023) $(2,978) 2 %
Capitalized general and administrative expenses$(8,162) $(8,834) (8)%
General and administrative expenses, net$10,470  $11,727  (11)%
General and administrative expenses, net per Mcfe$0.11  $0.09  22 %
The decrease in general and administrative expenses, gross was due primarily due to lower employee costs resulting from the reduction in workforce that was completed in the fourth quarter of 2019. Additionally, in June 2020, in response to the
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Comparison of
continued depressed commodity price environment, we announced several G&A initiatives to reduce our corporate cost structure. This decrease was partially offset by an increase in non-recurring legal and consulting expenses.

Interest Expense
Three months ended June 30,
 20202019
($ In thousands, except per unit)
Interest expense on senior notes28,179  32,281  
Interest expense on revolving credit agreement2,860  3,224  
Interest expense on construction loan and other310  312  
Capitalized interest(523) (1,005) 
Amortization of loan costs1,540  1,606  
Total interest expense$32,366  $36,418  
Interest expense per Mcfe$0.35  $0.29  
Weighted average debt outstanding under revolving credit facility$132,077  $168,791  
The decrease in interest expense for three months ended June 30, 2020 as compared to the Three Month Periods Ended Septemberthree months ended June 30, 2019 was primarily due to repurchases of our senior notes in the second half of 2019 and 2018the first half of 2020.
Income Taxes
. We reported net lossrecorded no income tax expense for three months ended June 30, 2020 compared to income tax benefit of $48.8$179.3 million for the three months ended SeptemberJune 30, 2019. As of June 30, 2020, we had a federal net operating loss carryforward of approximately $1.5 billion, in addition to numerous temporary differences, which gave rise to a net deferred tax asset. Quarterly, management performs a forecast of our taxable income and analyzes other relevant factors to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established if, in management’s opinion, it is more likely than not that some portion will not be realized. At June 30, 2020, a valuation allowance of $879.3 million has been maintained against the full net deferred tax asset. The tax benefit recorded during the three months ended June 30, 2019 was a result of management's determination there was sufficient positive evidence that it was more likely than not that the federal and some state net operating loss carryforwards would be realized.
On April 30, 2020, our Board of Directors approved the adoption of a tax benefits preservation plan that is intended to protect value by preserving our ability to use our tax attributes, such as NOLs, to offset potential future income taxes for federal income tax purposes. See Note 14 of the notes to our consolidated financial statements for more information.


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Comparison of the Six Month Periods Ended June 30, 2020 and 2019
We reported net loss of $1.1 billion for the six months ended June 30, 2020 as compared to net income of $95.2$297.2 million for the threesix months ended SeptemberJune 30, 2018. This $144.0 million period-to-period decrease2019. Included in the loss for the six months ended June 30, 2020 was due primarily to a $75.8 million decrease in$1.1 billion non-cash impairment of our oil and natural gas revenues,properties which primarily resulted from a $55.9significant decrease in the trailing twelve month first of month prices of natural gas, oil and NGL, and was the main driver of the change in our net (loss) income during the period. Additionally, pricing for all of our commodities decreased significantly, resulting in a $374.4 million decrease in natural gas, oil and NGL sales and a $25.9 million decrease in gain on natural gas, oil and NGL derivatives. The remaining variance related to a $4.9 million increase in general and administrative expenses, partially offset by a $110.5 million decrease in loss from equity method investments, including a $35.5$125.4 million impairment related to our investment in Mammoth Energy, a $35.6$100.6 million oil and natural gas properties impairment charge related to the decline in commodity prices, a $25.6 million increasedecrease in DD&A, and a $2.7 million decrease in gain on sale of equity method investments, partially offset by a $23.6$49.6 million gain on debt extinguishment, a $24.4 million decrease in midstream gathering and processing expenses, a $10.5 million decrease in lease operating expenses and a $26.5$7.6 million increasedecrease in income tax benefitproduction taxes for the threesix months ended SeptemberJune 30, 20192020 as compared to the threesix months ended SeptemberJune 30, 2018. Additional impairments of oil and natural gas properties are expected to occur in upcoming quarters should commodity prices continue below the average of the previous 12 months. However, the amount of any future impairments is difficult to predict as it depends on changes in commodity prices, production rates, proved reserves, evaluation of costs excluded from amortization, future development costs and production costs. The gain on sale of equity investments in 2018 was the result of the sale of Mammoth Energy common stock during 2018.2019.
Natural Gas, Oil and NGL RevenuesSales
Six months ended June 30,
20202019change
($ In thousands)
Natural gas195,344  501,273  (61)%
Oil and condensate31,541  69,392  (55)%
NGL27,165  57,812  (53)%
Natural gas, oil and NGL sales$254,050  $628,477  (60)%
. For the three months ended September 30, 2019, we reported oil andThe decrease in natural gas revenuessales without the impact of $285.2 million as comparedderivatives was due to oil and a 51% decrease in realized natural gas revenues of $361.0 million during the same period prices and a 20% decreasein 2018. This $75.8 million, or 21%, decrease in revenues was primarily attributable to the following:natural gas sales volumes.
A $21.1 millionThe decrease in oil and condensate sales without the impact of derivatives was due to an 40% decrease in realized oil and condensate prices and a 25% decrease in oil and condensate market prices and a 29%sales volumes.
The decrease in oil and condensate sales volumes.

A $33.5 million decrease in NGLsNGL sales without the impact of derivatives was due to a 48%40% decrease in NGLs marketrealized NGL prices and a 27% 22% decrease in NGLsNGL sales volumes.

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A $57.9 million decrease in natural gas sales without the impact of derivatives due to a 29% decrease in natural gas market prices, partially offset by an 11% increase in natural gas sales volumes.

Natural Gas, Oil and NGL Derivatives
A $1.0 million decrease in natural gas, oil and condensate and NGLs sales due to an unfavorable change in the fair value of the contingent consideration arrangement related to the Louisiana asset sale.
Six months ended June 30,
20202019
($ In thousands)
Natural gas derivatives - fair value (losses) gains$(63,271) $142,098  
Natural gas derivatives - settlement gains (losses)144,813  (6,054) 
Total gains on natural gas derivatives81,542  136,044  
Oil and condensate derivatives - fair value (losses) gains(5,012) 11,027  
Oil and condensate derivatives - settlement gains49,949  390  
Total gains on oil and condensate derivatives44,937  11,417  
NGL derivatives - fair value losses(332) (536) 
NGL derivatives - settlement gains471  4,170  
Total gains on NGL derivatives139  3,634  
Contingent consideration arrangement - fair value losses(1,381) —  
Total gains on natural gas, oil and NGL derivatives$125,237  $151,095  

These decreases were partially offset by:
A $37.7 million increase in natural gas, oil and condensate and NGLs sales due to a favorable change in gains and losses from derivative instruments. Of the total change, $87.7 million was due to favorable changes in settlements relatedSee Note 10 to our derivative positions, partially offset by $50.0 million in unfavorable change in the fair valueconsolidated financial statements for further discussion of our open derivative positions in each period. The unfavorable change in fair value of our open derivative positions is primarily a result of new options contracts entered into during the three months ended September 30, 2019, partially offset by fair value gain on swap contracts as a result of the decrease in forward curve prices for natural gas from the previous reporting period.activity.
Natural Gas, Oil and NGL Production and Pricing
The following table summarizes our oil and condensate, natural gas and NGLsNGL production and related pricing for the threesix months ended SeptemberJune 30, 2019,2020, as compared to such data for the threesix months ended SeptemberJune 30, 2018:


2019:
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 Six months ended June 30,
 20202019
($ In thousands)
Natural gas sales
Natural gas production volumes (MMcf)171,047  213,682  
Total natural gas sales$195,344  $501,273  
Natural gas sales without the impact of derivatives ($/Mcf)$1.14  $2.35  
Impact from settled derivatives ($/Mcf)$0.85  $(0.03) 
Average natural gas sales price, including settled derivatives ($/Mcf)$1.99  $2.32  
Oil and condensate sales
Oil and condensate production volumes (MBbls)948  1,261  
Total oil and condensate sales$31,541  $69,392  
Oil and condensate sales without the impact of derivatives ($/Bbl)$33.26  $55.03  
Impact from settled derivatives ($/Bbl)$52.67  $0.31  
Average oil and condensate sales price, including settled derivatives ($/Bbl)$85.93  $55.34  
NGL sales
NGL production volumes (MGal)88,346  113,019  
Total NGL sales$27,165  $57,812  
NGL sales without the impact of derivatives ($/Gal)$0.31  $0.51  
Impact from settled derivatives ($/Gal)$—  $0.04  
Average NGL sales price, including settled derivatives ($/Gal)$0.31  $0.55  
Natural gas, oil and condensate and NGL sales
Natural gas equivalents (MMcfe)189,359  237,394  
Total natural gas, oil and condensate and NGL sales$254,050  $628,477  
Natural gas, oil and condensate and NGL sales without the impact of derivatives ($/Mcfe)$1.34  $2.65  
Impact from settled derivatives ($/Mcfe)$1.03  $(0.01) 
Average natural gas, oil and condensate and NGL sales price, including settled derivatives ($/Mcfe)$2.37  $2.64  
Production Costs:
Average lease operating expenses ($/Mcfe)$0.17  $0.18  
Average production taxes ($/Mcfe)$0.04  $0.07  
Average midstream gathering and processing ($/Mcfe)$0.62  $0.60  
Total lease operating expenses, midstream costs and production taxes ($/Mcfe)$0.83  $0.85  

51
 Three months ended September 30,
 2019 2018
 ($ In thousands)
Natural gas sales   
Natural gas production volumes (MMcf)130,071
 116,994
    
Total natural gas sales$213,227
 $271,167
    
Natural gas sales without the impact of derivatives ($/Mcf)$1.64
 $2.32
Impact from settled derivatives ($/Mcf)$0.57
 $0.08
Average natural gas sales price, including settled derivatives ($/Mcf)$2.21
 $2.40
    
Oil and condensate sales   
Oil and condensate production volumes (MBbls)474
 665
    
Total oil and condensate sales$24,550
 $45,682
    
Oil and condensate sales without the impact of derivatives ($/Bbl)$51.75
 $68.73
Impact from settled derivatives ($/Bbl)$4.65
 $(14.76)
Average oil and condensate sales price, including settled derivatives ($/Bbl)$56.40
 $53.97
    
NGLs sales   
NGLs production volumes (MGal)52,951
 72,427
    
Total NGLs sales$20,324
 $53,776
    
NGLs sales without the impact of derivatives ($/Gal)$0.38
 $0.74
Impact from settled derivatives ($/Gal)$0.11
 $(0.07)
Average NGLs sales price, including settled derivatives ($/Gal)$0.49
 $0.67
    
Natural gas, oil and condensate and NGLs sales   
Natural gas equivalents (MMcfe)140,482
 131,328
    
Total natural gas, oil and condensate and NGLs sales$258,101

$370,625
    
Natural gas, oil and condensate and NGLs sales without the impact of derivatives ($/Mcfe)$1.84
 $2.82
Impact from settled derivatives ($/Mcfe)$0.58
 $(0.04)
Average natural gas, oil and condensate and NGLs sales price, including settled derivatives ($/Mcfe)$2.42
 $2.78
    
Production Costs:   
Average production costs ($/Mcfe)$0.16
 $0.17
Average production taxes ($/Mcfe)$0.05
 $0.07
Average midstream gathering and processing ($/Mcfe)$0.56
 $0.60
Total production costs, midstream costs and production taxes ($/Mcfe)$0.77
 $0.84

