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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q
(Mark One)
ý☒QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2017 OR
¨
For the quarterly period ended June 30, 2020
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 Corporation
(Exact Name of Registrant As Specified in Its Charter)
Delaware
73-1521290
Delaware
73-1521290
(State or Other Jurisdiction of
Incorporation or Organization)
(IRS Employer
Identification Number)
3001 Quail Springs Parkway
Oklahoma City, Oklahoma
73134
Oklahoma City,Oklahoma73134
(Address of Principal Executive Offices)(Zip Code)
(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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or such shorter period that the registrant was required to submit and post 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 filer  ý¨     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 27, 2017, 183,081,776July 31, 2020, 160,115,829 shares of the registrant’s common stock were outstanding.




Table of Contents



GULFPORT ENERGY CORPORATION
TABLE OF CONTENTS
 
Page
Page
PART I FINANCIAL INFORMATION
Item 1.
2
2
3
4
5
6
7
Item 2.
37
Item 3.
5459
Item 4.
5661
Item 1.
62
Item 1.1A.
5864
Item 1A.2.
58
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
5865
Item 3.
5966
Item 4.
5966
Item 5.
5967
Item 6.
5968
6170



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, 2017 December 31, 2016
 (In thousands, except share data)
Assets   
Current assets:   
Cash and cash equivalents$125,271
 $1,275,875
Restricted cash—
 185,000
Accounts receivable—oil and natural gas180,106
 136,761
Accounts receivable—related parties362
 16
Prepaid expenses and other current assets5,666
 3,135
Short-term derivative instruments35,332
 3,488
Total current assets346,737
 1,604,275
Property and equipment:   
Oil and natural gas properties, full-cost accounting, $2,956,732 and $1,580,305 excluded from amortization in 2017 and 2016, respectively8,867,239
 6,071,920
Other property and equipment84,225
 68,986
Accumulated depletion, depreciation, amortization and impairment(4,043,879) (3,789,780)
Property and equipment, net4,907,585
 2,351,126
Other assets:   
Equity investments279,282
 243,920
Long-term derivative instruments6,409
 5,696
Deferred tax asset4,692
 4,692
Inventories13,908
 4,504
Other assets18,985
 8,932
Total other assets323,276
 267,744
Total assets$5,577,598
 $4,223,145
Liabilities and Stockholders’ Equity   
Current liabilities:   
Accounts payable and accrued liabilities$582,928
 $265,124
Asset retirement obligation—current195
 195
Short-term derivative instruments29,130
 119,219
Current maturities of long-term debt570
 276
Total current liabilities612,823
 384,814
Long-term derivative instrument19,712
 26,759
Asset retirement obligation—long-term44,266
 34,081
Long-term debt, net of current maturities1,958,136
 1,593,599
Total liabilities2,634,937
 2,039,253
Commitments and contingencies (Note 9)
 
Preferred stock, $.01 par value; 5,000,000 authorized, 30,000 authorized as redeemable 12% cumulative preferred stock, Series A; 0 issued and outstanding—
 —
Stockholders’ equity:   
Common stock - $.01 par value, 200,000,000 authorized, 183,081,776 issued and outstanding at September 30, 2017 and 158,829,816 at December 31, 20161,831
 1,588
Paid-in capital4,413,623
 3,946,442
Accumulated other comprehensive loss(40,339) (53,058)
Retained deficit(1,432,454) (1,711,080)
Total stockholders’ equity2,942,661
 2,183,892
Total liabilities and stockholders’ equity$5,577,598
 $4,223,145


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,
 2017 2016 2017 2016
 (In thousands, except share data)
Revenues:       
Natural gas sales$223,340
 $122,018
 $606,544
 $271,873
Oil and condensate sales31,459
 21,799
 85,338
 60,799
Natural gas liquid sales33,559
 14,594
 88,985
 34,198
Net (loss) gain on natural gas, oil, and NGL derivatives(22,860) 35,281
 141,588
 (44,376)
 265,498
 193,692
 922,455
 322,494
Costs and expenses:
      
Lease operating expenses20,020
 17,471
 60,044
 48,789
Production taxes5,419
 3,525
 14,464
 9,492
Midstream gathering and processing69,372
 45,475
 176,258
 122,476
Depreciation, depletion and amortization106,650
 62,285
 254,887
 183,414
Impairment of oil and natural gas properties—
 212,194
 —
 601,806
General and administrative13,065
 10,467
 37,922
 32,941
Accretion expense456
 269
 1,148
 777
Acquisition expense33
 —
 2,391
 —
 215,015
 351,686
 547,114
 999,695
INCOME (LOSS) FROM OPERATIONS50,483
 (157,994) 375,341
 (677,201)
OTHER (INCOME) EXPENSE:
      
Interest expense27,130
 12,787
 74,797
 44,892
Interest income(37) (337) (927) (822)
Insurance proceeds—
 (3,750) —
 (3,750)
Loss (income) from equity method investments, net2,737
 (5,997) 20,945
 25,576
Other income(345) 6
 (863) (3)
 29,485
 2,709
 93,952
 65,893
INCOME (LOSS) BEFORE INCOME TAXES20,998
 (160,703) 281,389
 (743,094)
INCOME TAX EXPENSE (BENEFIT)2,763
 (3,407) 2,763
 (3,755)
NET INCOME (LOSS)$18,235
 $(157,296) $278,626
 $(739,339)
NET INCOME (LOSS) PER COMMON SHARE:       
Basic$0.10
 $(1.25) $1.56
 $(6.12)
Diluted$0.10
 $(1.25) $1.56
 $(6.12)
Weighted average common shares outstanding—Basic182,957,416
 125,408,866
 178,736,569
 120,771,046
Weighted average common shares outstanding—Diluted183,008,436
 125,408,866
 179,130,570
 120,771,046


See accompanying notes to consolidated financial statements.



3
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GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME (LOSS)
(Unaudited)
 Three months ended September 30, Nine months ended September 30,
 2017 2016 2017 2016
 (In thousands)
Net income (loss)$18,235
 $(157,296) $278,626
 $(739,339)
Foreign currency translation adjustment (1)6,832
 (4,013) 12,719
 4,361
Other comprehensive income (loss)6,832
 (4,013) 12,719
 4,361
Comprehensive income (loss)$25,067
 $(161,309) $291,345
 $(734,978)
 Three months ended June 30,Six months ended June 30,
2020201920202019
(In thousands)
Net (loss) income$(561,068) $234,956  $(1,078,606) $297,198  
Foreign currency translation adjustment6,872  3,610  (8,158) 7,411  
Other comprehensive income (loss)6,872  3,610  (8,158) 7,411  
Comprehensive (loss) income$(554,196) $238,566  $(1,086,764) $304,609  


(1) Net of $2.8 million in taxes for each of the three and nine months ended September 30, 2016.



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 Income (loss)
 
Retained
Deficit
 
Total
Stockholders’
Equity
 Common Stock    
 Shares Amount    
 (In thousands, except share data)
Balance at January 1, 2017158,829,816
 $1,588
 $3,946,442
 $(53,058) $(1,711,080) $2,183,892
Net income—
 —
 —
 —
 278,626
 278,626
Other Comprehensive Income
 
 
 12,719
 —
 12,719
Stock Compensation—
 —
 7,988
 —
 —
 7,988
Issuance of Common Stock for the Vitruvian Acquisition, net of related expenses23,852,117
 239
 459,197
 —
 —
 459,436
Issuance of Restricted Stock399,843
 4
 (4) —
 —
 —
Balance at September 30, 2017183,081,776
 $1,831
 $4,413,623
 $(40,339) $(1,432,454) $2,942,661
            
Balance at January 1, 2016108,322,250
 $1,082
 $2,824,303
 $(55,177) $(731,371) $2,038,837
Net loss—
 —
 —
 —
 (739,339) (739,339)
Other Comprehensive Income—
 —
 —
 4,361
 —
 4,361
Stock Compensation—
 —
 9,550
 —
 —
 9,550
Issuance of Common Stock in public offerings, net of related expenses16,905,000
 169
 411,542
 —
 —
 411,711
Issuance of Restricted Stock226,283
 2
 (2) —
 —
 —
Balance at September 30, 2016125,453,533
 $1,253
 $3,245,393
 $(50,816) $(1,470,710) $1,725,120

Paid-in
Capital		Accumulated
Other
Comprehensive (Loss) Income		Accumulated
Deficit		Total
Stockholders’
Equity
Common Stock
 SharesAmount
(In thousands)
Balance at January 1, 2019162,986  $1,630  $4,227,532  $(56,026) $(845,368) $3,327,768  
Net Income—  —  —  —  62,242  62,242  
Other Comprehensive Income—  —  —  3,801  —  3,801  
Stock Compensation—  —  2,785  —  —  2,785  
Shares Repurchased(3,619) (37) (28,293) —  —  (28,330) 
Issuance of Restricted Stock55  1  (1) —  —  —  
Balance at March 31, 2019159,422  $1,594  $4,202,023  $(52,225) $(783,126) $3,368,266  
Net Income—  —  —  —  234,956  234,956  
Other Comprehensive Income—  —  —  3,610  —  3,610  
Stock Compensation—  —  2,846  —  —  2,846  
Shares Repurchased(297) (3) (2,267) —  —  (2,270) 
Issuance of Restricted Stock271  3  (3) —  —  —  
Balance at June 30, 2019159,396  $1,594  $4,202,599  $(48,615) $(548,170) $3,607,408  


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,
 2017 2016
 (In thousands)
Cash flows from operating activities:   
Net income (loss)$278,626
 $(739,339)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:   
Accretion of discount—Asset Retirement Obligation1,148
 777
Depletion, depreciation and amortization254,887
 183,414
Impairment of oil and natural gas properties—
 601,806
Stock-based compensation expense4,793
 5,730
Loss from equity investments21,495
 25,988
Change in fair value of derivative instruments(129,692) 184,013
Deferred income tax expense (benefit)—
 17,211
Amortization of loan commitment fees3,548
 2,912
Amortization of note discount and premium—
 (1,716)
Changes in operating assets and liabilities:   
Increase in accounts receivable(43,345) (55,916)
Increase in accounts receivable—related party(346) (80)
Increase in prepaid expenses(2,531) (6,835)
Increase in other assets(5,665) —
Increase in accounts payable, accrued liabilities and other111,335
 28,265
Settlement of asset retirement obligation(2,520) (955)
Net cash provided by operating activities491,733
 245,275
Cash flows from investing activities:   
Deductions to cash held in escrow—
 8
Additions to other property and equipment(16,288) (20,131)
Acquisition of oil and natural gas properties(1,339,456) —
Additions to oil and natural gas properties(789,743) (441,128)
Proceeds from sale of oil and natural gas properties4,079
 41,534
Proceeds from sale of other property and equipment658
 —
Funding of restricted cash185,000
 —
Contributions to equity method investments(44,844) (18,510)
Distributions from equity method investments4,114
 14,220
Insurance proceeds—
 3,750
Net cash used in investing activities(1,996,480) (420,257)
Cash flows from financing activities:   
Principal payments on borrowings(183) (1,685)
Borrowings on line of credit365,000
 —
Borrowings on term loan2,951
 16,499
Debt issuance costs and loan commitment fees(8,261) (241)
Proceeds from issuance of common stock, net of offering costs(5,364) 411,711
Net cash provided by financing activities354,143
 426,284
Net (decrease) increase in cash and cash equivalents(1,150,604) 251,302
Cash and cash equivalents at beginning of period1,275,875
 112,974
Cash and cash equivalents at end of period$125,271
 $364,276
Supplemental disclosure of cash flow information:   
Interest payments$50,826
 $35,193
Income tax payments$—
 $—
Supplemental disclosure of non-cash transactions:   
Capitalized stock based compensation$3,195
 $3,820
Asset retirement obligation capitalized$11,557
 $6,726
Interest capitalized$8,753
 $8,920
Foreign currency translation gain on equity method investments$12,719
 $7,137
 Six months ended June 30,
20202019
(In thousands)
Cash flows from operating activities:
Net (loss) income$(1,078,606) $297,198  
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depletion, depreciation and amortization142,818  243,384  
Impairment of oil and natural gas properties1,086,225  —  
Loss (income) from equity investments10,834  121,449  
Gain on debt extinguishment(49,579) —  
Net gain on derivative instruments(125,237) (151,095) 
Net cash receipts (payments) on settled derivative instruments195,232  (1,494) 
Deferred income tax expense7,290  (179,331) 
Other, net9,844  11,341  
Changes in operating assets and liabilities:
Decrease in accounts receivable—oil and natural gas sales55,565  78,525  
Decrease (increase) in accounts receivable—joint interest and other29,159  (24,148) 
(Decrease) increase in accounts payable and accrued liabilities(30,620) 3,220  
Other, net(5,703) 720  
Net cash provided by operating activities247,222  399,769  
Cash flows from investing activities:
Additions to oil and natural gas properties(274,851) (508,315) 
Proceeds from sale of oil and natural gas properties45,185  745  
Additions to other property and equipment(575) (4,298) 
Proceeds from sale of other property and equipment151  130  
Contributions to equity method investments—  (432) 
Distributions from equity method investments—  1,945  
Net cash used in investing activities(230,090) (510,225) 
Cash flows from financing activities:
Principal payments on borrowings(323,322) (345,350) 
Borrowings on line of credit326,000  455,000  
Repurchases of senior notes(22,827) —  
Payments for repurchases of stock under approved stock repurchase program—  (30,000) 
Other, net(226) (714) 
Net cash (used in) provided by financing activities(20,375) 78,936  
Net decrease in cash, cash equivalents and restricted cash(3,243) (31,520) 
Cash, cash equivalents and restricted cash at beginning of period6,060  52,297  
Cash, cash equivalents and restricted cash at end of period$2,817  $20,777  
Supplemental disclosure of cash flow information:
Interest payments$60,523  $67,472  
Income tax receipts$—  $(1,794) 
Supplemental disclosure of non-cash transactions:
Capitalized stock-based compensation$1,891  $2,252  
Asset retirement obligation capitalized$1,553  $6,230  
Asset retirement obligation removed due to divestiture$(2,033) $—  
Interest capitalized$710  $1,771  
Fair value of contingent consideration asset on date of divestiture$23,090  $—  
Foreign currency translation (loss) gain on equity method investments$(8,158) $7,411  
 See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
These
1.BASIS OF PRESENTATION, SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND LIQUIDITY, MANAGEMENT'S PLANS AND GOING CONCERN
Basis of Presentation
The 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 which,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 thereto included in the Company’s most recent annual report on Form 10-K. Results for the three and nine month periodssix months ended SeptemberJune 30, 20172020 are not necessarily indicative of the results expected for the full year.
1.ACQUISITIONS
Vitruvian AcquisitionCOVID-19
In December 2016,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 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 its wholly-owned subsidiary Gulfport MidCon LLCDecember 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 (“Gulfport MidCon”) (formerly known as SCOOP Acquisition Company, LLC), entered into an agreement to acquire certain assets of Vitruvian II Woodford, LLC (“Vitruvian”), an unrelated third-party seller (the “Vitruvian Acquisition”CARES Act”). The assets included inCARES Act did not have a material impact on the Vitruvian Acquisition include 46,400 net surface acres located in Grady, StephensCompany’s consolidated financial statements.
Liquidity, Management's Plans and Garvin Counties, Oklahoma. On February 17, 2017, the Company completed the Vitruvian AcquisitionGoing Concern
As noted above, decreased demand for oil and natural gas as a total initial purchase price of approximately $1.85 billion, consisting of $1.35 billion in cash, subject to certain adjustments, and approximately 23.9 million sharesresult of the Company’s common stock (of which approximately 5.2 million shares were placed in an indemnity escrow). The cash portion of the purchase price was funded with the net proceeds from the December 2016 common stock and senior note offerings and cash on hand. Acquisition costs of $0.03 million and $2.4 million were incurred during the three and nine months ended September 30, 2017, respectively, related to the Vitruvian Acquisition.
Allocation of Purchase Price
The Vitruvian Acquisition qualified as a business combination for accounting purposes and, as such, the Company estimated the fair value of the acquired properties as of the February 17, 2017 acquisition date. The fair value of the assets acquired and liabilities assumed was estimated using assumptions that represent Level 3 inputs. See Note 11 for additional discussion of the measurement inputs.
The Company estimated that the consideration paid in the Vitruvian Acquisition for these properties approximated the fair value that would be paid by a typical market participant. As a result, no goodwill or bargain purchase gain was recognized in conjunction with the purchase.
The following table summarizes the consideration paid in the Vitruvian Acquisition to acquire the propertiesCOVID-19 pandemic and the fair value amount ofaccompanying decrease in commodity prices has significantly impaired the assets acquired as of February 17, 2017. Both the consideration paidCompany's ability to access capital markets and the fair value assigned to the assets is preliminary and subject to adjustment.refinance its

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  (In thousands)
Consideration:  
     Cash, net of purchase price adjustments $1,354,093
     Fair value of Gulfport’s common stock issued 464,639
Total Consideration $1,818,732
   
Estimated Fair value of identifiable assets acquired and liabilities assumed:  
     Oil and natural gas properties  
       Proved properties $362,264
       Unproved properties 1,462,957
     Asset retirement obligations (6,489)
Total fair value of net identifiable assets acquired $1,818,732

The equity consideration includedexisting 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 initial purchase price was basedCompany'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 equity offering priceevent of $20.96 on December 15, 2016. The decreasedefault under such indebtedness and result in the pricepotential acceleration of Gulfport’s common stock from $20.96 on December 15, 2016 to $19.48 on February 17, 2017 resulted in a decreaseoutstanding indebtedness thereunder and, with respect to the fair valuerevolving 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 total consideration paidCompany 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 initial purchaserecent 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 approximately $35.3 million,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 resultedcontemplates the realization of assets and satisfaction of liabilities and other commitments in a closing date fair value lower than the initial purchase price.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.
Post-Acquisition Operating
Impact on Previously Reported Results
ForDuring the threethird 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 six months ended SeptemberJune 30, 2017 and2019 contained herein, the period from the acquisition date of February 17, 2017 to September 30, 2017, the assets acquired in the Vitruvian Acquisition have contributed the following amounts of revenue to the Company’s consolidated statements of operations.cash flows and the condensed consolidating statements of cash flows were adjusted to increase net cash flows provided by operating activities by $90.8 million with a corresponding increase in net cash flows used in investing activities. The amountCompany has evaluated the effect of net income contributed by the assets acquired isprevious presentation, both qualitatively and quantitatively, and concluded that it did not presented below as it is impracticable to calculate due tohave a material impact on any previously filed annual or quarterly consolidated financial statements.
Recently Adopted Accounting Standards
On January 1, 2020, the Company integratingadopted ASU No. 2016-13, Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Instruments, which replaces the acquired assets into its overall operations usingincurred loss impairment methodology with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. The measurement of expected credit losses is based on relevant information about past events, including historical experience, current conditions and reasonable and supportable forecasts that affect the full cost methodcollectibility of accounting.
the
    Period from
    February 17, 2017
  Three months ended to
  September 30, 2017 September 30, 2017
  (In thousands)
Revenue $60,940
 $137,706
Pro Forma Information (Unaudited)

The following unaudited pro forma combined financial information presents the Company’s results as though the Vitruvian Acquisition had been completed at January 1, 2016. The pro forma combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Vitruvian Acquisition taken place on January 1, 2016; furthermore, the financial information is not intended to be a projection of future results.
  Three months ended September 30, Nine months ended September 30,
  2017 2016 2017 2016
  (In thousands, except share data)
Pro forma revenue $265,498
 $250,258
 $958,354
 $425,958
Pro forma net income (loss) $18,235
 $(200,005) $300,052
 $(935,219)
Pro forma earnings (loss) per share (basic) $0.10
 $(1.34) $1.68
 $(6.47)
Pro forma earnings (loss) per share (diluted) $0.10
 $(1.34) $1.68
 $(6.47)

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reported amount. The Company adopted the new standard using the prospective transition method, and it did not have a material impact on the Company's consolidated financial statements and related disclosures.
2.PROPERTY AND EQUIPMENT

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, 20172020 and December 31, 20162019 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, 2017 December 31, 2016
 (In thousands)
Oil and natural gas properties$8,867,239
 $6,071,920
Office furniture and fixtures34,875
 21,204
Building44,530
 42,530
Land4,820
 5,252
Total property and equipment8,951,464
 6,140,906
Accumulated depletion, depreciation, amortization and impairment(4,043,879) (3,789,780)
Property and equipment, net$4,907,585
 $2,351,126


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, 2017, the calculated ceiling was greater than2020, the net book value of the Company’sCompany'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 June 30, 2020. As a result, the Company was required to record impairments of its oil and natural gas properties thus no ceiling test impairment was requiredof $532.9 million and $1.1 billion for the ninethree and six months ended SeptemberJune 30, 2017. An impairment of$212.2 million and $601.8 millionwas2020, respectively. NaN impairments 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, 2016, respectively.
Includedand the short-term pricing outlook for the third quarter of 2020, the Company expects to recognize additional full cost impairments in oilthe third quarter of 2020. The amount of any future impairments is difficult to predict as it depends on future commodity prices, production rates, proved reserves, evaluation of costs excluded from amortization, future development costs and natural gas properties at September 30, 2017 is the cumulative capitalization of $155.5 million in general and administrative costs incurred and capitalizedproduction costs. 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 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 the 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 $8.9$8.2 million and $25.6$13.6 million for the three and ninesix months ended SeptemberJune 30, 2017,2020, respectively, and $7.2$8.8 million and $22.2$16.5 million for the three and ninesix months ended SeptemberJune 30, 2016,2019, 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 $0.73 and $1.00 per Mcfe for the six months ended June 30, 2020 and 2019, respectively.
The following table summarizes the Company’s non-producingunevaluated properties excluded from amortization by area at SeptemberJune 30, 2017:2020:
June 30, 2020
(In thousands)
Utica$874,886 
MidContinent687,169 
Other2,134 
$1,564,189 
9
 September 30, 2017
 (In thousands)
Utica$1,517,555
MidContinent1,435,992
Niobrara2,182
Southern Louisiana536
Bakken99
Other368
 $2,956,732
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At December 31, 2016,2019, approximately $1.6$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 have five-year extension terms which could extend this time frame beyond five years.evaluated properties over a timeframe consistent with their expected development schedule.

Asset Retirement Obligation
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A reconciliation of the Company’s asset retirement obligation for the ninesix months ended SeptemberJune 30, 20172020 and 20162019 is as follows:
June 30, 2020June 30, 2019
(In thousands)
Asset retirement obligation, beginning of period$60,355  $79,952  
Liabilities incurred1,553  5,153  
Liabilities settled—  (117) 
Liabilities removed due to divestitures(2,033) —  
Accretion expense1,496  2,426  
Revisions in estimated cash flows—  1,077  
Asset retirement obligation as of end of period61,371  88,491  

3.DIVESTITURES
 September 30, 2017 September 30, 2016
 (In thousands)
Asset retirement obligation, beginning of period$34,276
 $26,437
Liabilities incurred11,557
 6,726
Liabilities settled(2,520) (955)
Accretion expense1,148
 777
Asset retirement obligation as of end of period44,461
 32,985
Less current portion195
 75
Asset retirement obligation, long-term$44,266
 $32,910
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.
3.EQUITY INVESTMENTS

4.EQUITY INVESTMENTS
Investments accounted for by the equity method consist of the following as of SeptemberJune 30, 20172020 and December 31, 2016:2019:
   Carrying value 
(Income) loss from equity method investments

 Approximate ownership % September 30, 2017 December 31, 2016 Three months ended September 30, Nine months ended September 30,
    2017 2016 2017 2016
   (In thousands)
Investment in Tatex Thailand II, LLC23.5% $—
 $—
 $(95) $(253) $(549) $(412)
Investment in Tatex Thailand III, LLC17.9% —
 —
 —
 —
 —
 —
Investment in Grizzly Oil Sands ULC24.9999% 58,674
 45,213
 296
 363
 869
 24,811
Investment in Timber Wolf Terminals LLC50.0% 983
 991
 4
 3
 8
 7
Investment in Windsor Midstream LLC22.5% 31
 25,749
 (2) (9,014) 25,232
 (12,062)
Investment in Stingray Cementing LLC(1)
—% —
 1,920
 —
 79
 205
 187
Investment in Blackhawk Midstream LLC48.5% —
 —
 —
 —
 —
 —
Investment in Stingray Energy Services LLC(1)
—% —
 4,215
 —
 294
 282
 935
Investment in Sturgeon Acquisitions LLC(1)
—% —
 20,526
 —
 112
 (71) 623
Investment in Mammoth Energy Services, Inc.(1)
25.1% 149,219
 111,717
 2,407
 2,518
 (7,616) 11,527
Investment in Strike Force Midstream LLC25.0% 70,375
 33,589
 127
 (99) 2,585
 (40)
   $279,282

$243,920

$2,737
 $(5,997) $20,945
 $25,576
(1)
On June 5, 2017, Mammoth Energy Services, Inc. acquired Stingray Cementing LLC, Stingray Energy Services LLC and Sturgeon Acquisitions LLC. See below under Mammoth Energy Partners LP/Mammoth Energy Services, Inc. for information regarding these transactions.
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, 20172020 and December 31, 2016.2019.

Summarized balance sheet information:
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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 balance sheet information:
 September 30, 2017 December 31, 2016
  
 (In thousands)
Current assets$201,557
 $148,733
Noncurrent assets$1,494,770
 $1,305,407
Current liabilities$130,178
 $57,173
Noncurrent liabilities$164,759
 $67,680
Summarized results of operations: 
Three months ended September 30, Nine months ended September 30, Three months ended June 30,Six months ended June 30,
2017 2016 2017 2016 2020201920202019
(In thousands)(In thousands)
Gross revenue$160,950
 $76,627
 $357,901
 $206,666
Gross revenue$60,109  $179,114  $157,492  $443,958  
Net income (loss)$2,101
 $35,212
 $(109,651) $9,344
Net (loss) incomeNet (loss) income$(14,922) $(4,072) $(99,953) $20,684  
Tatex Thailand II, LLC
The Company has an indirect ownership interest in Tatex Thailand II, LLC (“Tatex II”). Tatex II holds an 8.5% interest in APICO, LLC (“APICO”), an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately 180,000 acres which includes the Phu Horm Field. The Company received $0.5 million and $0.4 million in distributions from Tatex II during the nine months ended September 30, 2017 and 2016, respectively.
Tatex Thailand III, LLC
The Company has an ownership interest in Tatex Thailand III, LLC (“Tatex III”). Tatex III previously owned a concession covering approximately 245,000 acres in Southeast Asia. As of December 31, 2014, the Company reviewed its investment in Tatex III and, together with Tatex III, made the decision to allow the concession to expire in January 2015. As such, the Company fully impaired the asset as of December 31, 2014.
Grizzly Oil Sands ULC
The Company, through its wholly owned subsidiary Grizzly Holdings Inc. (“Grizzly Holdings”), owns an approximate 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, 2017,2020, Grizzly had approximately 830,000 acres under lease in the Athabasca, and Peace River and Cold Lake oil sands regions of Alberta, Canada. Initiation of steam injection at its first project, Algar Lake Phase 1, commenced in January 2014 and first bitumen production was achieved during the second quarter of 2014. In April 2015, Grizzly determined to cease bitumen production at its Algar Lake facility due to the level of commodity prices. Grizzly continues to monitor market conditions as it assesses future plans for the facility. The Company reviewed its investment in Grizzly at March 31, 2016 for impairment based on FASB ASC 323 due to certain qualitative factorsat June 30, 2020 and as such, engaged an independent third party to assist management in determining fair value calculations of its investment. As a result of the calculated fair values2019 and other qualitative factors, the Company concluded that an other than temporarydetermined 0 impairment was required under FASB ASC 323, resulting in an impairment loss of $23.1 million for the three months ended March 31, 2016, which is included in loss from equity method investments, net in the consolidated statements of operations. As of and during the nine months ended September 30, 2017, commodity prices had increased as compared to the quarter ended March 31, 2016, and there were no impairment indicators that required further evaluation for impairment. If commodity prices decline in the future however, further impairment of the investment in Grizzly may be necessary. During the nine months ended September 30, 2017, Gulfportrequired. The Company paid $1.8$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 was increased by $6.7 million and $12.5$6.9 million as a result of a foreign currency translation gain for the three and nine months ended September 30, 2017, respectively. The Company's investment in Grizzly was decreased by $1.4$7.8 million as a result of a foreign currency translation loss for the three and six months ended June 30, 2020, respectively. The Company's investment in Grizzly was increased by $8.3$3.5 million and $7.3 million for the three and six months ended June 30, 2019, respectively, as a result of a foreign currency translation gain forgain.
Mammoth Energy Services, Inc.
At June 30, 2020, the threeCompany owned 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 Mammoth Energy at June 30, 2020 was $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 zero 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, ninetherefore, 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 SeptemberJune 30, 2016, respectively.