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Lease Operating Expenses. Lease operating expenses ("LOE") not including production taxes increased to $22.5 million
Six months ended June 30,
20202019change
($ In thousands, except per unit)
Lease operating expenses
Utica$24,180  $25,473  (5)%
SCOOP7,320  7,757  (6)%
Other(1)172  8,965  (98)%
Total lease operating expenses$31,672  $42,195  (25)%
Lease operating expenses per Mcfe
Utica$0.17  $0.14  21 %
SCOOP0.17  0.15  9 %
Other(1)1.77  4.96  (64)%
Total lease operating expenses per Mcfe$0.17  $0.18  (6)%
 _____________________
(1) Includes WCBB, Hackberry, Niobrara and Bakken.
The decrease in total LOE for the threesix months ended SeptemberJune 30, 2019 from $22.3 million for2020 as compared to the threesix months ended SeptemberJune 30, 2018. This $0.2 million, or 1%, increase2019 was primarily the result of an increase in location repairs and disposal costs, partially offset by aour 21% decrease in property taxes. However, due to a 7% increase in our production volumesproduction. Per unit LOE was relatively flat for the threesix months ended SeptemberJune 30, 20192020 as compared to the threesix months ended SeptemberJune 30, 2018, our per unit LOE decreased by 6% from $0.17 per Mcfe to $0.16 per Mcfe.2019.
Production Taxes. Production
Six months ended June 30,
20202019change
($ In thousands, except per unit)
Production taxes$8,404  $16,019  (48)%
Production taxes per Mcfe$0.04  $0.07  (34)%
The decrease in production taxes decreased $2.7 million, or 29%, to $6.6 million for the three months ended September 30, 2019 from $9.3 million for the three months ended September 30, 2018. This decrease was primarily duerelated to a decrease in commodityrealized prices as taxesand production for the six months ended June 30, 2020.
Six months ended June 30,
20202019change
($ In thousands, except per unit)
Midstream gathering and processing expenses$117,870  $142,297  (17)%
Midstream gathering and processing expenses per Mcfe$0.62  $0.60  4 %
The decrease in Ohio are assessed off of value, and the sale of our Louisiana assets, partially offset by an increase in the production tax rate associated with our SCOOP production.
Midstream Gathering and Processing Expenses. Midstreammidstream gathering and processing expenses decreased to $78.4 million for the three months ended September 30, 2019 from $78.9 million for the same period in 2018. This $0.5 million, or 1%, decrease was primarily attributable to a decrease in production volumes related to our Utica Shale non-operated properties partially offset by an increase21% decrease in our production volumes relatedfor the six months ended June 30, 2020 as compared to both our Utica Shale operated propertiesthe six months ended June 30, 2019. Per unit midstream gathering and SCOOP non-operated properties.processing expenses was relatively flat for the six months ended June 30, 2020 as compared to the six months ended June 30, 2019.
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Depreciation, Depletion and Amortization.
Six months ended June 30,
20202019change
($ In thousands, except per unit)
Depreciation, depletion and amortization$142,818  $243,384  (41)%
Depreciation, depletion and amortization per Mcfe$0.75  $1.03  (26)%
Depreciation, depletion and amortization ("DD&A") expense increased to $145.5 million for the three months ended September 30, 2019, and consisted of $142.7$137.6 million in depletion of oil and natural gas properties and $2.8$5.2 million in depreciation of other property and equipment, as compared to total$237.7 million in depletion of oil and natural gas properties and $5.7 million in depreciation of other property and equipment for the six months ended June 30, 2019. The decrease in DD&A expense of $119.9 million for the three months ended September 30, 2018. This $25.6 million, or 21%, increase was primarily due to an increaseboth a decrease in our depletion rate as a result of a decrease in our total proved reserves volumes used to calculate our total DD&A expense,amortization base from full cost ceiling test impairments recorded during 2019 and the first quarter of 2019 as well as an increasea decrease in our production.
GeneralImpairment of Oil and Administrative ExpensesGas Properties. . Net general and administrative expenses decreased to $14.7 million forDuring the threesix months ended SeptemberJune 30, 2019 from $15.8 million for the three months ended September 30, 2018. This2020, we incurred $1.1 million, or 7%, decrease was primarily due to decreases in salaries and benefits, consulting fees and travel expense, partially offset by increases in legal expense. In addition, for the three months ended September 30, 2019, we decreased our unit general and administrative expense by 17% to $0.10 per Mcfe from $0.12 per Mcfe for the three months ended September 30, 2018.
Interest Expense. Interest expense increased to $34.1 million for the three months ended September 30, 2019 as compared to $33.3 million for the three months ended September 30, 2018 due primarily to increased borrowings on our revolving credit facility as compared to the same period in 2018, partially offset by a decrease in outstanding senior notes as a resultbillion of debt repurchases. In addition, total weighted average debt outstanding under our revolving credit facility was $223.1 million for the three months ended September 30, 2019 as compared to $74.0 million debt outstanding under such facility. As of September 30, 2019, amounts borrowed under our revolving credit facility bore interest at a weighted average rate of 3.52%. In addition, we capitalized approximately $1.0 million and $1.6 million in interest expense to undeveloped oil and natural gas properties impairment charges related primarily to the decline in the twelve month trailing first of month average price for natural gas, oil and NGL compared to no impairment charge of oil and gas properties during the threesix months ended SeptemberJune 30, 20192019.
Equity Investments
Six months ended June 30,
20202019change
($ In thousands, except per unit)
Loss from equity method investments, net$10,834  $121,309  (91)%
The decrease in loss from equity method investments is primarily related to a $125.4 million impairment charge recorded during the six months ended June 30, 2019. The value of our investment in Mammoth was reduced to zero during the first quarter of 2020, and 2018, respectively.we did not record any similar impairment charges during the six months ended June 30, 2020. See Note 4 to our consolidated financial statements for further discussion on our equity investments.
General and Administrative Expenses
Six months ended June 30,
20202019change
($ In thousands, except per unit)
General and administrative expenses, gross$46,306  $43,980  5 %
Reimbursed from third parties$(6,075) $(5,667) 7 %
Capitalized general and administrative expenses$(13,592) $(16,529) (18)%
General and administrative expenses, net$26,639  $21,784  22 %
General and administrative expenses, net per Mcfe$0.14  $0.09  53 %
The increase in general and administrative expenses, gross was due primarily due to an increase in non-recurring legal and consulting charges for the six months ended June 30, 2020 as compared to the six months ended June 30, 2019. This $0.6 millionincrease was partially offset by lower employee costs resulting from the reduction in workforce that was completed in the fourth quarter of 2019. Additionally, in June 2020, in response to the continued depressed commodity price environment, we announced several G&A initiatives to reduce our corporate cost structure. The decrease in capitalized general and administrative expenses was due to lower development activities for the six months ended June 30, 2020 as compared to the six months ended June 30, 2019.
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Interest Expense
Six months ended June 30,
 20202019
($ In thousands, except per unit)
Interest expense on senior notes57,299  64,562  
Interest expense on revolving credit agreement5,025  5,479  
Interest expense on construction loan and other650  578  
Capitalized interest(710) (1,771) 
Amortization of loan costs3,092  3,191  
Total interest expense$65,356  $72,039  
Interest expense per Mcfe$0.35  $0.30  
Weighted average debt outstanding under revolving credit facility$107,027  $123,287  
The decrease in interest inexpense for the six months ended June 30, 2020 as compared to the six months ended June 30, 2019 period was primarily the resultdue to continued repurchases of changes to our development plan for our oil and natural gas properties.senior notes.
Income Taxes. We recorded income tax expense of 7.3 million for the six months ended June 30, 2020 compared to income tax benefit of 179.3 million for the six months ended June 30, 2019. As of SeptemberJune 30, 2019,2020, we had a federal net operating loss carryforward of approximately $942.9 million$1.5 billion from prior years, in addition to numerous temporary differences, which gave rise to a net deferred tax asset. Quarterly, management performs a forecast of our taxable income and analyzes other relevant factors to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established if, in management’s opinion, it is more likely than not that some portion will not be realized. DuringAt June 30, 2020, a valuation allowance of $879.3 million has been maintained against the threefull net deferred tax asset. Income tax expense recorded during the six months ending Septemberended June 30, 2020 is related to the recognition of a valuation allowance against a state deferred tax asset during the first quarter of 2020. The tax benefit recorded during the six months ended June 30, 2019 management determinedwas a result of management's determination there was sufficient positive evidence that it was more likely than not that the federal and some state net operating loss carryforwards shouldwould be realized and recorded a discrete tax benefit of $28.0 million. We will recognize through the annual effective tax rate a projected release of valuation allowance of an additional $0.3 million with respect to current year earnings. We will maintain a valuation allowance of $4.8 million against the net deferred tax asset for certain tax attributes for which we have determined it is more likely than not those attribute carryforwards will expire prior to utilization.
Comparison of the Nine Month Periods Ended September 30, 2019 and 2018
We reported net income of $248.4 million for the nine months ended September 30, 2019 as compared to net income of $296.6 million for the nine months ended September 30, 2018. This $48.2 million period-to-period decrease was due primarily to a $199.7 million increase in loss from equity method investments, including a $160.8 million impairment related to our

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investment in Mammoth Energy, a $124.8 million decrease in gain on sale of equity method investments, a $35.6 million oil and natural gas properties impairment charge related to the decline in commodity prices, a $36.1 million increase in DD&A and a $6.2 million increase in midstream gathering and processing expenses, partially offset by a $205.8 million increase in income tax benefit, a $125.7 million increase in natural gas, oil and NGL revenues and a $23.6 million increase in gain on debt extinguishment for the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018. Additional impairments of oil and natural gas properties are expected to occur in upcoming quarters should commodity prices continue below the average of the previous 12 months. However, the amount of any future impairments is difficult to predict as it depends on changes in commodity prices, production rates, proved reserves, evaluation of costs excluded from amortization, future development costs and production costs. The gain on sale of equity investments in 2018 was a result of the sale of our interest in Strike Force Midstream LLC ("Strike Force") and the sale of Mammoth Energy common stock during 2018.
Oil and Gas Revenues. For the nine months ended September 30, 2019, we reported oil and natural gas revenues of $1.1 billion as compared to oil and natural gas revenues of $939.1 million during the same period in 2018. This $125.7 million, or 13%, increase in revenues was primarily attributable to the following:
A $275.9 million increase in natural gas, oil and condensate and NGLs sales due to a favorable change in gains and losses from derivative instruments. Of the total change, $204.8 million was due to favorable changes in the fair value of our open derivative positions in each period and $71.1 million was due to a favorable change in settlements related to our derivative positions. The favorable change in fair value of our open derivative positions is primarily a result of the decrease in the forward curve prices for natural gas from the previous reporting period.
These increases were partially offset by:

•
A $38.8 milliondecrease in natural gas sales without the impact of derivatives due to a 10% decrease in natural gas market prices, partially offset by a 5%increase in natural gas sales volumes.

•
A $46.7 million decrease in oil and condensate sales without the impact of derivatives due to a 20%decrease in oil and condensate sales volumes and a 17% decrease in oil and condensate market prices.

•
A $63.7 million decrease in NGLs sales without the impact of derivatives due to a 35% decrease in NGLs market prices and a 16% decrease in NGLs sales volumes.

A $1.0 million decrease in natural gas, oil and condensate and NGLs sales due to an unfavorable change in the fair value of the contingent consideration arrangement related to the Louisiana asset sale.

The following table summarizes our oil and condensate, natural gas and NGLs production and related pricing for the nine months ended September 30, 2019, as compared to such data for the nine months ended September 30, 2018:

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 Nine months ended September 30,
 2019 2018
 ($ In thousands)
Natural gas sales   
Natural gas production volumes (MMcf)343,753
 327,272
    
Total natural gas sales$714,500
 $753,261
    
Natural gas sales without the impact of derivatives ($/Mcf)$2.08
 $2.30
Impact from settled derivatives ($/Mcf)$0.20
 $0.14
Average natural gas sales price, including settled derivatives ($/Mcf)$2.28
 $2.44
    
Oil and condensate sales   
Oil and condensate production volumes (MBbls)1,735
 2,166
    
Total oil and condensate sales$93,942
 $140,687
    
Oil and condensate sales without the impact of derivatives ($/Bbl)$54.13
 $64.96
Impact from settled derivatives ($/Bbl)$1.50
 $(10.28)
Average oil and condensate sales price, including settled derivatives ($/Bbl)$55.63
 $54.68
    
NGLs sales   
NGLs production volumes (MGal)165,970
 196,695
    
Total NGLs sales$78,136
 $141,883
    
NGLs sales without the impact of derivatives ($/Gal)$0.47
 $0.72
Impact from settled derivatives ($/Gal)$0.06
 $(0.06)
Average NGLs sales price, including settled derivatives ($/Gal)$0.53
 $0.66
    
Natural gas, oil and condensate and NGLs sales   
Gas equivalents (MMcfe)377,875
 368,366
    
Total natural gas, oil and condensate and NGLs sales$886,578
 $1,035,831
    
Natural gas, oil and condensate and NGLs sales without the impact of derivatives ($/Mcfe)$2.35
 $2.81
Impact from settled derivatives ($/Mcfe)$0.21
 $0.03
Average natural gas, oil and condensate and NGLs sales price, including settled derivatives ($/Mcfe)$2.56
 $2.84
    
Production Costs:   
Average production costs ($/Mcfe)$0.17
 $0.17
Average production taxes ($/Mcfe)$0.06
 $0.07
Average midstream gathering and processing ($/Mcfe)$0.58
 $0.58
Total production costs, midstream costs and production taxes ($/Mcfe)$0.81
 $0.82


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Lease Operating Expenses. Lease operating expenses not including production taxes increased to$64.7 million for the nine months ended September 30, 2019 from $64.1 million for the nine months ended September 30, 2018. This $0.6 million, or 1%, increase was primarily the result of an increase in expenses related to location repair, disposal costs and overhead, partially offset by a decrease in wireline services, facility maintenance expense and insurance.realized.
Production Taxes. Production taxes decreased to $22.6 million for the nine months ended September 30, 2019 from $23.9 million for the same period in 2018. This $1.3 million, or 5%, decrease was primarily related to a decrease in commodity prices, as taxes in Ohio are assessed off of value, and the sale of our Louisiana assets, partially offset by an increase in the production tax rate associated with our SCOOP production.
Midstream Gathering and Processing Expenses. Midstream gathering and processing expenses increased to $220.7 million for the nine months ended September 30, 2019 from $214.5 million for the same period in 2018. This $6.2 million, or 3%, increase was primarily attributable to midstream expenses related to our increased production volumes in the Utica Shale and SCOOP resulting from our 2018 and 2019 drilling activities as well as routine contract escalations associated with our Utica Shale production.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased to $388.9 million for the nine months ended September 30, 2019, and consisted of $380.4 million in depletion of oil and natural gas properties and $8.5 million in depreciation of other property and equipment, as compared to total DD&A expense of $352.8 million for the nine months ended September 30, 2018. This $36.1 million, or 10%, increase was primarily due to an increase in our depletion rate as a result of a decrease in our total proved reserves volumes used to calculate our total DD&A expense and an increase in our production.
General and Administrative Expenses. Net general and administrative expenses decreased to $39.5 million for the nine months ended September 30, 2019 from $43.0 million for the nine months ended September 30, 2018. This $3.5 million, or 8%, decrease was primarily due to decreases in salaries and benefits, consulting fees and travel expense, partially offset by increases in tax services and computer support. In addition, for the nine months ended September 30, 2019, we decreased our unit general and administrative expense by 17% to $0.10 per Mcfe from $0.12 per Mcfe the nine months ended September 30, 2018.
Interest Expense. Interest expense increased to$103.1 million for the nine months ended September 30, 2019 from $100.9 million for the nine months ended September 30, 2018 due primarily to increased borrowings on our revolving credit facility as compared to the same period in 2018, partially offset by a decrease in outstanding senior notes as a result of debt repurchases. Total weighted average debt outstanding under our revolving credit facility was $156.9 million for the nine months ended September 30, 2019 as compared to $91.3 million for the same period in 2018. Additionally, we capitalized approximately $2.8 million and $4.0 million in interest expense to undeveloped oil and natural gas properties during the nine months ended September 30, 2019 and September 30, 2018, respectively. This $1.2 million decrease in capitalized interest in the 2019 period was primarily the result of changes to our development plan for our oil and natural gas properties.
Income Taxes. As of September 30, 2019, we had a federal net operating loss carryforward of approximately $942.9 million from prior years, in addition to numerous temporary differences, which gave rise to a net deferred tax asset. Quarterly, management performs a forecast of our taxable income and analyzes other relevant factors to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established if, in management’s opinion, it is more likely than not that some portion will not be realized. During the nine months ending September 30, 2019, management determined there was sufficient positive evidence that it was more likely than not that the federal and some state net operating loss carryforwards should be realized and recorded a discrete tax benefit of $207.4 million. We will recognize through the annual effective tax rate a projected release of valuation allowance of an additional $0.3 million with respect to current year earnings. We will maintain a valuation allowance of $4.8 million against the net deferred tax asset for certain tax attributes for which we have determined it is more likely than not those attribute carryforwards will expire prior to utilization.
Liquidity and Capital Resources
Overview.
Historically, our primary sources of fundscapital funding and liquidity have been our operating cash flow, from our producing oil and natural gas properties, borrowings under our revolving credit facility and issuances of equity and debt securities. Our ability to access any of these sources of funds can be significantly impacted by changes in capital markets, decreases in commodity prices and decreases in our production levels.
In 2020, decreased demand for oil and natural gas as a result of the COVID-19 pandemic and the accompanying decrease in commodity prices has significantly reduced our ability to access capital markets and to refinance our existing indebtedness. Further, these conditions have made amendments or waivers to our revolving credit facility more difficult to obtain and available on terms less favorable to us. If depressed commodity prices persist or decline further, the borrowing base under our revolving credit facility could be further reduced at our next scheduled redetermination date in November 2020. Any such reduction would constrain our liquidity and may impair our ability to fund our planned capital expenditures and meet our obligations under our existing indebtedness. Further, a reduction in our capital expenditures would decrease our production, revenues, operating cash flow and EBITDA, which could limit our ability to comply with the restrictive covenants in our revolving credit facility and other existing indebtedness. Finally, our existing revolving credit facility matures in December 2021 and therefore will become a current liability at year end 2020 unless we are able to refinance the credit facility with a new credit facility or other financing. Considering the current state of the first lien market and our elevated leverage profile, there is substantial risk that a refinancing will not be available to us on reasonable terms. A current liability under the revolving credit facility at year end 2020 may result in a qualified audit opinion which could result in a default under the terms of the current revolving credit facility. As a result of these uncertainties and other factors, management has concluded that there is substantial doubt about our ability to continue as a going concern. Failure to meet our obligations under our existing indebtedness or failure to comply with any of our covenants, if not waived, would result in an event of default under such indebtedness and result in the potential acceleration of outstanding indebtedness thereunder and, with respect to the revolving credit facility, the
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potential foreclosure on the collateral securing such debt, and could cause a cross-default under our other outstanding indebtedness.

As of June 30, 2020, we had a cash balance of $2.8 million compared to $6.1 million as of December 31, 2019, and a net working capital deficit of $176.2 million as of June 30, 2020, compared to a net working capital deficit of $145.3 million as of December 31, 2019. As of June 30, 2020, our working capital deficit includes $0.6 million of debt due in the next 12 months. Our total principal debt as of June 30, 2020 was $1.9 billion compared to $2.0 billion as of December 31, 2019. As of June 30, 2020, we had $252.9 million of borrowing capacity available under the revolving credit facility, with outstanding borrowings of $123.0 million and $324.1 million utilized for various letters of credit.  See Note 5 of the notes to our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our notes.
Derivatives and Hedging Activities. Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. Our natural gas, production.oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to predict with greater certainty the total revenue we will receive.