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Timber Wolf Terminals LLC
During 2012,$2.5 million during the Company investedsix months ended June 30, 2019 as a result of $0.125 per share dividends in Timber Wolf Terminals LLC (“Timber Wolf”). Timber Wolf was formed to operate a crude/condensate terminalFebruary 2019 and a sand transloading facilityMay 2019. The loss (income) from equity method investments presented in Ohio.the table above reflects any intercompany profit eliminations.
Windsor Midstream LLC
At SeptemberJune 30, 2017,2020, the Company held a 22.5% interest in Windsor Midstream LLC (“Midstream”), an entity controlled and managed by an unrelated third party. Midstream previously owned a 28.4% interest in Coronado Midstream LLC (“Coronado”), a gas processing plant in West Texas. In March 2015, Coronado was sold to EnLink Midstream Partners, LP (“EnLink”). As a result of the sale of Coronado to EnLink, Midstream received common units of EnLink, which were subsequently sold by Midstream. During the nine months ended September 30, 2017, the Company noted that Midstream had not recorded certain activity and fair value treatment of Midstream's investment in EnLink common units in a timely manner. The corresponding effect of this treatment was immaterial to the Company's previously issued financial statements and the recording of the correction in the current periods' financial statements was not material to the Company's estimated net income for the current full fiscal year. For the nine months ended September 30, 2017, approximately $23.4 million of the loss from equity method investments, net was related to the out-of-period activity associated with the accounting for Midstream's investment in EnLink common units. The Company received $0.5 million and $14.2 million in0 distributions from Midstream during the ninesix months ended SeptemberJune 30, 2017 and 2016, respectively.
Stingray Cementing LLC
During 2012, the Company invested in Stingray Cementing LLC (“Stingray Cementing”). Stingray Cementing provides well cementing services. The (income) loss from equity method investments presented in the table above reflects any intercompany profit eliminations. On June 5, 2017, Mammoth Energy Services, Inc. (“Mammoth Energy”) acquired Stingray Cementing. See below under Mammoth Energy Partners LP/Mammoth Energy Services, Inc. for information regarding this transaction.
Blackhawk Midstream LLC
During 2012, the Company invested in Blackhawk Midstream LLC (“Blackhawk”). Blackhawk coordinated gathering, compression, processing and marketing activities for the Company in connection with the development of its Utica Shale acreage. Blackhawk does not have any current activities.
Stingray Energy Services LLC
During 2013, the Company invested in Stingray Energy Services LLC (“Stingray Energy”). Stingray Energy provides rental tools for land-based oil and natural gas drilling, completion and workover activities as well as the transfer of fresh water to wellsites. The (income) loss from equity method investments presented in the table above reflects any intercompany profit eliminations. On June 5, 2017, Mammoth Energy acquired Stingray Energy. See below under Mammoth Energy Partners LP/Mammoth Energy Services, Inc. for information regarding this transaction.
Sturgeon Acquisitions LLC
During 2014, the Company invested $20.7 million and received an ownership interest of 25% in Sturgeon Acquisitions LLC (“Sturgeon”). Sturgeon owns and operates sand mines that produce hydraulic fracturing grade sand. On June 5, 2017, Mammoth Energy acquired Sturgeon. See below under Mammoth Energy Partners LP/Mammoth Energy Services, Inc. for information regarding this transaction.
Mammoth Energy Partners LP/Mammoth Energy Services, Inc.
In the fourth quarter of 2014, the Company contributed its investments in four entities to Mammoth Energy Partners LP (“Mammoth”) for a 30.5% interest in this entity. Mammoth originally intended to pursue its initial public offering in 2014 or 2015; however, due to low commodity prices, the offering was postponed. In October 2016, Mammoth converted from a limited partnership into a limited liability company named Mammoth Energy Partners LLC (“Mammoth LLC”) and the Company and the other members of Mammoth LLC contributed their interests in Mammoth LLC to Mammoth Energy. The Company received 9,150,000 shares of Mammoth Energy common stock in return for its contribution. Following the contribution, Mammoth Energy completed its initial public offering (the “IPO”) of 7,750,000 shares of its common stock at a

2020.
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public offering price of $15.00 per share, of which 7,500,000 shares were sold by Mammoth Energy, and 250,000 shares were sold by certain selling stockholders, including 76,250 shares sold by the Company for which it received net proceeds of $1.1 million.
On June 5, 2017, the Company contributed all of its membership interests in Sturgeon (which owns Taylor Frac,Tatex Thailand II, LLC Taylor Real Estate Investments, LLC and South River Road, LLC), Stingray Energy and Stingray Cementing to Mammoth Energy in exchange for approximately 2.0 million shares of Mammoth Energy common stock. As of September 30, 2017, the Company held approximately 25.1% of Mammoth Energy’s outstanding common stock. The Company accounted for the transactions as a sale of financial assets under FASB ASC 860. The Company valued the shares of Mammoth Energy common stock it received in the transactions at $18.50 per share, which was the closing price of Mammoth Energy common stock on June 5, 2017. The Company recognized a gain of $12.5 million from the transactions, which is included in loss from equity method investments, net in the accompanying consolidated statements of operations.
The Company’s investment in Mammoth Energy was increased by a $0.16 million and $0.2 million foreign currency gain resulting from Mammoth Energy’s foreign subsidiary for the three and nine months ended September 30, 2017, respectively. The Company's investment in Mammoth Energy was increased by a $0.2 million foreign currency gain and decreased by a $1.1 million foreign currency loss resulting from Mammoth Energy's foreign subsidiary for the three and nine months ended September 30, 2016, respectively. The (income) loss from equity method investments presented in the table above reflects any intercompany profit eliminations.
Strike Force Midstream LLC
In February 2016, the Company, through its wholly owned subsidiary Gulfport Midstream Holdings, LLC (“Midstream Holdings”), entered into an agreement with Rice Midstream Holdings LLC (“Rice”), a subsidiary of Rice Energy Inc., to develop natural gas gathering assets in eastern Belmont County and Monroe County, Ohio (the “dedicated areas”). The Company contributed certain gathering assets for a 25% interest in the newly formed entity called Strike Force Midstream LLC (“Strike Force”). Rice acts as operator and owns the remaining 75% interest in Strike Force. Construction of the gathering assets, which is ongoing, is expected to provide gathering services for Gulfport operated wells and connectivity of existing dry gas gathering systems. During the nine months ended September 30, 2017, Gulfport paid $43.0 million in cash calls to Strike Force and received distributions of $3.6 million from Strike Force. During the nine months ended September 30, 2016, Gulfport paid $4.0 million in cash calls to Strike Force.
The Company accounted for its initial contribution to Strike Force at fair value under applicable codification guidance. The Company estimated the fair market value of its investment in Strike Force as of the contribution date using the discounted cash flow method under the income approach, based onhas an independently prepared valuation of the contributed assets. The fair market value was reduced by a discount factor for the lack of marketability due to the Company’s minority interest, resulting in a fair value of $22.5 million for the Company’s 25% interest. The fair value of the assets contributed was estimated using assumptions that represent Level 3 inputs. See “Note 11 - Fair Value Measurements” for additional discussion of the measurement inputs. The Company has elected to report its proportionate share of Strike Force’s earnings on a one-quarter lag as permitted under FASB ASC 323. The (income) loss from equity method investments presented in the table above reflects any intercompany profit eliminations.
4.VARIABLE INTEREST ENTITIES
As of September 30, 2017, the Company held variable interests in the following variable interest entities (“VIEs”), but was not the primary beneficiary: Midstream and Timber Wolf. These entities have governing provisions that are the functional equivalent of a limited partnership and are considered VIEs because the limited partners or non-managing members lack substantive kick-out or participating rights which causes the equity owners, as a group, to lack a controlling financial interest. The Company is a limited partner or non-managing member in each of these VIEs and is not the primary beneficiary because it does not have a controlling financial interest. The general partner or managing member has power to direct the activities that most significantly impact the VIEs’ economic performance. The Company also held a variableindirect ownership interest in Strike Force due toTatex Thailand II, LLC ("Tatex") and received 0 distributions and $2.1 million in distributions from Tatex during the fact that it does not have sufficient equity capital at risk. The Company is not the primary beneficiary of this entity. Prior to Mammoth Energy’s IPO, Mammothsix months ended June 30, 2020 and 2019, respectively. Tatex previously held an 8.5% interest in APICO, LLC was considered a variable interest entity. As a result of the Company’s contribution of(“APICO”), an international oil and gas exploration company, before selling its interest in Mammoth LLC to Mammoth EnergyJune 2019. APICO has a reserve base located in exchange for Mammoth Energy common stock and Mammoth Energy’s IPO,Southeast Asia through its ownership of concessions covering approximately 108,000 acres which includes the Company determined that it no longer held an interest in a variable interest entity. Prior to the contribution of Stingray Energy, Stingray Cementing and Sturgeon to Mammoth Energy, these entities were considered VIEs. As a result of the Company’s contribution of its membership interests in Stingray Energy, Stingray Cementing and Sturgeon to Mammoth Energy in exchange for Mammoth Energy common stock, the Company determined that it no longer held an interest in a variable interest entity.Phu Horm Field.


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5.LONG-TERM DEBT

The Company accounts for its investment in these 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 these 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. See Note 3 for further discussion of these entities, including the carrying amounts of each investment.
5.LONG-TERM DEBT
Long-term debt consisted of the following items as of SeptemberJune 30, 20172020 and December 31, 2016:
2019:
 September 30, 2017 December 31, 2016
 (In thousands)
Revolving credit agreement (1)$365,000
 $—
7.75% senior unsecured notes due 2020 (2)—
 —
6.625% senior unsecured notes due 2023 (3)350,000
 350,000
6.000% senior unsecured notes due 2024 (4)650,000
 650,000
6.375% senior unsecured notes due 2025 (5)600,000
 600,000
Net unamortized debt issuance costs (6)(30,111) (27,174)
Construction loan (7)23,817
 21,049
Less: current maturities of long term debt(570) (276)
Debt reflected as long term$1,958,136
 $1,593,599
The Company capitalized approximately $2.1 million and $8.8 million in interest expense to undeveloped oil and natural gas properties during the three and nine months ended September 30, 2017, respectively. The Company capitalized approximately $4.7 million and $7.7 million in interest expense to undeveloped oil and natural gas properties during the three and nine months ended September 30, 2016, respectively. During the three and nine months ended September 30, 2016, the Company also capitalized approximately $0.5 million and $1.2 million, respectively, in interest expense related to building construction. Construction on the building was completed in December 2016 and, as such, the Company did not capitalize any interest expense related to building construction for the three and nine months ended September 30, 2017.
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 certain lenders from time to time party thereto.other lenders. The credit agreement provides for a maximum facility amount of $1.5 billion and matures on June 6, 2018. On December 13, 2016,2021. On May 1, 2020, the Company further amended its revolving credit facilityentered into the fifteenth amendment to among other things, (a) reset the maturity dateAmended 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 December 31, 2021, (b) adjust lenders, (c) increase$700.0 million. Additionally, the basket for unsecured debt issuances to $1.6 billion, (d) increase the interest rates by 50 basis points, (e) increase the mortgageamendment added a requirement to 85% (from 80%), and (f) add deposit account control agreement language. On March 29, 2017, the Company further amended its revolving credit facilitymaintain a ratio of Net Secured Debt to among other things, amend the definition of the term EBITDAX to permit pro forma treatment of acquisitions that involve the payment of consideration by Gulfport and its subsidiaries in excess of $50.0 million and of dispositions of property or series of related dispositions of properties that yields gross proceeds to Gulfport or any of its subsidiaries in excess of $50.0 million. On May 4, 2017,(as defined under the revolving credit facility was further amendedagreement) not exceeding 2.00 to increase1.00, deferred the borrowing base from $700.0 millionrequirement to $1.0 billion, adjust certainmaintain a ratio of Net Funded Debt to EBITDAX of 4.00 to 1.00 until September 30, 2021 and added a limitation on the Company’s investment baskets and add five additional banksrepurchase of unsecured notes, among other amendments.
On July 27, 2020, the Company entered into the sixteenth amendment to the syndicate.Amended and Restated Credit Agreement. The sixteenth amendment allows for the Company to issue up to $750 million in second lien debt subject to certain conditions. See Note 16 for further information on this amendment.
As of SeptemberJune 30, 2017, $365.02020, $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 $237.5$324.1 million of letters of credit, was $397.5$252.9 million. The Company’s wholly-ownedwholly owned subsidiaries have guaranteed the obligations of the Company under the revolving credit facility.
In connection with the Company's fall redetermination under its revolving credit facility, the lead lenders have proposed to increase the Company's borrowing base from $1.0 million to $1.2 billion, with an elected commitment of $1.0 billion, and decrease the interest rate by 50 basis points, subject to the approval of the additional required banks within the syndicate.
AdvancesAt June 30, 2020, amounts borrowed under the 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 1.00% to 2.00%, plus (2) the highest of: (a) the

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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 2.00% to 3.00%, 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 service that displays on average London interbank offered rate as determined by ICE Benchmark Administration (or any other person that takes over 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, 2017, amounts borrowed under the credit facility bore interest at the eurodollara weighted average rate (3.74%).
The revolving credit facility contains customary negative covenants including, but not limited to, restrictions on the Company’s and its subsidiaries’ ability to:
•incur indebtedness;
•grant liens;
•pay dividends and make other restricted payments;
•make investments;
•make fundamental changes;
•enter into swap contracts and forward sales contracts;
•dispose of assets;
•change the nature of their business; and
•enter into transactions with affiliates.
The negative covenants are subject to certain exceptions as specified in the revolving credit facility. The revolving credit facility also contains certain affirmative covenants, including, but not limited to the following financial covenants:
(i) the ratio of net funded 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 investments plus without duplication and, in 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, 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 disposition will be limited to $3.0 million in the aggregate) for a twelve-month period may not be greater than 4.00 to 1.00; and
(ii) the ratio of EBITDAX to interest expense for a twelve-month period may not be less than 3.00 to 1.00.2.44%.
The Company was in compliance with allits financial covenants under the revolving credit facility at SeptemberJune 30, 2017.2020.
(2) On October 17, 2012,Loan issuance costs related to the Company issued $250.0 million in aggregate principal amount of 7.75% Senior Notes due 2020 (the “October Notes”) under an indenture among the Company, its subsidiary guarantors and Wells Fargo Bank, National Association, as the trustee (the “senior note indenture”). On December 21, 2012, the Company issued an additional $50.0 million in aggregate principal amount of 7.75% Senior Notes due 2020 (the “December Notes”) as additional securities under the senior note indenture. On August 18, 2014, the Company issued an additional $300.0 million in aggregate principal amount of 7.75% Senior Notes due 2020 (the “August Notes”). The August Notes were issued as additional securities under the senior note indenture. The October Notes, December Notes and the August Notes are collectively referred to as the “2020 Notes.”
In October 2016, the Company repurchased (in a cash tender offer) or redeemed all of the 2020 Notes, of which $600.0 million in aggregate principal amount was then outstanding, with the net proceeds from the issuance of its 6.000% Senior Notes

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due 2024 (the “2024 Notes”) discussed below and cash on hand, and the indenture governing the 2020 Notes was fully satisfied and discharged.
(3) On April 21, 2015, the Company issued $350.0 million in aggregate principal amount of 6.625% Senior Notes due 2023 (the “2023 Notes”"2023 Notes") to qualified institutional buyers pursuant to Rule 144A under, the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act6.000% Senior Notes due 2024 (the “2023 Notes Offering”). The Company received net proceeds of approximately $343.6 million after initial purchaser discounts and commissions and estimated offering expenses.
The 2023 Notes were issued under an indenture, dated as of April 21, 2015, among the Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee. In October 2015, the 2023 Notes were exchanged for a new issue of substantially identical debt securities registered under the Securities Act. Pursuant to the indenture relating to the 2023 Notes, interest on the 2023 Notes accrues at a rate of 6.625% per annum on the outstanding principal amount thereof, payable semi-annually on May 1 and November 1 of each year. The 2023 Notes are not guaranteed by Grizzly Holdings, Inc. and will not be guaranteed by any of the Company’s future unrestricted subsidiaries.
(4) On October 14, 2016, the Company issued the 2024 Notes in aggregate principal amount of $650.0 million. The 2024 Notes were issued under an indenture, dated as of October 14, 2016, among the Company, the subsidiary guarantors party thereto and the senior note indenture trustee (the “2024 Indenture”"2024 Notes"), to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act (the “2024 Notes Offering”). Under the 2024 Indenture, 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. The Company received approximately $638.9 million in net proceeds from the offering of the 2024 Notes, which was used, together with cash on hand, to purchase the outstanding 2020 Notes in a concurrent cash tender offer, to pay fees and expenses thereof, and to redeem any of the 2020 Notes that remained outstanding after the completion of the tender offer.
(5) On December 21, 2016, the Company issued $600.0 million in aggregate principal amount of 6.375% Senior Notes due 2025 (the “2025 Notes”"2025 Notes"). The 2025 Notes were issued under an indenture, dated as of December 21, 2016, among the Company, the subsidiary guarantors party thereto and the senior note indenture trustee6.375% Senior Notes due 2026 (the “2025 Indenture”"2026 Notes"), to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. Under the 2025 Indenture, 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. The Company received approximately $584.7 million in net proceeds from the offering of the 2025 Notes, which was used, together with the net proceeds from the Company’s December 2016 common stock offering and cash on hand, to fund the cash portion of the purchase price for the Vitruvian Acquisition. See “Note 1 – Acquisitions” for additional discussion of the Vitruvian Acquisition.
(6) In accordance with ASU 2015-03, loan issuance costs related to the 2023 Notes, the 2024 Notes and the 2025 Notes (collectively the “Notes”) have been presented as a reduction to the principal amount of the Notes. At SeptemberJune 30, 2017,2020, total unamortized debt issuance costs were $5.5$2.8 million for the 2023 Notes, $10.2$6.1 million for the 2024 Notes, and $14.3$8.5 million for the 2025 Notes and $3.4 million for the 2026 Notes. In addition, loan commitment fee costs for the Company's construction loan agreement described immediately below were $0.1 million at SeptemberJune 30, 2017.2020.
(7) On June 4, 2015, theThe Company entered into a construction loan agreement (the “Construction Loan”) with InterBank for the construction of a new corporate headquarters in Oklahoma City, which was substantially completed in December 2016. The Construction Loan allows for maximum principal borrowings of $24.5capitalized approximately $0.5 million and required$0.7 million in interest expense to its unevaluated oil and natural gas properties during the Company 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 annumthree and was payable on the last day of the month through May 31, 2017. Monthly interest and principal payments are due beginningsix months ended June 30, 2017, with the final payment due June 4, 2025. At September 30, 2017, the total borrowings under the Construction Loan were2020, respectively. The Company capitalized approximately $23.8 million.
6.COMMON STOCK AND CHANGES IN CAPITALIZATION
Issuance of Common Stock
On March 15, 2016, the Company issued 16,905,000 shares of its common stock in an underwritten public offering (which included 2,205,000 shares sold pursuant to an option to purchase shares sold pursuant to an option to purchase additional shares

$1.0
16
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million and $1.8 million in interest expense to its unevaluated oil and natural gas properties during the three and six months ended June 30, 2019, respectively.
Debt Repurchases
In 2019, the Company's Board of Directors authorized $200 million of cash to be used to repurchase its senior notes in the Company’s common stock granted by the Companyopen market at discounted values to and exercised in full by, the underwriters). The net proceeds from this equity offering were approximately $411.7 million, after underwriting discounts and commissions and offering expenses.par. The Company used borrowings under its revolving credit facility to repurchase in the net proceeds fromopen market $47.5 million and $73.3 million aggregate principal amount of its outstanding Notes for $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 offering primarilyincluded $4.9 million principal amount of the 2023 Notes, $16.3 million principal amount of the 2024 Notes, $13.5 million principal amount of the 2025 Notes, and $12.8 million principal amount of the 2026 Notes. The Company recognized a $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, 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. As of May 1, 2020, further repurchases under this program are limited due to fundthe agreements entered into under the fifteenth amendment to the 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 debt represented by the Notes was approximately $1.8 billion. Based on the quoted market prices (Level 1), the fair value of the Notes was determined to be approximately $930.2 million at June 30, 2020.

6.CHANGES IN CAPITALIZATION
Stock Repurchases
In January 2019, the Company's Board of Directors approved a stock repurchase program to acquire a portion of its 2017 capital development planthe Company's outstanding common stock within a 24-month period. The program was suspended in the fourth quarter of 2019, and for general corporate purposes.the May 1, 2020 amendment to the Company's revolving credit facility prohibits further stock repurchases.
On February 17, 2017,For the three and six months ended June 30, 2019, the Company completed the Vitruvian Acquisitionrepurchased 0.2 million and 3.8 million shares for a total initial purchase pricecost of approximately $1.85 billion, consisting$1.8 million and $30.0 million, respectively, under this repurchase program.
Additionally, during the three and six months ended June 30, 2020, the Company repurchased approximately 27,000 and 107,000 shares, respectively, for a cost of $1.35 billion in cash, subject$28 thousand and $0.1 million, respectively, to certain adjustments, and approximately 23.9 million sharessatisfy tax withholding requirements incurred upon the vesting of the Company’s common stock (of which approximately 5.2 million shares are subject to the indemnity escrow). See “Note 1 - Acquisitions” for additional discussion of the Vitruvian Acquisition.
7.STOCK-BASED COMPENSATION
restricted stock. During the three and ninesix months ended SeptemberJune 30, 2017,2019, the Company repurchased approximately 72,000 and 87,000 shares, respectively, for a cost of $0.5 million and $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.

7.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 six months ended June 30, 2020, the Company’s stock-based compensation cost was $2.8$2.2 million and $8.0$4.3 million, respectively, of which the Company capitalized $1.1$1.0 million and $3.2$1.9 million, respectively, relating to its exploration and development efforts. During the three and ninesix months ended SeptemberJune 30, 2016,2019, the Company'sCompany’s stock-based compensation cost was $3.0$2.8 million and $9.6$5.6 million, respectively, of which the Company capitalized $1.2$1.1 million and $3.8$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, 2017:2020:
 
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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
Number of
Unvested
Restricted Shares
 
Weighted
Average
Grant Date
Fair Value
Unvested shares as of January 1, 2017613,056
 $32.90
Unvested shares as of January 1, 2020Unvested shares as of January 1, 20204,098,318  $4.73  1,783,660  $2.96  
Granted870,358
 15.15
Granted1,985,452  0.67  —  —  
Vested(399,843) 28.77
Vested(512,283) 7.19  —  —  
Forfeited(74,024) 30.45
Forfeited(979,929) 3.82  (830,323) 1.98  
Unvested shares as of September 30, 20171,009,547
 $19.42
Unvested shares as of June 30, 2020Unvested 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, 20172020 related to restricted stock units was $9.4 million. The expense is expected to be recognized over a weighted average period of 1.75 years.
Performance Vesting Restricted Stock Units
The 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. Unrecognized compensation expense as of June 30, 2020 related to performance vesting restricted shares was $17.2$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 1.611.62 years.


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8.EARNINGS PER SHARE
Reconciliations of the components of basic and diluted net income (loss) per common share are presented in the tables below:
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Three months ended September 30,Three months ended June 30,
2017 2016 20202019
Income Shares 
Per
Share
 (Loss) Shares 
Per
Share
LossSharesPer
Share		IncomeSharesPer
Share
(In thousands, except share data)(In thousands, except share data)
Basic:           Basic:
Net income (loss)$18,235
 182,957,416
 $0.10
 $(157,296) 125,408,866
 $(1.25)
Net (loss) incomeNet (loss) income$(561,068) 159,933,739  $(3.51) $234,956  159,324,909  $1.47  
Effect of dilutive securities:
 
 
 
 
 
Effect of dilutive securities:
Stock options and awards—
 51,020
 
 —
 —
 
Stock awardsStock awards—  —  —  181,917  
Diluted:
 —
 
 
 0 
Diluted:
Net income (loss)$18,235
 183,008,436
 $0.10
 $(157,296) 125,408,866
 $(1.25)
Net (loss) incomeNet (loss) income$(561,068) 159,933,739  $(3.51) $234,956  159,506,826  $1.47  
Six months ended June 30,
20202019
LossSharesPer
Share		IncomeSharesPer
Share
(In thousands, except share data)
Basic:
Net (loss) income$(1,078,606) 159,846,981  $(6.75) $297,198  161,064,787  $1.85  
Effect of dilutive securities:
Stock options and awards—  —  —  525,300  
Diluted:
Net (loss) income$(1,078,606) 159,846,981  $(6.75) $297,198  161,590,087  $1.84  
            
            
 Nine months ended September 30,
 2017 2016
 Income Shares Per
Share		 (Loss) Shares Per
Share
 (In thousands, except share data)
Basic:           
Net income (loss)$278,626
 178,736,569
 $1.56
 $(739,339) 120,771,046
 $(6.12)
Effect of dilutive securities:
 
 
 
 
 
Stock options and awards—
 394,001
 
 —
 —
 
Diluted:
 —
 
 
 —
 
Net income (loss)$278,626
 179,130,570
 $1.56
 $(739,339) 120,771,046
 $(6.12)

There were 603,0681,281,773 and 598,7531,610,572 shares of common stock that were considered anti-dilutive for the three months and ninesix months ended SeptemberJune 30, 2016,2020, respectively. There were 0 potential shares of common stock that were considered anti-dilutive for the three and six months ended June 30, 2019.



18
9.COMMITMENTS AND CONTINGENCIES
Table of Contents


9.COMMITMENTS AND CONTINGENCIES
Plugging and Abandonment Funds
In connection with the Company’s acquisition in 1997 of the remaining 50% interest in its WCBB properties, the Company assumed the seller’s (Chevron) obligation to contribute approximately $18,000 per month through March 2004 to a plugging and abandonment trust and the obligation to plug a minimum of 20 wells per year for 20 years commencing March 11, 1997. Chevron retained a security interest in production from these properties until the Company’s abandonment obligations to Chevron have been fulfilled. Beginning in 2009, the Company could access the trust for use in plugging and abandonment charges associated with the property, although it has not yet done so. As of September 30, 2017, the plugging and abandonment trust totaled approximately $3.1 million. At September 30, 2017, the Company had plugged 551 wells at WCBB since it began its plugging program in 1997, which management believes fulfills its minimum plugging obligation.
Operating LeasesFuture Firm Sales Commitments
The Company leases office facilities under non-cancellable operating leases exceeding one year. has entered into various firm sales contracts to deliver and sell natural gas. The Company expects to fulfill its delivery commitments 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 minimum lease commitments under these leases at September 30, 2017 were as follows:
  (In thousands)
Remaining 2017 $27
2018 54
Total $81
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
15
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recorded 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:
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 contracts to deliver approximately 3,077,0001,455,000 MMBtu per day for the remainder of firm sales contracted with third parties. The table below presents2020 and 2021, respectively. Under these commitments at September 30, 2017 as follows:
  (MMBtu per day)
Remaining 2017 710,000
2018 561,000
2019 659,000
2020 526,000
2021 372,000
Thereafter 249,000
Total 3,077,000
The Company also had approximately $3.7 billion of firm transportation contracted with third parties. The table below presents these commitments at September 30, 2017 as follows:
  (In thousands)
Remaining 2017 $49,052
2018 238,767
2019 243,389
2020 240,746
2021 239,786
Thereafter 2,715,005
Total $3,726,745


19
Tablecontracts, the Company is obligated to deliver minimum daily volumes or pay fees for any deficiencies in deliveries. As a result of Contents


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 that expires on September 30, 2018.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.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 $0.2$1.9 million and $2.1$3.8 million related toin non-utilization fees under this agreement during the three months and ninesix months ended SeptemberJune 30, 2016,2020, respectively. The Company did not incur any non-utilization fees under this agreement during the three and nine months ended SeptemberJune 30, 2017.2019 and incurred $0.3 million of such fees during the six months ended June 30, 2019.
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, that expires on September 30, 2018. Pursuant to this agreement, as amended, Stingray Pressure has agreed to provide hydraulic fracturing, stimulation and related completion and rework services to the Company and the Company has agreed to pay Stingray Pressure a monthly service fee plus the associated costs of the services provided.
Future minimum commitments under these agreementsthis agreement at SeptemberJune 30, 2017 are as follows:
2020 are:
  (In thousands)
Remaining 2017 $13,110
2018 39,330
Total $52,440
(In thousands)
Remaining 2020$3,750  
20217,500  
Total$11,250  