As of June 30, 2020, we had the following open natural gas, oil and NGL derivative instruments:
Natural Gas Derivatives
YearType of Derivative InstrumentIndexDaily Volume (MMBtu/day)Weighted
Average Price ($)
2020SwapsNYMEX Henry Hub357,000  2.86  
2020Basis SwapsVarious70,000  (0.12) 
2021Costless CollarsNYMEX Henry Hub250,000  2.46/2.81
2022Sold Call OptionsNYMEX Henry Hub628,000  2.90  
2023Sold Call OptionsNYMEX Henry Hub628,000  2.90  
Oil Derivatives
YearType of Derivative InstrumentIndexDaily Volume (Bbls/day)Weighted
Average Price ($)
2020SwapsNYMEX WTI3,000  35.49  
NGL Derivatives
YearType of Derivative InstrumentIndexDaily Volume (Bbls/day)Weighted
Average Price ($)
2020SwapsMont Belvieu C31,500  20.27  
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Net cash flow provided by operating activities was $617.4 millionthe notes to our consolidated financial statements for further discussion of derivatives and hedging activities. Additionally, as discussed in Note 16, we brought forward the nine months ended September 30, 2019 as compared to $630.8 million for the same period in 2018. This $13.4 million decrease was primarily the resultvalue of a decrease in cash receipts from our oil swaps by monetizing our remaining position in April 2020 and natural gas purchasers dueentered into additional contracts to a 7% decreasehedge our remaining 2020 and 2021 production in net revenues after giving effect to settled derivative instrumentsApril and an increase in our operating expenses. In addition, we received $2.5 million in dividends from our investment in Mammoth Energy during the nine months ended September 30, 2019.
Net cash used in investing activities for the nine months ended September 30, 2019 was $638.6 million as compared to $554.6 million for the same period in 2018. During the nine months ended September 30, 2019, we spent $646.5 million in additions to oil and natural gas properties, of which $364.6 million was spent on our 2019 drilling and completion activities, $183.6 million was spent on expenses attributable to wells spud, completed and recompleted during 2018, $34.9 million was spent on lease related costs, primarily the acquisition of leases in the Utica Shale and $32.5 million was spent on tubulars, with the remainder attributable mainly to future location development and capitalized general and administrative expenses. During the nine months ended September 30, 2019, we invested $0.4 million in Grizzly and received a distribution of $2.1 million from Tatex Thailand II, LLC ("Tatex II"). We did not make any investments in our other equity investments during the nine months ended September 30, 2019.
Net cash used in financing activities for the nine months ended September 30, 2019 was $20.9 million as compared to $51.2 million for the same period in 2018. The 2019 amount used in financing activities is primarily attributable to purchases under our stock repurchase program of approximately $30.0 million and repurchase of senior notes of $79.5 million, partially offset by net borrowings under our credit facility.May 2020.
Credit Facility.
We have entered into a senior secured revolving credit facility, as amended, with The Bank of Nova Scotia, as the lead arranger and administrative agent and other lenders. The credit agreement provides for a maximum facility amount of $1.5 billion and matures on December 13, 2021. As of SeptemberJune 30, 2019,2020, we had a borrowing base of $1.4 billion, with anand elected commitment of $1.0 billion,$700.0 million and $135.0$123.0 million in borrowings outstanding. Total funds available for borrowing under our revolving credit facility, after giving effect to an aggregate of $248.6$324.1 million of outstanding letters of credit, were $616.4$252.9 million as of SeptemberJune 30, 2019.2020. This facility is secured by substantially all of our assets. Our wholly owned subsidiaries, excluding Grizzly Holdings Inc. ("Grizzly Holdings") and Mule Sky LLC ("Mule Sky"), guarantee our obligations under our revolving credit facility.
Advances under our revolving credit facility may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate, which ranges from 0.25% to 1.25%, plus (2) the highest of: (a) the federal funds rate plus 0.50%, (b) the rate of interest in effect for such day as publicly announced from time to time by agent as its “prime rate,” and (c) the eurodollar rate for an interest period of one month plus 1.00%. The interest rate for eurodollar loans is equal to (1) the applicable rate, which ranges from 1.25% to 2.25%, plus (2) the London interbank offered rate that appears on pages LIBOR01 or LIBOR02 of the Reuters screen that displays such rate for deposits in U.S. dollars, or, if such rate is not available, the rate as administered by ICE Benchmark Administration (or any other person that takes over administration of such rate) per annum equal to the offered rate on such other page or other service that displays an average London interbank offered rate as administered by ICE Benchmark Administration (or any other person that takes over the administration of such rate) for deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major New York money center banks of whom the agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. At September 30, 2019, amounts borrowed under our credit facility bore interest at a weighted average rate of 3.52%.
Our revolving credit facility contains customary negative covenants including, but not limited to, restrictions on our and our subsidiaries’ ability to: incur indebtedness; grant liens; pay dividends and make other restricted payments; agree to payment restrictions affecting our restricted subsidiaries; make investments; makeundertake fundamental changes;changes including selling all or substantially all of our assets; enter into swap contracts and forward sales contracts; dispose of assets; change the nature of their business; and enter into transactions with their affiliates.affiliates; and engage in certain transactions with restricted subsidiaries. The negative covenants are subject to certain exceptions as specified in our revolving credit facility. Our revolving credit facility also contains certain affirmative covenants, including, but not limited to the following financial covenants: (1) the ratio of net funded debtNet Secured Debt to EBITDAX (net income, excluding (i) any non-cash revenue or expense associated with swap contracts resulting from ASC 815 and (ii) any cash or non-cash revenue or expense attributable to minority investment plus without duplication and, in(as defined under the case of expenses, to the extent deducted from revenues in determining net income, the sum of (a) the aggregate amount of consolidated interest expense for such period, (b) the aggregate amount of income, franchise, capital or similar tax expense (other than ad valorem taxes) for such period, (c) all amounts attributable to depletion, depreciation, amortization and asset or goodwill impairment or writedown for such period, (d) all other non-cash charges, (e) exploration costs deducted in determining net income under successful efforts accounting, (f) actual cash distributions received from minority investments, (g) to the extent actually reimbursed by insurance,

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expenses with respect to liability on casualty events or business interruption, and (h) all reasonable transaction expenses related to dispositions and acquisitions of assets, investments and debt and equity offerings (provided that expenses related to any unsuccessful dispositions will be limited to $3.0 million in the aggregate) for a twelve-month periodrevolving credit agreement) may not be greater than 4.002.00 to 1.00;1.00 for the
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twelve-month period of the end of each fiscal quarter; and (2) the ratio of EBITDAX to interest expense for athe twelve-month period at the end of each fiscal quarter may not be less than 3.00 to 1.00. On May 1, 2020, we entered into a fifteenth amendment to our Amended and Restated Credit Agreement. As part of the amendment, our borrowing base and elected commitment were reduced from $1.2 billion and $1.0 billion, respectively, to $700.0 million. Additionally, the amendment added the requirement to maintain a ratio of Net Secured Debt to EBITDAX as described above, deferred the requirement to maintain a ratio of Net Funded Debt to EBITDAX of 4.00 to 1.00 until September 30, 2021, and added a limitation on the repurchase of unsecured notes, among other amendments. We were in compliance with these financial covenants at SeptemberJune 30, 2019.2020.
On July 27, 2020, we entered into the sixteenth amendment to the Amended and Restated Credit Agreement. The sixteenth amendment allows us to issue up to $750 million in second lien debt subject to certain conditions.
Senior Notes.
In April 2015, we issued an aggregate of $350.0 million in principal amount of our 2023 Notes. Interest on these senior notes accrues at a rate of 6.625% per annum on the outstanding principal amount thereof from April 21, 2015, payable semi-annually on May 1 and November 1 of each year, commencing on November 1, 2015. The 2023 Notes will mature on May 1, 2023.
On October 14, 2016, we issued an aggregate of $650.0 million in principal amount of our 2024 Notes. Interest on the 2024 Notes accrues at a rate of 6.000% per annum on the outstanding principal amount thereof from October 14, 2016, payable semi-annually on April 15 and October 15 of each year, commencing on April 15, 2017. The 2024 Notes will mature on October 15, 2024.
On December 21, 2016, we issued an aggregate of $600.0 million in principal amount of our 2025 Notes. Interest on the 2025 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof from December 21, 2016, payable semi-annually on May 15 and November 15 of each year, commencing on May 15, 2017. The 2025 Notes will mature on May 15, 2025.
On October 11, 2017, we issued $450.0 million in aggregate principal amount of our 2026 Notes. Interest on the 2026 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof from October 11, 2017, payable semi-annually on January 15 and July 15 of each year, commencing on January 15, 2018. The 2026 Notes will mature on January 15, 2026.
During the three months ended September 30, 2019, weWe used borrowings under our revolving credit facility to repurchase in the open market approximately $104.4$47.5 million and $73.3 million aggregate principal amount of our outstanding Notes for $80.3 million. This$12.6 million and $22.8 million during the three and six months ended June 30, 2020, respectively. For the three months ended June 30, 2020, this included approximately $10.0$4.9 million principal amount of the 2023 Notes, $19.2$16.3 million principal amount of the 2024 Notes, $22.7$13.5 million principal amount of the 2025 Notes, and $52.5$12.8 million principal amount of the 2026 Notes. We recognized a $23.6$34.3 million and $49.6 million gain on debt extinguishment, which included retirement of unamortized issuance costs and fees associated with the repurchased debt.debt, during the three and six months ended June 30, 2020, respectively.
All ofSubject to restrictions in our existing and future restricted subsidiaries that guarantee our securedown revolving credit facility, or certain other debt guarantee the Notes, provided, however, that the Notes are not guaranteed by Grizzly Holdings or Mule Sky, and will not be guaranteed by any of our future unrestricted subsidiaries. The guarantees rank equally in the right of payment with all of the senior indebtedness of the subsidiary guarantors and senior in the right of payment to any future subordinated indebtedness of the subsidiary guarantors. The Notes and the guarantees are effectively subordinated to all of our and the subsidiary guarantors’ secured indebtedness (including all borrowings and other obligations under our amended and restated credit agreement) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated to all indebtedness and other liabilities of any of our subsidiaries that do not guarantee the Notes.
If we experience a change of control (as defined in the senior note indentures relating to the Notes), we will be required to make an offer to repurchase the Notes and at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase. If we sell certain assets and fail to use the proceeds in a manner specified in our senior note indentures, we will be required to use the remaining proceeds to make an offer to repurchase the Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase. The senior note indentures relating to the Notes contain certain covenants that, subject to certain exceptions and qualifications, among other things, limit our ability and the ability of our restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make distributions on capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted subsidiaries, agree to payment restrictions affecting our restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of our assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and gas business and designate certain of our subsidiaries as unrestricted subsidiaries. Under the indentures relating to the Notes, certain of these covenants are subject to termination upon the occurrence of certain events, including in the event the Notes are ranked as “investment grade.”

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In connection with the issuance of the 2024 Notes, 2025 Notes and 2026 Notes, we and our subsidiary guarantors entered into registration rights agreements, pursuant to which we agreed to file a registration statement with respect to offers to exchange the 2024 Notes, 2025 Notes and 2026 Notes, as applicable, for new issues of substantially identical debt securities registered under the Securities Act. The exchange offers for the 2024 Notes and 2025 Notes were completed on September 13, 2017, and the exchange offer for the 2026 Notes was completed on March 22, 2018.
We may use a combination of cash and borrowingsborrowing under our
revolving credit facility to retire our outstanding debt, through privately negotiated transactions, open market repurchases,
redemptions, tender offers or otherwise, but we are under no obligation to do so.
Construction Loan.
On June 4, 2015, we entered into a construction loan agreement (the "construction loan") with InterBank for the construction of our new corporate headquarters in Oklahoma City, which was substantially completed in December 2016. The construction loan allows for maximum principal borrowings of $24.5 million and required us to fund 30% of the cost of the construction before any funds could be drawn, which occurred in January 2016. Interest accrues daily on the outstanding principal balance at a fixed rate of 4.50% per annum and we make monthly payments of interest and principal. The final payment is due June 4, 2025. As of September 30, 2019, the total borrowings under the construction loan were approximately $22.7 million.
Capital Expenditures.
Our recent capital commitments have been primarily for the execution of our drilling programs for acquisitions in the Utica Shale and our SCOOP acquisition in 2017, and for investments in entities that may provide services to facilitate the developmentdiscounted repurchases of our acreage.senior notes. Our capital investment strategy is to continue to (1) increase cash flow generated from our operations by undertaking new drilling and workover projects to exploitfocused on prudently developing our existing properties subject to economicgenerate sustainable cash flow considering current and industry conditionsforecasted commodity prices while also selectively pursuing mergers or acquisitions in our current operating regions in an effort to gain scale and (2) pursue select acquisition and disposition opportunities.deepen our drilling inventory.
Of our net reserves at December 31, 2018, 55.4% were categorized as proved undeveloped. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved developed reserves, or both. To realize reserves and increase production, we must continue our exploratory drilling, undertake other replacement activities or use third parties to accomplish those activities.
For further discussion on activities related to our capital expenditures incurred through September 30, 2019 see 2019 Productionfor 2020 are currently estimated to be in the range of $265.0 million to $285.0 million for drilling and Drilling Activity section above.
As of September 30, 2019, our net investment in Grizzly was approximately $49.5 million. We do not currently anticipate any material capital expenditures in 2019 related to Grizzly’s activities.
completion expenditures. In response to current declining forward natural gas prices, we are shifting to building an organization that is focused on disciplined capital allocation, cash flow generation and a commitment to executing a thoughtful, clearly communicated business plan that enhances value for all of our stockholders. We plan to maximize results with the core assets in our portfolio today and focus on returns that will allow us to operate within operating cash flow in 2019. As a result,addition, we currently expect 2019 capital expenditures to be approximately 29% lower than 2018.
Our operated drilling and completion capital expenditures for 2019 were weighted to the first half of the year. For the nine months ended September 30, 2019 we incurred $423.7 million for operated drilling and completion capital expenditures and $72.6 million for non-operated drilling and completion capital expenditures. We currently expect to incur $40.0spend $20.0 million to $50.0$25.0 million in 20192020 for non-drilling and completion expenditures, which includes acreage expenses, primarily lease extensions in the Utica Shale, of which $33.1 million was incurred as of September 30, 2019. Additionally, we are pursuing the sale of certain non-operated Utica Shale interests. NetShale. The midpoint of the planned divestiture of certain non-operated interests, we continue to expect our capital expenditures to be within our previously provided guidance range of $565.0 million to $600.0 million. The 20192020 range of capital expenditures is more than 50% lower than the $814.7$602.5 million incurredspent in 2018,2019, primarily due to the decreaseour decision to reduce capital activity in currentresponse to lower commodity prices, specifically natural gas prices, and our desire to fund our capital development program within cash flow, as well as to generate free cash flow.
In January 2019, our board of directors approved a new stock repurchase program to acquire a portion of our outstanding common stock within a 24 month period. We intend to purchase shares under the repurchase program opportunisticallyprimarily with