Litigation and Regulatory Proceedings
In twoThe 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 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 2 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
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District of the State of Louisiana in the 15th15th Judicial District Court for the Parish of VermillionVermilion on July 29, 2016 (together, the Company was named as a defendant, among 26 oil and gas companies, in the Cameron Parish complaint and among more than 40 oil and gas companies in the Vermillion Parish complaint, or the Complaints."Complaints"). The Complaints were filed underallege 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 which the Company referred to collectively as the CZM Laws, and allege that certain of the defendants’ oil and gas exploration, production and transportation operations associated with the development of the East Hackberry and West Hackberry oil and gas fields, in the case of the Cameron Parish complaint, and the Tigre Lagoon and Lac Blanc oil and gas fields, in the case of the Vermillion Parish complaint, were conducted in violation of the CZM Laws. The Complaints allege that such activities caused(the "CZM Laws") by causing substantial damage to land and waterbodies located in the coastal zone of the relevant Parish, including due to defendants’ design, construction and use of waste pits and the alleged failure to properly close the waste pits and to clear, re-vegetate, detoxify and return the property affected to its original condition, as well as the defendants’ alleged discharge of waste into the coastal zone.Parish. The Complaints also allege that the defendants’ oil and gas activities have resulted in the dredging of numerous canals, which had a direct and significant impact on the state coastal waters within the relevant Parish and that the defendants, among other things, failed to design, construct and maintain these canals using the best practical techniques to prevent bank slumping, erosion and saltwater intrusion and to minimize the potential for inland movement of storm-generated surges, which activities allegedly have resulted in the erosion of marshes and the degradation of terrestrial and aquatic life therein. The Complaints also allege that the defendants failed to re-vegetate, refill, clean, detoxify and otherwise restore these canals to their original condition. In these two petitions, 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 pre-judgment and post judgment interest.
The Company was served withUnited States District Court for the Cameron complaint in early May 2016 and with the Vermillion complaint in early September 2016.  TheWestern District of Louisiana Attorney General and the Louisiana Department of Natural Resources intervened in both the Cameron Parish suit and the Vermillion Parish suit.  Shortly after the Complaints were filed, certain defendants removedissued orders remanding the cases to their respective state court, and the lawsuitdefendants 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 many 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 Louisiana.  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 both cases,October 2019, Kelsie Wagner, in her capacity as trustee of various trusts and on behalf of the plaintiffstrusts and other similarly situated royalty owners, filed a motion to remand, andan action against the plaintiffs agreed to an extension of time for all defendants to file responsive pleadings until the District Courts ruled on the motions to remand.  In the Vermilion Parish case,Company in the District Court enteredof 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 order on September 26, 2017 remandingaction against certain of our current and former executive officers and directors in the lawsuitUnited States District Court for the District of Delaware. The complaint alleges that the defendants breached their fiduciary duties to the 15th JudicialCompany 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 Statefor the Southern District of Louisiana, ParishOhio 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 Vermilion.  Pursuant40 hours per week. The complaint seeks to recover unpaid regular and overtime wages, liquidated damages in an

amount equal
20
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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.
agreement with plaintiffs’ counsel, all defendants have an extension of time through November 27, 2017 to file responsive pleadings to plaintiffs’ petitionsThese cases are still in the Vermilion Parish lawsuit.  In the Cameron Parish lawsuit, the District Court has not ruled on plaintiffs’ motion to remand.  Briefing on the motion to remand has been completed; however, no hearing has been set for the motion to remand, and the District Court has not given the parties any indication regarding whentheir early stages. As a ruling should be expected. Due the procedural posture of lawsuits, the fact that responsive pleadings have not been filed and the fact that the parties have not begun discovery,result, the Company has not had the opportunity to evaluate the applicability of the allegations made in the plaintiffs' complaints and intends to vigorously defend the suits.
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 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 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 17 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 resulted in monetary sanctions of 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 operationspurchase 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 management cannot determineto pay the costs from not having the proper permits in place in the amount of loss, if any, that may result.
In addition, due$180,000 to the natureODEQ. 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 Company’s business, it is, from time to time, involved in routine litigationopinion that no pending or subject to disputesthreatened lawsuit or claims relateddispute relating to its business activities, including workers’ compensation claims and employment related disputes. In the opinion of the Company’s management, none of the pending litigation, disputes or claims against the Company, if decided adversely, willoperations is likely to have a material adverse effect on itstheir future consolidated financial condition, cash flows orposition, results of operations.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.
18
10.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 ("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 natural gas liquidsNGL 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, Argus Louisiana Light Sweet Crude for oil, the NYMEX West Texas Intermediate for oil and Mont Belvieu for propane, pentane and pentane.ethane. Below is a summary of the Company’s open fixed price swap positions as of SeptemberJune 30, 2017.2020.
LocationDaily Volume
(MMBtu/day)		Weighted
Average Price
Remaining 2020NYMEX Henry Hub357,000  $2.86  
 LocationDaily Volume (MMBtu/day) Weighted
Average Price
Remaining 2017NYMEX Henry Hub765,000
 $3.19
2018NYMEX Henry Hub898,000
 $3.06
2019NYMEX Henry Hub112,000
 $3.01
LocationDaily Volume
(Bbls/day)		Weighted
Average Price
Remaining 2020NYMEX WTI3,000  $35.49  
 LocationDaily Volume
(Bbls/day)		 Weighted
Average Price
Remaining 2017ARGUS LLS1,500
 $53.12
2018ARGUS LLS1,000
 $53.91
Remaining 2017NYMEX WTI4,500
 $54.89
2018NYMEX WTI3,000
 $52.24
 LocationDaily Volume
(Bbls/day)		 Weighted
Average Price
Remaining 2017Mont Belvieu C33,000
 $26.63
2018Mont Belvieu C33,500
 $28.03
Remaining 2017Mont Belvieu C5250
 $49.14
2018Mont Belvieu C5500
 $46.62

21

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 short call option has an established ceiling price. When the referenced settlement price is above the price ceiling established by these short 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
2022NYMEX Henry Hub628,000  $2.90  
2023NYMEX Henry Hub628,000  $2.90  
 LocationDaily Volume (MMBtu/day) Weighted Average Price
Remaining 2017NYMEX Henry Hub65,000
 $3.11
2018NYMEX Henry Hub103,000
 $3.25
2019NYMEX Henry Hub135,000
 $3.07
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 combined natural gas derivative instruments containing fixed price swapsranges set by the floor and sold call options,ceiling prices in the counterparty has an option to extend the original terms an additional twelve months for the period January 2018 through December 2018. The option to extend the terms expires in December 2017. If extended,various collars, the Company would have additional fixed price swaps for 30,000 MMBtu per day at a weighted average price of $3.36 per MMBtu and additional short call options for 30,000 MMBtu per day at a weighted average ceiling price of $3.36 per MMBtu.will cash-settle the difference with the counterparty.
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. The option to extend the terms expires in December 2018. If executed, the Company would have additional fixed price swaps for 100,000 MMBtu per day at a weighted average price of $3.05 per MMBtu.
LocationDaily Volume (MMBtu/day)Weighted Average Floor PriceWeighted Average Ceiling Price
2021NYMEX Henry Hub250,000  $2.46  $2.81  
In addition, the Company has entered into natural gas basis swap positions, which settle on the pricing index to basis differential of NGPL Mid-Continent to NYMEX Henry Hub.positions. As of SeptemberJune 30, 2017,2020, the Company had the following natural gas basis swap positions for NGPL Mid-Continent.open:
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) 
19

 LocationDaily Volume (MMBtu/day) Hedged Differential
Remaining 2017NGPL Mid-Continent50,000
 $(0.26)
2018NGPL Mid-Continent12,000
 $(0.26)
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 Company sold its non-core assets located in the West Cote Blanche Bay and Hackberry fields of Louisiana in July 2019. The sale price included the potential for the Company to receive contingent payments based on commodity prices exceeding specified thresholds over the two years following the closing date. This contingent consideration arrangement was 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)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.
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, 20172020 and December 31, 2016:2019:
 September 30, 2017 December 31, 2016
 (In thousands)
Short-term derivative instruments - asset$35,332
 $3,488
Long-term derivative instruments - asset$6,409
 $5,696
Short-term derivative instruments - liability$29,130
 $119,219
Long-term derivative instruments - liability$19,712
 $26,759
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

22

The following table presents the gain and loss recognized in Net (loss)net gain on natural gas, oil and NGL derivatives in the accompanying consolidated statements of operations for the three and ninesix months ended SeptemberJune 30, 20172020 and 2016.2019.
20

Net (loss) gain on derivative instrumentsNet gain (loss) on derivative instruments
Three months ended September 30, Nine months ended September 30,Three months ended June 30,Six months ended June 30,
2017 2016 2017 20162020201920202019
(In thousands)(In thousands)
Natural gas derivatives$(7,077) $33,167
 $135,868
 $(43,454)Natural gas derivatives$35,689  $152,475  $81,542  $136,044  
Oil derivatives(6,571) 1,708
 12,477
 362
Oil derivatives(7,937) 11,871  44,937  11,417  
Natural gas liquids derivatives(9,212) 406
 (6,757) (1,284)
NGL derivativesNGL derivatives(781) 6,794  139  3,634  
Contingent consideration arrangementContingent consideration arrangement—  —  (1,381) —  
Total$(22,860) $35,281
 $141,588
 $(44,376)Total$26,971  $171,140  $125,237  $151,095  
Offsetting of derivative assetsDerivative Assets and liabilitiesLiabilities
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, 2017
 Gross Assets (Liabilities) Gross Amounts  
 Presented in the Subject to Master Net
 Consolidated Balance Sheets Netting Agreements Amount
 (In thousands)
Derivative assets$41,741
 $(36,969) $4,772
Derivative liabilities$(48,842) $36,969
 $(11,873)
As of December 31, 2016As of December 31, 2019
Gross Assets (Liabilities) Gross Amounts  Gross Assets (Liabilities)Gross Amounts
Presented in the Subject to Master NetPresented in theSubject to MasterNet
Consolidated Balance Sheets Netting Agreements AmountConsolidated Balance SheetsNetting AgreementsAmount
(In thousands)(In thousands)
Derivative assets$9,184
 $(9,184) $—
Derivative assets$126,764  $(53,438) $73,326  
Derivative liabilities$(145,978) $9,184
 $(136,794)Derivative liabilities$(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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11.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 in accordance with FASB ASC 820, “Fair Value Measurement and Disclosures” (“FASB ASC 820”). FASB ASC 820 defines fair value asis 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. The statement establishes marketMarket or observable inputs asare the preferred

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sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The statement requires fairFair value measurements beare 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 FASB ASC 820 valuation level as of SeptemberJune 30, 20172020 and December 31, 2016:2019:
June 30, 2020
Level 1Level 2Level 3
(In thousands)
Assets:
Derivative Instruments$— $57,486 $— 
Liabilities:
Derivative Instruments$— $54,155 $— 
 September 30, 2017
 Level 1 Level 2 Level 3
 (In thousands)
Assets:     
Derivative Instruments$—
 $41,741
 $—
Liabilities:     
Derivative Instruments$—
 $48,842
 $—
December 31, 2019
Level 1Level 2Level 3
(In thousands)
Assets:
Derivative Instruments$— $126,764 $— 
Liabilities:
Derivative Instruments$— $53,438 $— 

 December 31, 2016
 Level 1 Level 2 Level 3
 (In thousands)
Assets:     
Derivative Instruments$—
 $9,184
 $—
Liabilities:     
Derivative Instruments$—
 $145,978
 $—


The Company estimates the fair value of all derivative instruments using industry-standard models that consideredconsider 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 estimated fair valuesvalue of proved oil and natural gas properties assumed in business combinations are based on athe contingent consideration arrangement is calculated using discounted cash flow modeltechniques and market assumptions as to future commodity prices, projectionsis based on internal estimates of estimated quantities of oil and natural gas reserves, expectations for timing and amount ofthe Company's future development program and operating costs, projections of future rates ofwater production expected recovery rates and risk-adjusted discount rates. The estimated fair values of unevaluated oil and natural gas properties was based on geological studies, historical well performance, location and applicable mineral lease terms. Based onlevels. Given the unobservable nature of certain of the inputs, the estimated fair value measurement of the oil and gas properties assumedcontingent consideration arrangement is deemed to use Level 3 inputs. The asset retirement obligations assumed as partCompany has elected the fair value option for this contingent consideration arrangement and, therefore, records changes in fair value in earnings. The Company recognized a loss of $3.2 million and $3.0 million on changes in fair value of the business combination were estimated usingcontingent consideration during the same assumptionsthree and methodology as described below. See Note 1 for further discussionsix months ended June 30, 2020, respectively, which is included in other expense (income) in
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the Vitruvian Acquisition.accompanying consolidated statements of operations. Settlements under the contingent consideration arrangement totaled $0.3 million during the six months ended June 30, 2020.
The Company estimates asset retirement obligations pursuant to the provisions of FASB ASC Topic 410, Asset Retirement and Environmental Obligations (“FASB ASC 410”). The initial measurement of asset retirement obligations at fair value is

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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, 20172020 were approximately $11.6 million.$1.6 million.
The fairFair value of the common stock received from Mammoth Energy in connection with the Company’s contribution of all of its membership interests in Sturgeon, Stingray Energy and Stingray Cementing was estimated using Level 1 inputs, as the price per share was a quoted price in an active market for identical Mammoth Energy common shares.financial instruments
Due to the unobservable nature of the inputs, the fair value of the Company’s investment in Grizzly was estimated using assumptions that represent Level 3 inputs. The Company estimated the fair value of the investment as of March 31, 2016 to be approximately $39.1 million. See Note 3 for further discussion of the Company’s investment in Grizzly.
Due to the unobservable nature of the inputs, the fair value of the Company’s initial investment in Strike Force was estimated using assumptions that represent Level 3 inputs. The Company’s estimated fair value of the investment as of the February 1, 2016 contribution date was $22.5 million. See Note 3 for further discussion of the Company’s contribution to Strike Force.
12.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 Construction LoanCompany'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
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 NGL. Sales of natural gas, oil and condensate and NGL 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 2017,days of the carryingend 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. 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 $65.6 and $121.2 million as of June 30, 2020 and December 31, 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 six months ended June 30, 2020, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

13.LEASES
Nature of Leases
The Company has operating leases associated with drilling rig commitments, 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 a contract for a drilling rig with a third party to ensure rig 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 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 liability associated with its rig commitment is based on the minimum contractual obligation, primarily standby rate, and does 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. As 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 of use assets and lease liabilities associated with the terminated contract.
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 outstanding debt represented by the Notes was approximately $1.6 billion, including the unamortized debt issuance costestimated rate of approximately $5.5 million relatedinterest that it would pay to borrow on a collateralized basis over a similar term an amount equal to the 2023 Notes, approximately $10.2 million related tolease payments in a similar economic environment.
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Maturities of operating lease liabilities as of June 30, 2020 were as follows:
(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 2024 Notesthree and approximately $14.3 million related to the 2025 Notes. Based on the quoted market price, the fair valuesix months ended June 30, 2020 and 2019 consisted of the Notes was determined to be approximately $1.6 billion at September 30, 2017.following:
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  
13.(1)CONDENSED CONSOLIDATING FINANCIAL INFORMATIONThe 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.
On October 17, 2012, December 21, 2012Supplemental cash flow information for the six months ended June 30, 2020 and August 18, 2014,2019 related to leases was as follows:
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 June 30, 2020 was 0.83 years. The weighted-average discount rate used to determine the operating lease liability as of June 30, 2020 was 2.47%.
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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 issued the 2020 Notes in an aggregaterecognized $7.3 million of $600.0 million principal amount. The 2020 Notes were subsequently exchanged for substantially identical notesincome tax expense discretely in the same aggregate principal amountquarter 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 were registered underit was more likely than not that the Securities Act. In October 2016, the Company repurchased (in a cash tender offer)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 redeemed all of the 2020 Notes, of which $600.0 million in aggregate principal amount was then outstanding, with the net proceedsbenefit from the issuancedeferred 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 2024 Notes discussed belowoil and cash on hand.gas industry.

On April 21, 2015,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 issued $350.0 millionduring any three-year period result in aggregate principal amounta 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. On April 30, 2020, the board of directors of the 2023 NotesCompany adopted a tax benefits preservation plan in order to qualified institutional buyers pursuantprotect against a possible limitation on the Company’s ability to Rule 144A under the Securities Actuse its tax net operating losses and certain other tax benefits to certain non-U.S. persons in accordance with Regulation S under the Securities Act. In connection with the 2023 Notes Offering, the Company and its subsidiary guarantors entered into a registration rights agreement, dated asreduce potential future U.S. federal income tax obligations. The Tax Benefits Preservation Plan is intended to prevent against such an ownership change by deterring any person or group from acquiring beneficial ownership of April 21, 2015, pursuant to which the Company agreed to file a registration statement with respect to an offer to exchange the 2023 Notes for a new issue of substantially identical debt securities registered under the Securities Act. The exchange offer for the 2023 Notes was completed on October 13, 2015.
On October 14, 2016, the Company issued $650.0 million in aggregate principal amount of the 2024 Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. The net proceeds from the issuance of the 2024 Notes, together with cash on hand, were used to repurchase4.9% or redeem all of the then-outstanding 2020 Notes in October 2016.
On December 21, 2016, the Company issued $600.0 million in aggregate principal amount of the 2025 Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. The Company used the net proceeds from the issuance of the 2025 Notes, together with the net proceeds from the December 2016 underwritten offeringmore of the Company’s common stock and cash on hand, to fund the cash portion of the purchase price for the Vitruvian Acquisition.

securities.
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15.CONDENSED CONSOLIDATING FINANCIAL INFORMATION
In connection with the 2024 Notes and the 2025 Notes Offerings, the Company and its subsidiary guarantors entered into two registration rights agreements, pursuant to which the Company agreed to file a registration statement with respect to offers to exchange the 2024 Notes and the 2025 Notes for new issues of substantially identical debt securities registered under the Securities Act. The exchange offers for the 2024 Notes and the 2025 Notes were completed on September 13, 2017.
The 2020 Notes were, and the 2023 Notes, the 2024 Notes, the 2025 Notes and the 20252026 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 2020 Notes were not, and the 2023 Notes, the 2024 Notes and the 2025 Notes are not guaranteed by Grizzly Holdings Inc.or Mule Sky LLC ("Mule Sky") (the “Non-Guarantor”“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 (loss) income and statements of cash flows are provided for the Parent, the Guarantors and the Non-GuarantorNon-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-Guarantor.Non-Guarantors.



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CONDENSED CONSOLIDATING BALANCE SHEETS
(Amounts in thousands)
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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 September 30, 2017
 Parent Guarantors Non-Guarantor Eliminations Consolidated
Assets         
Current assets:         
Cash and cash equivalents$89,095
 $36,175
 $1
 $—
 $125,271
Accounts receivable - oil and natural gas126,746
 53,360
 —
 —
 180,106
Accounts receivable - related parties362
 —
 —
 —
 362
Accounts receivable - intercompany514,187
 57,927
 —
 (572,114) —
Prepaid expenses and other current assets5,486
 180
 —
 —
 5,666
Short-term derivative instruments35,332
 —
 —
 —
 35,332
Total current assets771,208
 147,642
 1
 (572,114) 346,737
Property and equipment:         
Oil and natural gas properties, full-cost accounting6,371,324
 2,496,644
 —
 (729) 8,867,239
Other property and equipment84,182
 43
 —
 —
 84,225
Accumulated depletion, depreciation, amortization and impairment(4,043,843) (36) —
 —
 (4,043,879)
Property and equipment, net2,411,663
 2,496,651
 —
 (729) 4,907,585
Other assets:         
Equity investments and investments in subsidiaries2,262,011
 70,375
 58,674
 (2,111,778) 279,282
Long-term derivative instruments6,409
 —
 —
 —
 6,409
Deferred tax asset4,692
 —
 —
 —
 4,692
Inventories9,438
 4,470
 —
 —
 13,908
Other assets10,561
 8,424
 —
 —
 18,985
Total other assets2,293,111
 83,269
 58,674
 (2,111,778) 323,276
  Total assets$5,475,982
 $2,727,562
 $58,675
 $(2,684,621) $5,577,598
          
Liabilities and Stockholders’ Equity
         
Current liabilities:         
Accounts payable and accrued liabilities$430,195
 $152,733
 $—
 $—
 $582,928
Accounts payable - intercompany57,927
 514,060
 127
 (572,114) —
Asset retirement obligation - current195
 —
 —
 —
 195
Derivative instruments29,130
 —
 —
 —
 29,130
Current maturities of long-term debt570
 —
 —
 —
 570
Total current liabilities518,017
 666,793
 127
 (572,114) 612,823
Long-term derivative instrument19,712
 —
 —
 —
 19,712
Asset retirement obligation - long-term37,456
 6,810
 —
 —
 44,266
Long-term debt, net of current maturities1,958,136
 —
 —
 —
 1,958,136
Total liabilities2,533,321
 673,603
 127
 (572,114) 2,634,937
          
Stockholders’ equity:         
Common stock1,831
 —
 —
 —
 1,831
Paid-in capital4,413,623
 1,905,599
 258,871
 (2,164,470) 4,413,623
Accumulated other comprehensive (loss) income(40,339) —
 (38,443) 38,443
 (40,339)
Retained (deficit) earnings(1,432,454) 148,360
 (161,880) 13,520
 (1,432,454)
Total stockholders’ equity2,942,661
 2,053,959
 58,548
 (2,112,507) 2,942,661
  Total liabilities and stockholders’ equity
$5,475,982
 $2,727,562
 $58,675
 $(2,684,621) $5,577,598


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CONDENSED CONSOLIDATING BALANCE SHEETS
(Amounts in thousands)
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  
29
 December 31, 2016
 Parent Guarantors Non-Guarantor Eliminations Consolidated
Assets         
Current assets:         
Cash and cash equivalents$1,273,882
 $1,993
 $—
 $—
 $1,275,875
Restricted Cash185,000
 —
 —
 —
 185,000
Accounts receivable - oil and natural gas137,087
 37,496
 —
 (37,822) 136,761
Accounts receivable - related parties16
 —
 —
 —
 16
Accounts receivable - intercompany449,517
 1,151
 —
 (450,668) —
Prepaid expenses and other current assets3,135
 —
 —
 —
 3,135
Short-term derivative instruments3,488
 —
 —
 —
 3,488
Total current assets2,052,125
 40,640
 —
 (488,490) 1,604,275
          
Property and equipment:         
Oil and natural gas properties, full-cost accounting,5,655,125
 417,524
 —
 (729) 6,071,920
Other property and equipment68,943
 43
 —
 —
 68,986
Accumulated depletion, depreciation, amortization and impairment(3,789,746) (34) —
 —
 (3,789,780)
Property and equipment, net1,934,322
 417,533
 —
 (729) 2,351,126
Other assets:         
Equity investments and investments in subsidiaries236,327
 33,590
 45,213
 (71,210) 243,920
Long-term derivative instruments5,696
 —
 —
 —
 5,696
Deferred tax asset4,692
 —
 —
 —
 4,692
Inventories3,095
 1,409
 —
 —
 4,504
Other assets8,932
 —
 —
 —
 8,932
Total other assets258,742
 34,999
 45,213
 (71,210) 267,744
  Total assets$4,245,189
 $493,172
 $45,213
 $(560,429) $4,223,145
          
Liabilities and Stockholders’ Equity
         
Current liabilities:         
Accounts payable and accrued liabilities$255,966
 $9,158
 $—
 $—
 $265,124
Accounts payable - intercompany31,202
 457,163
 126
 (488,491) —
Asset retirement obligation - current195
 —
 —
 —
 195
Derivative instruments119,219
 —
 —
 —
 119,219
Current maturities of long-term debt276
 —
 —
 —
 276
Total current liabilities406,858
 466,321
 126
 (488,491) 384,814
          
Long-term derivative instrument26,759
 —
 —
 —
 26,759
Asset retirement obligation - long-term34,081
 —
 —
 —
 34,081
Long-term debt, net of current maturities1,593,599
 —
 —
 —
 1,593,599
Total liabilities2,061,297
 466,321
 126
 (488,491) 2,039,253
          
Stockholders’ equity:         
Common stock1,588
 —
 —
 —
 1,588
Paid-in capital3,946,442
 33,822
 257,026
 (290,848) 3,946,442
Accumulated other comprehensive (loss) income(53,058) —
 (50,931) 50,931
 (53,058)
Retained (deficit) earnings(1,711,080) (6,971) (161,008) 167,979
 (1,711,080)
Total stockholders’ equity2,183,892
 26,851
 45,087
 (71,938) 2,183,892
  Total liabilities and stockholders’ equity
$4,245,189
 $493,172
 $45,213
 $(560,429) $4,223,145


28
Table of Contents



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) 

30
 Three months ended September 30, 2017
 Parent Guarantors Non-Guarantor Eliminations Consolidated
          
Total revenues$188,390
 $77,108
 $—
 $—
 $265,498
          
Costs and expenses:         
Lease operating expenses16,019
 4,001
 —
 —
 20,020
Production taxes4,052
 1,367
 —
 —
 5,419
Midstream gathering and processing52,725
 16,647
 —
 —
 69,372
Depreciation, depletion, and amortization106,649
 1
 —
 —
 106,650
General and administrative13,956
 (892) 1
 —
 13,065
Accretion expense335
 121
 —
 —
 456
Acquisition expense(5) 38
 —
 —
 33
 193,731

21,283

1

—

215,015
          
(LOSS) INCOME FROM OPERATIONS(5,341)
55,825

(1)
—

50,483
          
OTHER (INCOME) EXPENSE:         
Interest expense27,914
 (784) —
 —
 27,130
Interest income(29) (8) —
 —
 (37)
(Income) loss from equity method investments and investments in subsidiaries(53,880) 128
 296
 56,193
 2,737
Other income(344) (1) —
 —
 (345)
 (26,339)
(665)
296

56,193

29,485
          
INCOME (LOSS) BEFORE INCOME TAXES20,998
 56,490
 (297) (56,193) 20,998
INCOME TAX EXPENSE2,763
 —
 —
 —
 2,763
          
NET INCOME (LOSS)$18,235

$56,490

$(297)
$(56,193)
$18,235


29
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  

31
 Three months ended September 30, 2016
 Parent Guarantors Non-Guarantor Eliminations Consolidated
          
Total revenues$193,227
 $465
 $—
 $—
 $193,692
          
Costs and expenses:         
Lease operating expenses17,283
 188
 —
 —
 17,471
Production taxes3,495
 30
 —
 —
 3,525
Midstream gathering and processing45,385
 90
 —
 —
 45,475
Depreciation, depletion, and amortization62,284
 1
 —
 —
 62,285
Impairment of oil and natural gas properties212,194
 —
 —
 —
 212,194
General and administrative10,772
 (305) —
 —
 10,467
Accretion expense269
 —
 —
 —
 269
 351,682
 4
 —
 —
 351,686
          
(LOSS) INCOME FROM OPERATIONS(158,455)
461

—

—

(157,994)
          
OTHER (INCOME) EXPENSE:         
Interest expense12,787
 —
 —
 —
 12,787
Interest income(337) —
 —
 —
 (337)
Insurance Proceeds(3,750) —
 —
 —
 (3,750)
(Income) loss from equity method investments and investments in subsidiaries(6,457) (99) 364
 195
 (5,997)
Other income5
 1
 

 

 6
 2,248
 (98) 364
 195
 2,709
          
(LOSS) INCOME BEFORE INCOME TAXES(160,703)
559

(364)
(195)
(160,703)
INCOME TAX BENEFIT(3,407) —
 —
 —
 (3,407)
          
NET (LOSS) INCOME$(157,296) $559
 $(364) $(195) $(157,296)


30
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) 

32
 Nine months ended September 30, 2017
 Parent Guarantors Non-Guarantor Eliminations Consolidated
          
Total revenues$710,184
 $212,271
 $—
 $—
 $922,455
          
Costs and expenses:         
Lease operating expenses49,891
 10,153
 —
 —
 60,044
Production taxes10,799
 3,665
 —
 —
 14,464
Midstream gathering and processing132,740
 43,518
 —
 —
 176,258
Depreciation, depletion, and amortization254,884
 3
 —
 —
 254,887
General and administrative39,882
 (1,963) 3
 —
 37,922
Accretion expense908
 240
 —
 —
 1,148
Acquisition expense—
 2,391
 —
 —
 2,391
 489,104
 58,007
 3
 —
 547,114
          
INCOME (LOSS) FROM OPERATIONS221,080
 154,264
 (3) —
 375,341
          
OTHER (INCOME) EXPENSE:         
Interest expense79,095
 (4,298) —
 —
 74,797
Interest income(913) (14) —
 —
 (927)
(Income) loss from equity method investments and investments in subsidiaries(136,969) 2,586
 869
 154,459
 20,945
Other (income) expense(1,522) (241) —
 900
 (863)
 (60,309) (1,967) 869
 155,359
 93,952
          
INCOME (LOSS) BEFORE INCOME TAXES281,389
 156,231
 (872) (155,359) 281,389
INCOME TAX EXPENSE2,763
 —
 —
 —
 2,763
          
NET INCOME (LOSS)$278,626
 $156,231
 $(872) $(155,359) $278,626


31
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  

33
 Nine months ended September 30, 2016
 Parent Guarantors Non-Guarantor Eliminations Consolidated
          
Total revenues$321,404
 $1,090
 $—
 $—
 $322,494
          
Costs and expenses:         
Lease operating expenses48,246
 543
 —
 —
 48,789
Production taxes9,410
 82
 —
 —
 9,492
Midstream gathering and processing122,250
 226
 —
 —
 122,476
Depreciation, depletion, and amortization183,411
 3
 