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available funds primarily from cash flow from operationsoperations. As a result of our decreased capital spending program for 2020 and salethe impact of non-core assets while maintaining sufficient liquidityour 2019 property divestitures, we expect our production volumes in 2020 to fund our capital development programs.be approximately 22% to 27% lower than 2019. Coupled with forecasted lower commodity prices, we expect 2020 revenues, operating cash flows and EBITDA to be significantly lower in 2020 as compared to 2019.
We continually monitor market conditions and are prepared to adjust our drilling program if commodity prices dictate. Currently, we believe that our cash flow from operations, cash on hand and borrowingsborrowing base availability under our revolving credit facilityagreement will be sufficient to meet our normal recurring operating needs and capital requirements for the next twelve months. We believe that our strong liquidity position, hedge portfolio and conservative balance sheet position us wellhave the ability to react quickly to changing commodity prices and accelerate or decelerate our activity within the Utica Shale and the SCOOPour operating areas as the market conditions warrant. Notwithstanding the foregoing, in the event commodity prices decline from current levels or our capital or other costs increase our equity method investments require additional contributions and/or we pursue additional equity method investments or acquisitions, we may be required to obtain additional funds which we would seek to do through traditional borrowings, offerings of debt or equity securities or other means, including the sale of assets. To the extent that access to capital and other financial markets is adversely affected by the effects of COVID-19, the Company may need to consider alternative sources of funding for some of its operations and for working capital, which may increase the cost of, as well as adversely impact access to, capital. We regularly evaluate newmerger, acquisition and divestiture opportunities. Needed capitalCapital may not be available to us on acceptable terms or at all.all in the future. Further, if we are unable to obtain funds when needed or on acceptable terms, we may be required to delay or curtail implementation of our business plan or not be able to complete acquisitions that may be favorable to us. If the current low commodity price environment worsens, our revenues, cash flows, results of operations, liquidity and reserves may be materially and adversely affected.
Commodity Price RiskCash Flow from Operating Activities. Net cash flow provided by operating activities was $247.2 million for the six months ended June 30, 2020 as compared to $399.8 million for the same period in 2019. This decrease was primarily the result of a significant decrease in our realized gas prices as well as decreases in our production volumes.
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Divestitures. During the six months ended June 30, 2020, we divested our SCOOP water infrastructure assets and received $50.0 million in cash upon closing and have an opportunity to earn additional incentive payments over the next 15 years, subject to our ability to meet certain thresholds which will be driven by, among other things, our future development program and future water production levels. Proceeds from the divestiture were used to reduce our outstanding revolver balance. See Item 3. “QuantitativeNote 3 of the notes to our consolidated financial statements for further discussion.
Use of Funds. The following table presents the uses of our cash and Qualitative Disclosures about Market Risk”cash equivalents for information regardingthe six months ended June 30, 2020 and 2019:
 Six months ended June 30,
20202019
(In thousands)
Oil and Natural Gas Property Cash Expenditures:
Drilling and completion costs255,904  435,583  
Leasehold acquisitions10,098  25,778  
Other8,849  46,954  
Total oil and natural gas property expenditures$274,851  $508,315  
Other Uses of Cash and Cash Equivalents
Cash paid to repurchase senior notes22,827  —  
Cash paid to repurchase common stock under approved stock repurchase program—  30,000  
Other801  5,444  
Total other uses of cash and cash equivalents$23,628  $35,444  
Total uses of cash and cash equivalents$298,479  $543,759  
Drilling and Completion Costs. During six months ended June 30, 2020, we spud 12 gross (11.1 net) and commenced sales from 13 gross and net operated wells in the Utica Shale for a total cost of approximately $141.5 million. During the six months ended June 30, 2020, we spud six gross (5.2 net) and commenced sales from four gross (3.8 net) operated wells in the SCOOP for a total cost of approximately $42.2 million.
During the six months ended June 30, 2020, we did not participate in any wells that were spud or turned to sales by other operators on our open fixed price swaps at SeptemberUtica Shale acreage. In addition, 5.00 gross (0.03 net) wells were spud and 5.00 gross (3.5 net) wells were turned to sales by other operators on our SCOOP acreage during the six months ended June 30, 2019.2020.
Contractual and Commercial Obligations
We have various contractual obligations in the normal course of our operations and financing activities. See Note 9 and Note 13 of the notes to our consolidated financial statements for further discussion of the termination of our Master Services Agreement with Stingray Pressure Pumping LLC, a subsidiary of Mammoth Energy Services, Inc. and a related party. There have been no other material changes to our contractual obligations from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2018.    2019. 
Off-balance Sheet Arrangements
We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations.  As of SeptemberJune 30, 2019,2020, our material off-balance sheet arrangements and transactions include $248.6$324.1 million in letters of credit outstanding against our 2019 revolving credit facility and $63.0$119.5 million in surety bonds issuedissued. Both the letters of credit and surety bonds are being used as financial assurance, primarily on midstreamcertain firm transportation agreements. Management believes these items will expire without being funded. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital
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resources. See Note 89 to our consolidated financial statements for further discussion of the various financial guarantees we have issued.
Critical Accounting Policies and Estimates
As of SeptemberJune 30, 2019,2020, there have been no significant changes in our critical accounting policies from those disclosed in our 20182019 Annual Report on Form 10-K.
New Accounting Pronouncements
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In February 2016,
ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Natural Gas, Oil and Natural Gas Liquids Derivative Instruments. Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL. To mitigate a portion of our exposure to adverse price changes, we have entered into various derivative instruments. Our natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to predict with greater certainty the Financial Accounting Standardsrevenue we will receive. We believe our derivative instruments continue to be highly effective in achieving our risk management objectives.
Our general strategy for protecting short-term cash flow and attempting to mitigate exposure to adverse natural gas, oil and NGL price changes is to hedge into strengthening natural gas, oil and NGL futures markets when prices reach levels that management believes are unsustainable for the long term, have material downside risk in the short term or provide reasonable rates of return on our invested capital. Information we consider in forming an opinion about future prices includes general economic conditions, industrial output levels and expectations, producer breakeven cost structures, liquefied natural gas trends, oil and natural gas storage inventory levels, industry decline rates for base production and weather trends. Executive management is involved in all risk management activities and the Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-02, Leases (Topic 842).of Directors reviews our derivative program at its quarterly board meetings. We believe we have sufficient internal controls to prevent unauthorized trading.
We use derivative instruments to achieve our risk management objectives, including swaps, options and costless collars. All of these are described in more detail below. We typically use swaps for a large portion of the oil and natural gas price risk we hedge. We have also sold calls, taking advantage of premiums associated with market price volatility.
We determine the notional volume potentially subject to derivative contracts by reviewing our overall estimated future production levels, which are derived from extensive examination of existing producing reserve estimates and estimates of likely production from new drilling. Production forecasts are updated at least monthly and adjusted if necessary to actual results and activity levels. We do not enter into derivative contracts for volumes in excess of our share of forecasted production, and if production estimates were lowered for future periods and derivative instruments are already executed for some volume above the new production forecasts, the positions would be reversed. The standard supersedesactual fixed price on our derivative instruments is derived from the previous lease guidance by requiring lessees to recognize a right-to-use asset and lease liabilityreference NYMEX price, as reflected in current NYMEX trading. The pricing dates of our derivative contracts follow NYMEX futures. All of our commodity derivative instruments are net settled based on the balance sheetdifference between the fixed price as stated in the contract and the floating-price, resulting in a net amount due to or from the counterparty.
We review our derivative positions continuously and if future market conditions change and prices are at levels we believe could jeopardize the effectiveness of a position, we will mitigate this risk by either negotiating a cash settlement with our counterparty, restructuring the position or entering a new trade that effectively reverses the current position. The factors we consider in closing or restructuring a position before the settlement date are identical to those we review when deciding to enter the original derivative position. Gains or losses related to closed positions will be recognized in the month specified in the original contract.
We have determined the fair value of our derivative instruments utilizing established index prices, volatility curves and discount factors. These estimates are compared to counterparty valuations for all leases with lease termsreasonableness. Derivative transactions are also subject to the risk that counterparties will be unable to meet their obligations. This non-performance risk is considered in the valuation of greater than one year while maintaining substantially similar classifications for financingour derivative instruments, but to date has not had a material impact on the values of our derivatives. Future risk related to counterparties not being able to meet their obligations has been partially mitigated under our commodity hedging arrangements that require counterparties to post collateral if their obligations to us are in excess of defined thresholds. The values we report in our financial statements are as of a point in time and operating leases. Subsequentsubsequently change as these estimates are revised to ASU 2016-02, the FASB issued several related ASU’s to clarify the applicationreflect actual results, changes in market conditions and other factors. See Note 10 of the lease standard. We adopted the new standard as of January 1, 2019 on a prospective basis using the simplified transition method permitted by ASU 2018-11, Leases (Topic 842): Targeted Improvements. The comparative information has not been restated and continues to be reported under the historic accounting standards in effect for those periods. See Note 13notes to our consolidated financial statements for further discussion of the lease standard.fair value measurements associated with our derivatives.
As of June 30, 2020, our natural gas, oil and NGL derivative instruments consisted of the following types of instruments:
•Swaps: We receive a fixed price and pay a floating market price to the counterparty for the hedged commodity. In exchange for higher fixed prices on certain of our swap trades, we may sell call options.
In June 2016,•Basis Swaps: These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point. We receive the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Instruments. This ASU amends guidance on reporting credit lossesfixed price differential and pay the floating market price differential to the counterparty for assets held at amortized cost basis and available for sale debt securities. For assets held at amortized cost basis, this ASU eliminates the probable initial recognitionhedged commodity.

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•Options: We sell, and occasionally buy, call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, we pay the counterparty the excess on sold call options, and we receive the excess on bought call options. If the market price settles below the fixed price of the call option, no payment is due from either party.
threshold in current GAAP•Costless Collars: These instruments have a set floor and instead, requires an entity to reflect its current estimateceiling price for the hedged production. If the applicable monthly price indices are outside of all expected credit losses. The amendments affect loans, debt securities, trade receivables, net investments in leases, off balance sheet credit exposure, reinsurance receivablesthe ranges set by the floor and any other financial assets not excluded from the scope that have the contractual right to receive cash. Additionally, in May 2019, the FASB issued ASU No. 2019-05, Financial Instruments—Credit Losses (Topic 326): Targeted Transition Relief. The amendments in this update allow preparers to irrevocably elect the fair value option, on an instrument-by-instrument basis, for eligible financial assets measured at amortized cost basis upon adoption of 2016-13. The guidance is effective for periods after December 15, 2019, with early adoption permitted. We areceiling prices in the process of designing processes and controls needed to complyvarious collars, we will cash-settle the difference with the requirements of the new standard. Although the standard will have an impact, we do not currently anticipate the ASU to have a material effect on our consolidated financial statements and related disclosures.counterparty.
In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement which removes, modifies, and adds certain disclosure requirements on fair value measurements. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. We do not anticipate the new standard to have a material effect on our consolidated financial statements and related disclosures.
In August 2018, the FASB also issued ASU No. 2018-15, Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, which aligns the accounting for costs associated with implementing a cloud computing arrangement in a hosting arrangement that is a service contract with the accounting for implementation costs incurred to develop or obtain internal-use software. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. We do not anticipate the new standard to have a material effect on our consolidated financial statements and related disclosures.
In November 2018, the FASB issued ASU No. 2018-18, Collaborative Arrangements (Topic 808): Clarifying the Interaction Between Topic 808 and Topic 606, which provides guidance on how to assess whether certain transactions between participants in a collaborative arrangement should be accounted for within the ASU No. 2014-09 revenue recognition standard discussed above. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. We do not anticipate the new standard to have a material effect on our consolidated financial statements and related disclosures.
In July 2019, the FASB issued ASU No. 2019-07, Codification Updates to SEC Sections, Amendments to SEC Paragraphs Pursuant to SEC Final Rule Releases No. 33-10532, Disclosure Update and Simplification, and Nos. 33-10231 and 33-10442, Investment Company Reporting Modernization, and Miscellaneous Updates. This ASU amends various SEC sections within the FASB Codification to align with the updated requirements of certain SEC final rules and includes miscellaneous updates to agree the language in the Codification to the electronic Code of Federal Regulations. ASU No. 2019-07 is effective upon issuance, and we have adopted the changes with no material impacts.
ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend primarily upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors, including: worldwide and domestic supplies of oil and natural gas; the level of prices, and expectations about future prices, of oil and natural gas; the cost of exploring for, developing, producing and delivering oil and natural gas; the expected rates of declining current production; weather conditions, including hurricanes, that can affect oil and natural gas operations over a wide area; the level of consumer demand; the price and availability of alternative fuels; technical advances affecting energy consumption; risks associated with operating drilling rigs; the availability of pipeline capacity; the price and level of foreign imports; domestic and foreign governmental regulations and taxes; the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; political instability or armed conflict in oil and natural gas producing regions; and the overall economic environment.
These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. During 2018, West Texas Intermediate ("WTI") prices ranged from $44.48 to $77.41 per barrel and the Henry Hub spot market price of natural gas ranged from $2.49 to $6.24 per MMBtu. On October 25, 2019, the WTI posted price for crude oil was $56.46 per Bbl and the Henry Hub spot market price for natural gas was $2.28 per MMBtu. If

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the prices of oil and natural gas decline from current levels, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected. In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Reductions in our reserves could also negatively impact the borrowing base under our revolving credit facility, which could further limit our liquidity and ability to conduct additional exploration and development activities.
To mitigate the effects of commodity price fluctuations on our oil and natural gas production, we had the following open fixed price swap positions at SeptemberJune 30, 2019:2020:
LocationDaily Volume (MMBtu/day)Weighted
Average Price
Remaining 2020NYMEX Henry Hub357,000  $2.86  
 LocationDaily Volume (MMBtu/day) Weighted
Average Price
Remaining 2019NYMEX Henry Hub1,380,000
 $2.81
2020NYMEX Henry Hub519,000
 $2.88
LocationDaily Volume
(Bbls/day)		Weighted
Average Price
Remaining 2020NYMEX WTI3,000  $35.49  
 LocationDaily Volume
(Bbls/day)		 Weighted
Average Price
Remaining 2019NYMEX WTI6,000
 $60.81
2020NYMEX WTI6,000
 $59.82

 LocationDaily Volume
(Bbls/day)		 Weighted
Average Price
Remaining 2019Mont Belvieu C21,000
 $18.48
Remaining 2019Mont Belvieu C34,000
 $29.02
Remaining 2019Mont Belvieu C51,000
 $53.71
LocationDaily Volume
(Bbls/day)		Weighted
Average Price
Remaining 2020Mont Belvieu C31,500  $20.27  
We sold call options in exchange for a premium, and used the associated premiums to enhance the fixed price for a portion of the fixed price natural gas swaps primarily for 2020 listed above. EachWe had the following open sold call option has an established ceiling price. Whenpositions at June 30, 2020:
LocationDaily Volume (MMBtu/day)Weighted
Average Price
2022NYMEX Henry Hub628,000  $2.90  
2023NYMEX Henry Hub628,000  $2.90  
We had the referenced settlement price is above the price ceiling established by these call options, we pay our counterparty an amount equal to the difference between the referenced settlement price and the price ceiling multiplied by the hedged contract volumes.following open costless collar positions at June 30, 2020:
LocationDaily Volume (MMBtu/day)Weighted Average Floor PriceWeighted Average Ceiling Price
2021NYMEX Henry Hub250,000  $2.46  $2.81  
 LocationDaily Volume (MMBtu/day) Weighted Average Price
Remaining 2019NYMEX Henry Hub30,000
 $3.10
2022NYMEX Henry Hub628,000
 $2.90
2023NYMEX Henry Hub628,000
 $2.90
For a portion of the natural gas fixed price swaps listed above, the counterparty has an option to extend the original terms an additional twelve months for the period January 2019 through December 2019. In December 2018, the counterparties chose to exercise all natural gas fixed price swaps, resulting in an additional 100,000 MMBtu per day at a weighted average price of $3.05 per MMBtu, which is included in the natural gas fixed price swaps listed above.
In addition, we have entered into natural gas basis swap positions. As of SeptemberJune 30, 2019, we2020, the Company had the following natural gas basis swap positions open:
 Gulfport PaysGulfport ReceivesDaily Volume (MMBtu/day) Weighted Average Fixed Spread
Remaining 2019Transco Zone 4NYMEX Plus Fixed Spread60,000
 $(0.05)
2020Transco Zone 4NYMEX Plus Fixed Spread60,000
 $(0.05)
2020Fixed SpreadONEOK Minus NYMEX10,000
 $(0.54)
Gulfport PaysGulfport ReceivesDaily Volume (MMBtu/day)Weighted Average Fixed Spread
Remaining 2020Transco Zone 4NYMEX Plus Fixed Spread60,000  $(0.05) 
Remaining 2020Fixed SpreadONEOK Minus NYMEX10,000  $(0.54) 

During the three months ended June 30, 2020, we early terminated oil fixed price swaps which represented approximately 6,000 BBls of oil per day for the remainder of 2020. The early termination resulted in a cash settlement of approximately $40.5 million.
In August 2020, we entered into natural gas fixed price swap contracts for the fourth quarter of 2020 covering approximately 100,000 MMBtu of natural gas per day at an average swap price of $2.38 per MMBtu.
Our fixed price swap contracts are tied to the commodity prices on NYMEX Henry Hub for natural gas and Mont Belvieu for propane, pentane and ethane. We will receive the fixed priced amount stated in the contract and pay to its counterparty the current market price as listed on NYMEX Henry Hub for natural gas or Mont Belvieu for propane, pentane and ethane.
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Contingent Consideration Arrangement
The purchase and sale agreement for the sale of our non-core assets located in the WCBB and Hackberry fields of Louisiana included a contingent consideration arrangement that entitles us to receive bonus payments if commodity prices exceed specified thresholds. The calculated fair value of this contingent payment arrangement was approximately $1.1 million as of the closing date of the divestiture. See below for threshold and potential payment amounts.
Period
Threshold(1)
Payment to be received(2)
July 2020 - June 2021Greater than or equal to $60.65$150,000
 Between $52.62 - $60.65
Calculated Value(3)

 Less than or equal to $52.62$—
(1)Based on the "WTI NYMEX + Argus LLS Differential," as published by Argus Media.
(2)Payment will be assessed monthly from July 2020 through June 2021. If threshold is met, payment shall be received within five business days after the end of each calendar month.
(3)If average daily price, as defined in (1), is greater than $52.62 but less than $60.65, payment received will be $150,000 multiplied by a fraction, the numerator of which is the amount determined by subtracting $52.62 from such average daily price, and the denominator of which is $8.03.
Under our 20192020 contracts, we have hedged approximately 91%59% to 94%63% of our estimated 20192020 production. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or commodity prices increase. At SeptemberJune 30, 2019,2020, we had a net asset derivative position of $85.5$3.3 million as compared to a net liabilityasset derivative position of $54.4$139.5 million as of SeptemberJune 30, 2018,2019, related to our fixed price swaps.hedging portfolio. Utilizing actual derivative contractual volumes, a 10% increase in underlying commodity prices would have reduced the fair value of these instruments by approximately $139.1$48.8 million, while a 10% decrease in underlying commodity prices would have increased the fair value of these instruments by approximately $124.3$43.1 million. However, any realized derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument.
Interest Rate Risk. Our revolving amended and restated credit agreement is structured under floating rate terms, as advances under this facility may be in the form of either base rate loans or eurodollar loans. As such, our interest expense is sensitive to fluctuations in the prime rates in the U.S.United States, or, if the eurodollar rates are elected, the eurodollar rates. At SeptemberJune 30, 2019,2020, we had $135.0$123.0 million in borrowings outstanding under our revolving credit facility which bore interest at a weighted average rate of 3.52%2.44%. A 1.0% increase in the average interest rate for the nine months ended September 30, 2019 would have resulted in an estimated $0.7 million increase in interest expense. As of SeptemberJune 30, 2019,2020, we did not have any interest rate swaps to hedge our interest risks.

ITEM 4.CONTROLS AND PROCEDURES
Evaluation of Disclosure Control and Procedures. Under the direction of our Chief Executive Officer and President and our Chief Financial Officer, we have established disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and President and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.
As of SeptemberJune 30, 2019,2020, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and President and our Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and President and our Chief Financial Officer have concluded that, as of SeptemberJune 30, 2019,2020, our disclosure controls and procedures are effective.were not effective because of the material weakness in our internal control over financial reporting described in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A of Part II of our Annual Report on Form 10-K for the year ended December 31, 2019.
Remediation Plan for the Material Weakness. Our management is actively engaged in the implementation of remediation efforts to address the material weakness identified in the fourth quarter of 2019. Specifically, our management is in the process of implementing new controls and processes over the evaluation and transfer of unevaluated costs to the amortizable base. Our management believes that these actions will remediate the material weakness in internal control over financial reporting.