 

 183,414
Impairment of oil and natural gas properties601,806
 —
 —
 —
 601,806
General and administrative33,230
 (291) 2
 —
 32,941
Accretion expense777
 —
 —
 —
 777
 999,130
 563
 2
 —
 999,695
          
(LOSS) INCOME FROM OPERATIONS(677,726) 527
 (2) —
 (677,201)
          
OTHER (INCOME) EXPENSE:         
Interest expense44,891
 1
 —
 —
 44,892
Interest income(822) —
 —
 —
 (822)
Insurance Proceeds(3,750) —
 —
 —
 (3,750)
Loss (income) from equity method investments and investments in subsidiaries25,044
 (40) 24,812
 (24,240) 25,576
Other income5
 (8) —
 —
 (3)
 65,368
 (47) 24,812
 (24,240) 65,893
          
(LOSS) INCOME BEFORE INCOME TAXES(743,094) 574
 (24,814) 24,240
 (743,094)
INCOME TAX BENEFIT(3,755) —
 —
 —
 (3,755)
          
NET (LOSS) INCOME$(739,339) $574
 $(24,814) $24,240
 $(739,339)


32
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 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  

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) 

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  
34
 Three months ended September 30, 2017
 Parent Guarantors Non-Guarantor Eliminations Consolidated
          
Net income (loss)$18,235
 $56,490
 $(297) $(56,193) $18,235
Foreign currency translation adjustment6,832
 158
 6,674
 (6,832) 6,832
Other comprehensive income (loss)6,832
 158
 6,674
 (6,832) 6,832
Comprehensive income (loss)$25,067
 $56,648
 $6,377
 $(63,025) $25,067


 Three months ended September 30, 2016
 Parent Guarantors Non-Guarantor Eliminations Consolidated
          
Net (loss) income$(157,296) $559
 $(364) $(195) $(157,296)
Foreign currency translation adjustment(4,013) —
 (1,417) 1,417
 (4,013)
Other comprehensive (loss) income(4,013) —
 (1,417) 1,417
 (4,013)
Comprehensive (loss) income$(161,309) $559
 $(1,781) $1,222
 $(161,309)


 Nine months ended September 30, 2017
 Parent Guarantors Non-Guarantor Eliminations Consolidated
          
Net income (loss)$278,626
 $156,231
 $(872) $(155,359) $278,626
Foreign currency translation adjustment12,719
 232
 12,487
 (12,719) 12,719
Other comprehensive income (loss)12,719
 232
 12,487
 (12,719) 12,719
Comprehensive income (loss)$291,345
 $156,463
 $11,615
 $(168,078) $291,345


 Nine months ended September 30, 2016
 Parent Guarantors Non-Guarantor Eliminations Consolidated
  
Net (loss) income$(739,339) $574
 $(24,814) $24,240
 $(739,339)
Foreign currency translation adjustment4,361
 —
 8,252
 (8,252) 4,361
Other comprehensive income (loss)4,361
 —
 8,252
 (8,252) 4,361
Comprehensive (loss) income$(734,978) $574
 $(16,562) $15,988
 $(734,978)

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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  

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  
35
 Nine months ended September 30, 2017
 Parent Guarantors Non-Guarantor Eliminations Consolidated
          
Net cash provided by (used in) operating activities$310,624
 $181,108
 $(1) $2
 $491,733
          
Net cash (used in) provided by investing activities(1,849,554) (1,554,063) (1,843) 1,408,980
 (1,996,480)
          
Net cash provided by (used in) financing activities354,143
 1,407,137
 1,845
 (1,408,982) 354,143
          
Net (decrease) increase in cash and cash equivalents(1,184,787) 34,182
 1
 —
 (1,150,604)
          
Cash and cash equivalents at beginning of period1,273,882
 1,993
 —
 —
 1,275,875
          
Cash and cash equivalents at end of period$89,095
 $36,175
 $1
 $—
 $125,271


 Nine months ended September 30, 2016
 Parent Guarantors Non-Guarantor Eliminations Consolidated
          
Net cash provided by (used in) operating activities$244,758
 $517
 $3,998
 $(3,998) $245,275
          
Net cash (used in) provided by investing activities(420,257) (26,500) (18,510) 45,010
 (420,257)
          
Net cash provided by (used in) financing activities426,284
 26,500
 14,512
 (41,012) 426,284
          
Net increase in cash and cash equivalents250,785
 517
 —
 —
 251,302
          
Cash and cash equivalents at beginning of period112,494
 479
 1
 —
 112,974
          
Cash and cash equivalents at end of period$363,279
 $996
 $1
 $—
 $364,276


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16.SUBSEQUENT EVENTS
14.RECENT ACCOUNTING PRONOUNCEMENTS
In May 2014,Amendment to Credit Facility

On July 27, 2020, Gulfport entered into a Sixteenth Amendment to the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers, which supersedesAmended and Restated Credit Agreement. Among other changes, the revenue recognition requirementsSixteenth Amendment amends the Credit Agreement to: (i) require that, in Topic 605, Revenue Recognition, and most industry-specific guidance. The core principlethe event of the new standard is for the recognitionany issuances of revenue to depict the transfer of goods or services to customers in amounts that reflect the payment to which the company expects to be entitled in exchange for those goods or services. The new standard will also result in enhanced revenue disclosures, provide guidance for transactions that were not previously addressed comprehensively and improve guidance for multiple-element arrangements. The ASU is effective for annual periods beginningSenior Notes, including Second Lien Notes, after December 15, 2016, and interim periods within those years. The new standard permits retrospective application using either of the following methodologies: (i) restatement of each prior reporting period presented (full retrospective method) or (ii) recognition of a cumulative-effect adjustment as of the date of initial application (modified retrospective method). In July 2015, the FASB decided to defer the effective date, the then effective borrowing base will be reduced by one year (until 2018). The Company is evaluatinga variable amount prescribed in the impactCredit Agreement to the extent the proceeds are not used to satisfy previously issued senior notes within 90 days of this ASU on its consolidated financial statements and working to identify any potential differencessuch issuance; (ii) require that would result from applyingeach Loan Notice specify the requirementsamount of the ASUthen effective Borrowing Base and Pro Forma Borrowing Base, the Aggregate Elected Commitment Amount, and the current Total Outstandings, both with and without regard to existing contractsthe 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 current accounting policies and practices. This evaluation requires, among other things,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 reviewstated 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 contracts it has with customers within eachincurrence or issuance of the revenue streams identified within the Company's business, including natural gas sales, oil and condensate sales and natural gas liquid sales. The Company does not believe further disaggregation of revenue will be required under the new standard. Substantially all of the Company's revenueany Permitted Refinancing Notes (as such term is earned pursuant to agreements under which they have currently interpreted one performance obligation, which is satisfied at a point-in-time. As part of the evaluation work to-date, the Company has substantially completed its contract reviews and documentation. Due to industry-wide ongoing discussions on certain application issues, the Company cannot reasonably estimate the expected financial statement impact; however, it does not expect the impact of the application of the new standard to have a material impact on net income or cash flows based on the reviews performed to-date. The Company is currently assessing the requirements for additional disclosures and documentation of new policies, procedures, system, control and data requirements. The Company’s expectation is to adopt the standard on January 1, 2018, using the modified retrospective method. Based on the analysis to-date, the Company has not identified any material impact on their consolidated financial statements other than additional disclosures requirements.
In February 2016, the FASB issued ASU No. 2016-02, Leases. The guidance requires the lessee to recognize most leases on the balance sheet thereby resultingdefined in the recognitionCredit Agreement) not to exceed $750,000,000, subject to the terms of lease assetsan intercreditor agreement; and liability for those leases currently classified(vii) amend and restate the Applicable Rate Gridto provide as operating leases. The accounting for lessors is largely unchanged. The guidance is effective for periods after December 15, 2018, with early adoption permitted. The Company is in the process of evaluating the impact of this guidance on its consolidated financial statements and related disclosures; however, based on the Company’s current operating leases, it is not expected to have a material impact.follows:


In March 2016, the FASB issued ASU No. 2016-05, Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships. The guidance was issued to clarify that change in the counterparty to a derivative instrument that had been designated as the hedging instrument under Topic 815, does not require designation of that hedging relationship provided that all other hedge accounting criteria continue to be met. The Company adopted the standard as of January 1, 2017. There was no impact on the Company’s consolidated financial statements because all current derivative instruments are not designated for hedge accounting.
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%
In March 2016, the FASB issued ASU No. 2016-09, Improvements to Employee Share-Based Payment Accounting. This guidance was intended to simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The Company adopted the standard as of January 1, 2017. The Company has elected to recognize forfeitures of awards as they occur. The adoption of this standard did not have a material impact on the Company's consolidated financial statements.

In May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition and Derivatives and Hedging: Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting. This guidance rescinds SEC Staff Observer comments that are codified in Topic 606, Revenue from Contracts with Customers, and Topic 932, Extractive Activities--Oil and Gas. This amendment is effective upon adoption of Topic 606. The Company is in the process of evaluating the impact of this guidance on its consolidated financial statements.

In June 2016, 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 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 GAAP and instead, requires an entity to reflect its current estimate of all expected credit losses. The

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amendments 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 have the contractual right to receive cash. The Company is currently evaluating the impact this standard will have on its financial statements and related disclosures and does not anticipate it to have a material affect.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments. This ASU provides guidance of eight specific cash flow issues. This ASU is effective for periods after December 15, 2017, with early adoption permitted. The Company is in the process of evaluating the impact of this guidance on its consolidated financial statements.

In December 2016, the FASB issued ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers. This guidance updates narrow aspects of the guidance issued in Update 2014-09. This amendment is effective for periods after December 15, 2017, with early adoption permitted. The Company is in the process of evaluating the impact of this ASU on its consolidated financial statements.
In January 2017, the FASB issued ASU No. 2017-01, Clarifying the Definition of a Business. Under the current business combination guidance, there are three elements of a business: inputs, processes and outputs. The revised guidance adds an initial screen test to determine if substantially all of the fair value of the gross assets acquired is concentrated in a single asset or group of similar assets. If that screen is met, the set of assets is not a business. The new framework also specifies the minimum required inputs and processes necessary to be a business. This amendment is effective for periods after December 15, 2017, with early adoption permitted. The Company is in the process of evaluating the impact of this ASU on its consolidated financial statements.
15.SUBSEQUENT EVENTS
Derivatives
In October of 2017,August 2020, the Company entered into fixed price swaps for 2018 for approximately 1,500 Bbls of oil per day at a weighted average price of $52.05 per Bbl. The Company’snatural gas fixed price swap contracts are tied tofor the commodity prices on NYMEX WTI. The Company will receive the fixedfourth quarter of 2020 covering approximately 100,000 MMBtu of natural gas per day at an average swap price amount stated in the contract and pay to its counterparty the current market price as listed on NYMEX for oil.of $2.38 per MMBtu.
Senior Notes Offering
On October 11, 2017, the Company issued $450.0 million in aggregate principal amount of its 6.375% Senior Notes due 2026 (the “2026 Notes”) to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. 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. A portion of the net proceeds from the issuance of the 2026 Notes was used to repay all of the Company's outstanding borrowings under its secured revolving credit facility on October 11, 2017 and the balance will be used to fund the remaining anticipated outspend related to the Company's 2017 capital development plans.



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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.

Disclosure
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 or the Securities Act, and(the "Securities Act"), Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), and the 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 Exchange Act.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 intended to identify forward-looking 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 strength, goals, expansion and growth of our business and operations, plans, references to future success, reference 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 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; 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; our ability to identify, complete and integrate acquisitions of properties (including those recently acquired from Vitruvian II Woodford, LLC) and businesses; changes in laws or regulations; adverse weather conditions and natural disasters such as hurricanes and otherthe factors including those listed in theItem 1A. “Risk Factors” section ofin our most recent Annual Report on Form 10-K for the year ended December 31, 2019 and elsewhere in this Form 10-Q. All forward-looking statements speak only as of the date of this Form 10-Q.
All forward-looking statements, expressed or implied, included in this Quarterly ReportsReport 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-looking statements that we or persons acting on Form 10-Q orour behalf may issue.
Except as otherwise required by applicable law, we disclaim any other filings we make with the SEC, manyduty to update any forward-looking statements, all of which are beyond our control. Consequently, all ofexpressly qualified by the forward-looking statements made in this report are qualified by these cautionary statements,section, to reflect events or circumstances after the date of this Quarterly Report.

Investors should note that we announce financial information in SEC filings, press releases and we cannot assure youpublic conference calls. We may use the Investors section of our website (www.gulfportenergy.com) to communicate with investors. It is possible that the actual results or developments anticipated by us willfinancial and other information posted there could be realized or, even if realized, that they will have the expected consequencesdeemed to or effectsbe material information. The information on us, our business or operations. We have no intention, and disclaim any obligation, to update or revise any forward-looking statements, whether as a resultwebsite is not part of new information, future results or otherwise.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 ("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, 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.
We cannot predict the full impact that COVID-19 or the significant disruption and volatility currently being experienced in the oil and 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 this 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 cost structure in 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 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.
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.
2020 Operational and Financial 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 three and six months ended June 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 interests, we hold an acreage position alongthings, our future development program and future water production levels. Proceeds from the Louisiana Gulf Coast in the West Cote Blanche Bay, or WCBB,divestiture were used to reduce our outstanding revolver balance.