Changes in Internal Control over Financial Reporting. There have not been any changes in our internal control over financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

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PART II
ITEM 1.LEGAL PROCEEDINGS
Litigation and Regulatory Proceedings
We are involved in a number of litigation and regulatory proceedings including those described below. Many of these proceedings are in early stages, and many of them seek or may seek damages and penalties, the amount of which is indeterminate. Our total accrued liabilities in respect of litigation and regulatory proceedings is determined on a case-by-case basis and represents an estimate of probable losses after considering, among other factors, the progress of each case or proceeding, ourits experience and the experience of others in similar cases or proceedings, and the opinions and views of legal counsel. Significant judgment is required in making these estimates and ourtheir final liabilities may ultimately be materially different.
We, along with a number of other oil and gas companies, have been named as a defendant in two separate complaints, one filed by the State of Louisiana and the Parish of Cameron in the 38th Judicial District Court for the Parish of Cameron on February 9, 2016 and the other filed by the State of Louisiana and the District Attorney for the 15th15th Judicial District of the State of Louisiana in the 15th15th Judicial District Court for the Parish of Vermilion on July 29, 2016 (together, the "Complaints"). The Complaints allege that certain of the defendants’ operations violated the State and Local Coastal Resources Management Act of 1978, as amended, and the rules, regulations, orders and ordinances adopted thereunder (the "CZM Laws") by causing substantial damage to land and waterbodies located in the coastal zone of the relevant Parish. The plaintiffs seek damages and other appropriate relief under the CZM Laws, including the payment of costs necessary to clear, re-vegetate, detoxify and otherwise restore the affected coastal zone of the relevant Parish to its original condition, actual restoration of such coastal zone to its original condition, and the payment of reasonable attorney fees and legal expenses and interest. The United States District Court for the Western District of Louisiana issued orders remanding the cases to their respective state court, and the defendants have appealed the remand orders to the 5th Circuit Court of Appeals.
In July 2019, Pigeon Land Company, Inc., a successor in interest to certain of our legacy Louisiana properties, filed an action against us and a number ofmany other oil and gas companies in the 16th Judicial District Court for the Parish of Iberia in Louisiana. The suit alleges negligence, strict liability and various violations of Louisiana statutes relating to property damage in connection with the historic development of our Louisiana properties and seeks unspecified damages (including punitive damages), an injunction to return the affected property to its original condition, and the payment of reasonable attorney fees and legal expenses and interest.
In September 2019, a stockholder of Mammoth Energy filed a derivative action on behalf of Mammoth Energy against members of Mammoth Energy’s board of directors, including a director designated by us, and its significant stockholders, including us, in the United States District Court for the Western District of Oklahoma. The complaint alleges, among other things, that the members of Mammoth Energy’s board of directors breached their fiduciary duties and violated the Securities Exchange Act of 1934, as amended, in connection with Mammoth Energy’s activities in Puerto Rico following Hurricane Maria. The complaint seeks unspecified damages, the payment of reasonable attorney fees and legal expenses and interest and to force Mammoth Energy and its board of directors to make specified corporate governance reforms.
In October 2019, Saydee Resources, LLC, on behalf of itself and a class of similarly situated royalty holders, filed an action against us in the District Court of Grady County Oklahoma. The suit alleges that we underpaid royalty holders and seeks unspecified damages for breach of contract, tortious breach of contract, fraud and unjust enrichment.
In October 2019, Kelsie Wagner, in her capacity as trustee of various trusts and on behalf of the trusts and other similarly situated royalty owners, filed an action against us in the District Court of Grady County, Oklahoma.  The suit alleges that we underpaid royalty owners and seeks unspecified damages for violations of the Oklahoma Production Revenue Standards Act and fraud.
In March 2020, Robert F. Woodley, individually and on behalf of all others similarly situated, filed a federal securities class action against us, David M. Wood, Keri Crowell and Quentin R. Hicks in the United States District Court for the Southern District of New York. The complaint alleges that we made materially false and misleading statements regarding our business and operations in violation of the federal securities laws and seeks unspecified damages, the payment of reasonable attorneys’ fees, expert fees and other costs, pre-judgment and post-judgment interest, and such other and further relief that may be deemed just and proper.
In June 2020, Sam L. Carter, derivatively on behalf of the Company, filed an action against certain of our current and former executive officers and directors in the United States District Court for the District of Delaware. The complaint alleges that the defendants breached their fiduciary duties to the Company in connection with certain alleged materially false and misleading statements regarding our business and operations in violation of the federal securities laws. The complaint seeks to
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recover unspecified damages from the defendants, the implementation of specified corporate governance reforms, reasonable attorneys’ and experts’ fees, costs and expenses, and such other relief as may be deemed just and proper.

In December 2019, we filed a lawsuit against Stingray Pressure Pumping LLC, a subsidiary of Mammoth Energy (“Stingray”), for breach of contract and to terminate the Master Services Agreement for pressure pumping services, effective as of October 1, 2014, as amended (the “Master Services Agreement”), between Stingray and us. In March 2020, Stingray filed a counterclaim against us in the Superior Court of the State of Delaware. The counterclaim alleges that we have breached the Master Services Agreement. The counterclaim seeks actual damages, which the complaint calculates to be approximately 28 million as of June 2020 (such amount to increase each month), the payment of reasonable attorney fees and legal expenses and pre- and post-judgment interest as allowed, and such other and further relief which it may be justly entitled.
In April 2020, Bryon Lefort, individually and on behalf of similarly situated individuals, filed an action against us in the United States District Court for the Southern District of Ohio Eastern Division. The complaint alleges that we violated the Fair Labor Standards Act (“FLSA”), the Ohio Wage Act and the Ohio Prompt Pay Act by classifying the plaintiffs as independent contractors and paying them a daily rate with no overtime compensation for hours worked in excess of 40 hours per week. The complaint seeks to recover unpaid regular and overtime wages, liquidated damages in an amount equal to six percent of all unpaid overtime compensation, the payment of reasonable attorney fees and legal expenses and pre-judgment and post-judgment interest, and such other damages that may be owed to the workers.
These cases are still in their early stages. As a result, we have not had the opportunity to evaluate the allegations made in the plaintiffs' complaints and intend to vigorously defend the suits.

We filed an action against TH Exploration, LLC ("TH") in Tarrant County, TX. The suit alleges breach of purchase and sale agreement providing for the our disposition of certain oil and gas properties in Ohio to TH. We are seeking specific

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performance, related to TH's obligations to close the transaction and tender the purchase price, along with any additional relief available to us.
SEC Investigation
The SEC has commenced an investigation with respect to certain actions by our former Company management, including alleged improper personal use of Companycompany assets, and potential violations by our former management and the Companycompany of the Sarbanes-Oxley Act of 2002 in connection with such actions. We have fully cooperated and intend to continue to cooperate fully with the SEC’s investigation. Although it is not possible to predict the ultimate resolution or financial liability with respect to this matter, we believe that the outcome of this matter will not have a material effect on our business, financial condition or results of operations.
Business Operations
We are involved in various lawsuits and disputes incidental to our business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions.
Environmental Contingencies
The nature of the oil and gas business carries with it certain environmental risks for usGulfport and ourits subsidiaries. WeThey have implemented various policies, programs, procedures, training and audits to reduce and mitigate such environmental risks. WeThey conduct periodic reviews, on a company-wide basis, to assess changes in ourtheir environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. We manage our exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the extent of an identified environmental concern, wethey may, among other things, exclude a property from the transaction, require the seller to remediate the property to ourtheir satisfaction in an acquisition or agree to assume liability for the remediation of the property.
We received several Finding of Violation (“FOVs”) from the United States Environmental Protection Agency ("USEPA") alleging violations of the Clean Air Act at approximately 1217 locations in Ohio. The first FOV for one site was dated December 11, 2013.  Two subsequent FOVs incorporated and expanded the scope on January 4, 2017 and April 15, 2019.  We have exchanged information with the USEPA and are engaged in discussions aimed at resolving the allegations. Resolution of the matter may resultresulted in monetary sanctions of more than $100,000. approximately $1.7 million.
In October 2018, we submitted a Voluntary Disclosure document to the Oklahoma Department of Environmental Quality (ODEQ) stemming from improper air permitting at several sites in Midcon between 2014 and 2017. The sites were permitted by Vitruvian prior to our purchase of those assets. The sites were permitted utilizing the “permit by rule” regulation but actually required Title V air permits. We have agreed in a draft Consent Order to obtain the proper permits and to pay the
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costs from not having the proper permits in place in the amount of $180,000 to the ODEQ. The Order received final approval at the ODEQ and expects to be finalized in the third quarter of 2020.
Other Matters
Based on management’s current assessment, wethey are of the opinion that no pending or threatened lawsuit or dispute relating to ourits business operations areis likely to have a material adverse effect on ourtheir future consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.

ITEM 1A.RISK FACTORS
See risk factors previously disclosedOur business has many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our common stock or senior notes are described under "Risk Factors" in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2018.2019. The risk factors below updates our risk factors previously discussed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2019.
Any significant reduction in our borrowing base under our revolving credit facility as a result of periodic borrowing base redeterminations or otherwise or an inability to refinance our revolving credit facility prior to its maturity may negatively impact our ability to fund our operations, and we may not have sufficient funds to repay borrowings under our revolving credit facility if required as a result of a borrowing base redetermination.
In 2020, decreased demand for oil and natural gas as a result of the COVID-19 pandemic and the accompanying decrease in commodity prices has significantly reduced our ability to access capital markets and to refinance our existing indebtedness. Further, these conditions have made amendments or waivers to our revolving credit facility more difficult to obtain and available on terms less favorable to us. If depressed commodity prices persist or decline further, the borrowing base under our revolving credit facility could be further reduced at our next scheduled redetermination date in November 2020. Any such reduction would constrain our liquidity and may impair our ability to fund our planned capital expenditures and meet our obligations under our existing indebtedness. Further, a reduction in our capital expenditures would decrease our production, revenues, operating cash flow and EBITDA, which could limit our ability to comply with the restrictive covenants in our revolving credit facility and other existing indebtedness. Finally, our existing revolving credit facility matures in December 2021 and therefore will become a current liability at year end 2020 unless we are able to refinance the credit facility with a new credit facility or other financing. Considering the current state of the first lien market and our elevated leverage profile, there is substantial risk that a refinancing will not be available to us on reasonable terms. A current liability under the revolving credit facility at year end 2020 may result in a qualified audit opinion which could result in a default under the terms of the current revolving credit facility. As a result of these uncertainties, management has concluded that there is substantial doubt about our ability to continue as a going concern. Failure to meet our obligations under our existing indebtedness or failure to comply with any of our covenants, if not waived, would result in an event of default under such indebtedness and result in the potential acceleration of outstanding indebtedness thereunder and, with respect to the revolving credit facility, the potential foreclosure on the collateral securing such debt, and could cause a cross-default under our other outstanding indebtedness. Further, if the outstanding borrowings under our revolving credit facility were to exceed the borrowing base as a result of any such redetermination, we would be required to repay the excess. We may not have sufficient funds to make such repayments. If we do not have sufficient funds and we are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

The outbreak of the novel coronavirus, or COVID-19, has affected and may materially adversely affect, and any future outbreak of any other highly infectious or contagious diseases may materially adversely affect, our operations, financial performance and condition, operating results and cash flows.
The recent outbreak of COVID-19 has affected, and may materially adversely affect, our business and financial and operating results. The severity, magnitude and duration of the current COVID-19 outbreak is uncertain, rapidly changing and hard to predict. Thus far in 2020, the outbreak has significantly impacted economic activity and markets around the world, and COVID-19 or another similar outbreak could negatively impact our business in numerous ways, including, but not limited to, the following:
•our revenue may be reduced if the outbreak results in an economic downturn or recession, as many experts predict, to the extent it leads to a prolonged decrease in the demand for natural gas and, to a lesser extent, NGL and oil;
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•our operations may be disrupted or impaired, thus lowering our production level, if a significant portion of our employees or contractors are unable to work due to illness or if our field operations are suspended or temporarily shut-down or restricted due to control measures designed to contain the outbreak;
•the operations of our midstream service providers, on whom we rely for the transmission, gathering and processing of a significant portion of our produced natural gas, oil and NGL, may be disrupted or suspended in response to containing the outbreak, and/or the difficult economic environment may lead to the bankruptcy or closing of the facilities and infrastructure of our midstream service providers, which may result in substantial discounts in the prices we receive for our produced natural gas, oil and NGL or result in the shut-in of producing wells or the delay or discontinuance of development plans for our properties; and
•the disruption and instability in the financial markets and the uncertainty in the general business environment may affect our ability to execute on our business strategy, including our focus on reducing our leverage profile. If we are not able to successfully execute our plan to reduce our leverage profile, our high level of indebtedness could make it more difficult for us to satisfy our obligations with respect to our indebtedness, and any failure to comply with the obligations under any of our debt instruments, including their restrictive covenants, could result in a default under our revolving credit facility or the indentures governing our senior notes. Additionally, our credit ratings may be lowered, we may reduce or delay our planned capital expenditures or investments, and we may revise or delay our strategic plans.
We expect that the principal areas of operational risk for us are availability of service providers and supply chain disruption. Active development operations, including drilling and fracking operations, represent the greatest risk for transmission given the number of personnel and contractors on site. While we believe that we are following best practices under COVID-19 guidance, the potential for transmission still exists. In certain instances, it may be necessary or determined advisable for us to delay development operations.
In addition, the COVID-19 pandemic has increased volatility and caused negative pressure in the capital and credit markets. As a result, we may experience difficulty accessing the capital or financing needed to fund our exploration and production operations, which have substantial capital requirements, or refinance our upcoming maturities on satisfactory terms or at all. We typically fund our capital expenditures with existing cash and cash generated by operations (which is subject to a number of variables, including many beyond our control) and, to the extent our capital expenditures exceed our cash resources, from borrowings under our revolving credit facility and other external sources of capital. If our cash flows from operations or the borrowing capacity under our revolving credit facility are insufficient to fund our capital expenditures and we are unable to obtain the capital necessary for our planned capital budget or our operations, we could be required to curtail our operations and the development of our properties, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, results of operations and financial position.
To the extent the COVID-19 pandemic adversely affects our business and financial results, it may also have the effect of heightening many of the other risks set forth in Item 1A., “Risk Factors” in our Annual Report on Form 10-K, such as those relating to our financial performance and debt obligations. The rapid development and fluidity of this situation precludes any prediction as to the ultimate adverse impact of COVID-19 on our business, which will depend on numerous evolving factors and future developments that we are not able to predict, including the length of time that the pandemic continues, its effect on the demand for natural gas, NGL and oil, the response of the overall economy and the financial markets as well as the effect of governmental actions taken in response to the pandemic.

We expect that we will be unable to meet our firm commitment delivery obligations under our firm transportation contracts relating to our Utica Shale or SCOOP acreage due to decreased developmental activities, which will result in fees and may have a material adverse effect on our operations.
As of June 30, 2020, we had entered into firm transportation contracts to deliver approximately 1,455,000 MMBtu per day for the remainder of 2020 and 2021, respectively. Under these firm transportation contracts, we are obligated to deliver minimum daily volumes or pay fees for any deficiencies in deliveries. As a result of the reduced production from our Utica Shale or SCOOP acreage due to decreased developmental activities, taking into consideration the current low commodity price environment, we expect that we will be unable to meet our obligations under the existing firm transportation contracts, resulting in fees, which may be significant and may have a material adverse effect on our operations.

ITEM 2.UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
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Unregistered Sales of Equity Securities
None.
Issuer Repurchases of Equity Securities
Our common stock repurchase activity for the three months ended SeptemberJune 30, 20192020 was as follows:

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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 (1) Approximate maximum dollar value of shares that may yet be purchased under the plans or programs (2)
July 2019 —
 $—
 —
 $370,000,000
August 2019 35,977
 $2.45
 —
 $370,000,000
September 2019 —
 $—
 —
 $370,000,000
Total 35,977
 $2.45
 —
  
PeriodTotal number of shares purchased (1)Average price paid per shareTotal number of shares purchased as part of publicly announced plans or programsApproximate maximum dollar value of shares that may yet be purchased under the plans or programs (2)
April 202018,338  $0.72  —  $370,000,000  
May 2020—  $—  —  $370,000,000  
June 20208,956  $1.69  —  $370,000,000  
Total27,294  $1.04  —  
(1)In August 2019,During the three months ended June 30, 2020, we repurchased and canceled 35,97727,294 shares of our common stock at a weighted average price of $2.45$1.04 to satisfy tax withholding requirements incurred upon the vesting of restricted stock unit awards. No repurchases were made under our repurchase program during the three months ended September 30, 2019.
(2)In January 2019, our board of directors approved a new stock repurchase program to acquire up to $400$400.0 million of our outstanding common stock within a 24 month period. This repurchaseThe program may bewas suspended from timein the fourth quarter of 2019, and the May 1, 2020 amendment to time, modified, extended or discontinued by our board of directors at any time.revolving credit facility prohibits further repurchases.
ITEM 3.DEFAULTS UPON SENIOR SECURITIES
Not applicable.
ITEM 4.MINE SAFETY DISCLOSURES
Not applicable.
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ITEM 5.OTHER INFORMATION
None.
Incentive compensation program

In connection with a comprehensive review of the Company’s compensation programs and in consultation with its independent compensation consultant and legal advisors, the Board of Directors has determined that significant changes are appropriate to retain and motivate the Company’s employees as a result of the ongoing uncertainty and unprecedented disruption in the oil and gas industry. Accordingly, as of August 4, 2020, the Board has authorized a redesign of the incentive compensation program for the Company’s workforce, including for its current named executive officers: David M. Wood, Donnie Moore, Quentin R. Hicks, Patrick K. Craine and Michael Sluiter (the “executives”). Participation by the executives in the new compensation program is contingent upon forfeiture of (i) all unpaid amounts previously awarded pursuant to the 2020 Incentive Plan, (ii) all restricted stock units granted in 2020 and (iii) any award pursuant to the 2019 Executive Annual Incentive Compensation Program for 2020, other than payment of pro-rata bonuses earned for the period from January 1, 2020 through July 31, 2020 at the target level. Under the new compensation program, each executive’s target total variable compensation amount for 2020 (target annual bonus and long-term incentive, after adjusting the long-term incentive targets for each of Messrs. Hicks and Craine to 350% in recognition of increased workload), less any amounts previously paid pursuant to the 2020 Incentive Plan, will be paid as soon as practicable. Of this variable compensation amount, 50% will be subject to repayment on an after-tax basis in the event of the executive’s resignation without good reason or termination by the Company for cause prior to the earlier of July 31, 2021, a change in control or completion of a restructuring, and the remaining 50% will be subject to repayment on an after-tax basis if performance metrics established by the Board are not met over performance periods from August 1, 2020 through July 31, 2021.
Restricted stock dispositions to satisfy tax withholding obligations for Named Executive Officers
All shares noted below represent vested restricted stock units previously granted under Gulfport's equity incentive plan and were withheld by Gulfport to satisfy tax withholding obligations due upon settlement of the restricted stock units.
On February 26, 2020, the following named executive officers disposed of shares to satisfy tax withholding obligations:
ITEM 6.EXHIBITS
Exhibit
Number
Named Executive Officer		DescriptionRestricted Stock Units
David M. Wood43,557
3.1Michael Sluiter
Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006).17,060
3.2
Certificate of Amendment No. 1 to Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.2 to Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 6, 2009).
3.3
Certificate of Amendment No. 2 to Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 23, 2013).
3.4
Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 12, 2006).
3.5
First Amendment to the Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 23, 2013).
3.6
Second Amendment to the Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company on May 2, 2014).
4.1
Form of Common Stock certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the Company with the SEC on July 22, 2004).
4.5
Indenture, dated as of April 21, 2015, among the Company, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of the Company’s 6.625% Senior Notes due 2023) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 21, 2015).

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shares to satisfy tax withholding obligations:
Named Executive OfficerRestricted Stock Units
4.6Donnie Moore
Indenture, dated as of October 14, 2016, among Gulfport Energy Corporation, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of Gulfport Energy Corporation’s 6.000% Senior Notes due 2024) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File. No. 000-19514, filed by the Company with the SEC on October 19, 2016).19,498
4.7
Indenture, dated as of December 21, 2016, among Gulfport Energy Corporation, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of Gulfport Energy Corporation’s 6.375% Senior Notes due 2025) (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 21, 2016).
4.8
Indenture, dated as of October 11, 2017, among Gulfport Energy Corporation, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of Gulfport Energy Corporation’s 6.375% Senior Notes due 2026) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 11, 2017).
4.9
Registration Rights Agreement, dated as of February 17, 2017, by and between Gulfport Energy Corporation and Vitruvian II Woodford, LLC (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K, File No. 000-19514, filed by the Company with the SEC on February 24, 2017).
10.1+
Employment Agreement, effective as of August 26, 2019, by and between Gulfport Energy Corporation and Quentin Hicks (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on August 12, 2019).
10.2+
Separation and Release Agreement, effective August 9, 2019, by and between Gulfport Energy Corporation and Keri Crowell (incorporated by reference to Exhibit 10.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on August 12, 2019).
10.3+
2019 Amended and Restated Stock Incentive Plan Form of Performance Share Award Agreement (incorporated by reference to Exhibit 10.3 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on August 12, 2019).
31.1*
Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
31.2*
Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
32.1*
Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
32.2*
Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
101.INS*XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH*XBRL Taxonomy Extension Schema Document.
101.CAL*XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE*XBRL Taxonomy Extension Presentation Linkbase Document.
104*Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

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*Filed herewith.
+ITEM 6.
EXHIBITS
INDEX OF EXHIBITS
Incorporated by Reference
Exhibit NumberDescriptionFormSEC File NumberExhibitFiling DateFiled or Furnished Herewith
3.18-K000-195143.14/26/2006
3.210-Q000-195143.211/6/2009
3.38-K000-195143.17/23/2013
3.48-K000-195143.12/27/2020
3.58-K001-195143.15/29/2020
3.68-A001-195143.14/30/2020
4.1SB-2333-1153964.17/22/2004
4.28-K000-195144.14/21/2015
4.38-K000-195144.110/19/2016
4.48-K000-195144.112/21/2016
4.58-K000-195144.110/11/2017
4.68-A001-195144.14/30/2020
10.1+8-K000-1951410.13/17/2020
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10.2+8-K000-1951410.23/17/2020
10.3X
10.48-K001-1951410.17/30/2020
31.1X
31.2X
32.1X
32.2X
101.INSXBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.X
101.SCHXBRL Taxonomy Extension Schema Document.X
101.CALXBRL Taxonomy Extension Calculation Linkbase Document.X
101.DEFXBRL Taxonomy Extension Definition Linkbase Document.X
101.LABXBRL Taxonomy Extension Labels Linkbase Document.X
101.PREXBRL Taxonomy Extension Presentation Linkbase Document.X
104Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.X

+Management contract, compensation plan or arrangement.


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SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: November 1, 2019August 6, 2020
 
GULFPORT ENERGY CORPORATION
GULFPORT ENERGY CORPORATION
By:
By:/s/    Quentin Hicks
Quentin Hicks

Executive Vice President & Chief Financial Officer


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