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2020 Production and Hackberry fields, an acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC, or Grizzly, and an approximate 25.1% equity interest in Mammoth Energy Services, Inc., or Mammoth Energy, an oil field services company listed on the Nasdaq Global Select Market (TUSK). We seek to achieve reserve growth and increase our cash flow through our annual drilling programs.
2017 Operational and Other HighlightsDrilling Activity
Production increased 63% to 110,367Volumes
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 million cubic feet of natural gas equivalent, orproduction averaged approximately 1,027.1 MMcfe forper day during the three months ended SeptemberJune 30, 2017 from 67,541 MMcfe for the three months ended September 30, 2016. Our net daily production mix for the third quarter of 2017 averaged 1,199.62020, 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 was comprisedSCOOP operating areas beginning in the third and fourth quarters of approximately 88% natural gas, 8% natural gas liquids, or NGLs, and 4% oil.
On February 17, 2017,2019. Additionally, in response to sharp declines in commodity prices resulting from COVID-19 uncertainties, beginning in March 2020, we throughchose to shut in a portion of our wholly-owned subsidiary Gulfport MidCon LLC, or Gulfport MidCon (formerly known as SCOOP Acquisition Company, LLC), completed our acquisition, which we refer to asoperated low margin, liquids-weighted production during the Acquisition,second quarter of certain assets from Vitruvian II Woodford, LLC, an unrelated third-party seller, for a total purchase price of approximately $1.85 billion,2020, largely consisting of $1.35 billionlegacy vertical production in cash, subjectthe 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 certain adjustments, and approximately 23.9 million shares of the Company’s common stock (of which approximately 5.2 million shares were

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)%
placedOur 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 an indemnity escrow).2019. The Acquisition included approximately 46,000 net surface acres with multiple producing zones, including21% decrease in production is largely the Woodfordresult of a decrease in development activities of our Utica Shale and Springer formationsSCOOP operating areas beginning in the South Central Oklahoma Oil Province, or SCOOP, resource play,third and fourth quarters of 2019. Additionally, in Grady, Stephens and Garvin Counties, Oklahoma.
On June 5, 2017,response to sharp declines in commodity prices resulting from COVID-19 uncertainties, beginning in March 2020, we acquired approximately 2.0 million shares of Mammoth Energy common stockchose to shut in connection with our contribution of alla portion of our membership interestsoperated low margin, liquids-weighted production during the second quarter of 2020, largely consisting of legacy vertical production in Sturgeon Acquisitions LLC, Stingray Energy Services LLCthe SCOOP. We also experienced shut ins across both the SCOOP and Stingray Cementing LLC, which we referUtica 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 as Sturgeon, Stingray Energy and Stingray Cementing, respectively, bringing our equity interest in Mammoth Energy to approximately 25.1%.production.
During the three months ended SeptemberUtica Shale. From January 1, 2020 through June 30, 2017,2020, we spud 2312 gross (23.0(11.1 net) wells in the Utica Shale, participatedof which one was being drilled and 11 were in anvarious stages of operations at June 30, 2020. In addition, we completed 22 gross and net operated wells. We did not participate in any additional four gross (1.3 net) wells that were drilled by other operators on our Utica Shale acreage and spud six gross and net wells and recompleted nine gross and net wells on our Louisiana acreage. In addition, during the three months ended September 30, 2017, seven gross (6.1 net) wells were spud in the SCOOP. We also participated in an additional three gross (0.03 net) wells that were drilled by other operators on our SCOOP acreage. Of the 36 new wells we spud, at September 30, 2017, 28 were in various stages of completion and eight were being drilled. In addition, 19 gross (17.9 net) operated wells and nine gross (2.1 net) non-operated wells were turned-to-sales in our Utica Shale operating area and six gross (5.6 net) operated wells and 12 gross (0.43 net) non-operated wells were turned-to-sales in our SCOOP operating area during the three months ended September 30, 2017.
During the nine months ended September 30, 2017, we reduced our unit lease operating expense by 16% to $0.21 per Mcfe from $0.26 per Mcfe during the nine months ended September 30, 2016.

During the nine months ended September 30, 2017, we decreased our unit general and administrative expense by 22% to $0.13 per Mcfe from $0.17 per Mcfe during the nine months ended September 30, 2016.
On October 11, 2017, we issued $450.0 million in aggregate principal amount of our 6.375% Senior Notes due 2026, or the 2026 Notes, to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. 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. A portion of the net proceeds from the issuance of the 2026 Notes was used to repay all of our outstanding borrowings under our secured revolving credit facility on October 11, 2017 and the balance will be used to fund the remaining anticipated outspend related to our 2017 capital development plans.




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2017 Production and Drilling Activity
During the three months ended September 30, 2017, our total net production was 97,824,927 cubic feet, or Mcf, of natural gas, 685,316 barrels of oil and 59,007,909 gallons of NGLs for a total of 110,367 MMcfe, as compared to 58,150,669 Mcf of natural gas, 521,356 barrels of oil and 43,837,087 gallons of NGLs, or 67,541 MMcfe, for the three months ended September 30, 2016. Our total net production averaged approximately 1,199.6 MMcfe per day during the three months ended September 30, 2017 as compared to 734.1 MMcfe per day during the same period in 2016. The 63% increase in production is largely the result of the continuing development of our Utica Shale acreage and production attributable to the Acquisition.
Utica Shale. As of November 1, 2017, we held leasehold interests in approximately 235,000 gross (213,000 net) acres in the Utica Shale. From January 1, 2017 through November 1, 2017, we spud 89 gross (84.1 net) wells, of which 16 were producing, 69 were in various stages of completion and four were being drilled at November 1, 2017. In addition, 16 gross (5.5 net) wells were drilled by other operators on our Utica Shale acreage during the nine months ended September 30, 2017.
As of November 1, 2017,July 31, 2020, we had fourone operated horizontal rigs under contract on our Utica Shale acreage. We currently intenddrilling rig running in the play and expect to spud 96 gross (91 net) horizontal wells, and commence sales from 68 gross (61 net) wells, on our Utica Shale acreage in 2017.continue with this level of activity through the third quarter of 2020.
Aggregate net production from our Utica Shale acreage during the three months ended SeptemberJune 30, 20172020 was approximately 90,82272,082 MMcfe, or an average of 987.2792.1 MMcfe per day, of which 94%98% was from natural gas and 6%2% was from oil and NGLs.NGL.
SCOOP. As of November 1, 2017, we held leasehold interests in approximately 50,400 net acres in the SCOOP. From January 1, 20172020 through November 1, 2017, 16June 30, 2020, we spud six gross (13.6(5.2 net) wells were spud,in the SCOOP, of which four wereone was being drilled and 12five were waiting on completionin various stages of operations at November 1, 2017.June 30, 2020. In addition, 25addition. we completed 4 gross (0.8(3.8 net) operated wells. We also participated in an additional five gross wells that were drilled by other operators on our SCOOP acreage during the period from February 17, 2017 to September 30, 2017.acreage.
As of November 1, 2017,July 31, 2020, we had four horizontal rigs under contract on our SCOOP acreage. We currently intendone operated drilling rig running in the play and expect to spud 22 gross (18 net) wells, and commence sales from 18 gross (16 net) wells, on our SCOOP acreage in 2017.continue with this level of activity for the remainder of 2020. 
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Aggregate net production from our SCOOP acreage during the three months ended SeptemberJune 30, 20172020 was approximately 17,88821,330 MMcfe, or an average of 194.4234.4 MMcfe per day, of which 70%68% was from natural gas and 30%32% was from oil and NGLs.NGL.
WCBB
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. From January 1, 2017 through November 1, 2017, we spud ten new wellsThis 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 recompleted 59 wells. Aggregate netprocessing expenses, a $6.7 million decrease in lease operating expenses and a $4.5 million decrease in production fromtaxes for the three months ended June 30, 2020 as compared to the three months ended June 30, 2019.
Natural Gas, Oil and NGL Sales
Three months ended June 30,
20202019change
($ 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  $287,854  (63)%
The decrease in natural gas sales without the impact of derivatives was due to a 49% decrease in realized natural gas prices and a 24%decrease in natural gas sales volumes.
The decrease in oil and condensate sales without the impact of derivatives was due to a 65% decrease in realized oil and condensate prices and a 36% decrease in oil and condensate sales volumes.
The decrease in NGL sales without the impact of derivatives was due to a 45% decreasein realized NGL prices and a 27% decrease in NGL sales volumes.
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Natural Gas, Oil and NGL Derivatives
Three months ended June 30,
20202019
($ 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  $171,140  
See Note 10 to our consolidated financial statements for further discussion of our derivative activity.
Natural Gas, Oil and NGL Production and Pricing
The following table summarizes our oil and condensate, natural gas and NGL production and related pricing for the three months ended June 30, 2020, as compared to such data for the three months ended June 30, 2019:
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 Three months ended June 30,
 20202019
($ 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  $0.18  (7)%
 _____________________
(1) Includes WCBB, fieldHackberry, Niobrara and Bakken.
The decrease in total lease operating expenses ("LOE") for the three months ended June 30, 2020 as compared to the three months ended June 30, 2019 was primarily the result of our 24% decrease in production and ongoing well optimization and cost initiatives. Per unit LOE was relatively flat for the three months ended June 30, 2020 as compared to the three months ended June 30, 2019.
Production Taxes
Three months ended June 30,
20202019change
($ 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  $0.58  10 %
The decrease in midstream gathering and processing expenses was primarily related to our 24% decrease in our production for the three months ended June 30, 2020 as compared to the three months ended June 30, 2019. The increase in per unit midstream gathering and processing expenses for the three months ended June 30, 2020 as compared to the three months ended June 30, 2019 is primarily related to Utica Shale production volumes falling below a minimum volume commitment and the resulting deficiency payments during the three months ended SeptemberJune 30, 20172020.
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Depreciation, Depletion and Amortization
Three months ended June 30,
20202019change
($ 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 approximately 1,255 MMcfe, or andue 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$532.9 million oil and natural gas properties impairment charge related primarily to the decline in the twelve month trailing first of month average price for natural gas, oil and NGL, compared to no impairment charge of 13.6 MMcfe per day, 98% of which was from oil.
East Hackberry Field. From January 1, 2017 through November 1, 2017, we spud five new wellsoil and recompleted 20 wells. Aggregate net production from the East Hackberry fieldgas properties during the three months ended SeptemberJune 30, 2017 was approximately 296 MMcfe, or2019.
Based on prices for the last nine months and the short-term pricing outlook for the third quarter of 2020, we expect to recognize an averageadditional full cost impairment in the third quarter of 3.2 MMcfe per day,2020. The amount of which 98% wasany future impairments is difficult to predict as it depends on changes in commodity prices, production rates, proved reserves, evaluation of costs excluded from oilamortization, future development costs and 2% wasproduction costs.
Equity Investments
Three months ended June 30,
20202019change
($ In thousands, except per unit)
Loss from equity method investments, net$45  $125,582  (100)%
The decrease in loss from natural gas.
West Hackberry Field. From January 1, 2017 through November 1, 2017, we did not spud any wells in our West Hackberry field. Aggregate net production from the West Hackberry fieldequity method investments is primarily related to a $125.4 million impairment charge recorded during the three months ended SeptemberJune 30, 20172019. As the value of our investment in Mammoth was approximately 19.7 MMcfe, or an averagereduced to zero during the first quarter of 214.5 Mcfe per day, all of which was from oil.
We currently intend to drill 15 gross and net wells and perform recompletion activities on our acreage in Southern Louisiana.
Niobrara Formation. As of September 30, 2017,2020, we held leases for approximately 4,000 net acres in the Niobrara Formation in Northwestern Colorado. From January 1, 2017 through November 1, 2017, there were no wells spud on our Niobrara Formation acreage. Aggregate net production was approximately 19.9 MMcfe, or an average of 216.5 Mcfe per daydid not record any similar impairment charges during the three months ended SeptemberJune 30, 2017, all2020. See Note 4 to our consolidated financial statements for further discussion on our equity investments.
General and Administrative Expenses
Three months ended June 30,
20202019change
($ 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  $0.09  22 %
The decrease in general and administrative expenses, gross was due primarily due to lower employee costs resulting from the reduction in workforce that was completed in the fourth quarter of which2019. Additionally, in June 2020, in response to the
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continued depressed commodity price environment, we announced several G&A initiatives to reduce our corporate cost structure. This decrease was from oil.partially offset by an increase in non-recurring legal and consulting expenses.
Bakken
Interest Expense
Three months ended June 30,
 20202019
($ 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 months ended June 30, 2019 was primarily due to repurchases of our senior notes in the second half of 2019 and the first half of 2020.
Income Taxes. We recorded no income tax expense for three months ended June 30, 2020 compared to income tax benefit of $179.3 million for the three months ended June 30, 2019. As of SeptemberJune 30, 2017,2020, we heldhad a federal net operating loss carryforward of approximately 778$1.5 billion, in addition to numerous temporary differences, which gave rise to a net acresdeferred 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 Bakken Formation of Western North Dakota and Eastern Montana with interests in 18 wells and overriding royalty interests in certain existing and future wells. Aggregatefull net production from this acreagedeferred tax asset. The tax benefit recorded during the three months ended SeptemberJune 30, 20172019 was approximately 64.5 MMcfe, ora 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 $297.2 million for the six months ended June 30, 2019. Included in the loss for the six months ended June 30, 2020 was a $1.1 billion 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, 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 $125.4 million impairment related to our investment in Mammoth Energy, a $100.6 million decrease in DD&A, a $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 $7.6 million decrease in production taxes for the six months ended June 30, 2020 as compared to the six months ended June 30, 2019.
Natural Gas, Oil and NGL Sales
Six months ended June 30,
20202019change
($ 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  $628,477  (60)%
The decrease in natural gas sales without the impact of derivatives was due to a 51% decrease in realized natural gas prices and a 20% decreasein natural gas sales volumes.
The decrease in oil and condensate sales without the impact of derivatives was due to an average40% decrease in realized oil and condensate prices and a 25% decrease in oil and condensate sales volumes.
The decrease in NGL sales without the impact of 701.4 Mcfe per day,derivatives was due to a 40% decrease in realized NGL prices and a 22% decrease in NGL sales volumes.
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Natural Gas, Oil and NGL Derivatives
Six months ended June 30,
20202019
($ 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  
See 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 15% was fromand condensate, natural gas and 7% was from NGLs.

NGL production and related pricing for the six months ended June 30, 2020, as compared to such data for the six months ended June 30, 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  

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Lease Operating Expenses
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  $0.18  (6)%
 _____________________
(1) Includes WCBB, Hackberry, Niobrara and Bakken.
The decrease in total LOE for the six months ended June 30, 2020 as compared to the six months ended June 30, 2019 was primarily the result of our 21% decrease in production. Per unit LOE was relatively flat for the six months ended June 30, 2020 as compared to the six months ended June 30, 2019.
Production Taxes
Six months ended June 30,
20202019change
($ In thousands, except per unit)
Production taxes$8,404  $16,019  (48)%
Production taxes per Mcfe$0.04  $0.07  (34)%
The decrease in production taxes was primarily related to a decrease in realized prices and production for the six months ended June 30, 2020.
Six months ended June 30,
20202019change
($ In thousands, except per unit)
Midstream gathering and processing expenses$117,870  $142,297  (17)%
Midstream gathering and processing expenses per Mcfe$0.62  $0.60  4 %
The decrease in midstream gathering and processing expenses was primarily related to our 21% decrease in our production for the six months ended June 30, 2020 as compared to the six months ended June 30, 2019. Per unit midstream gathering and processing expenses was relatively flat for the six months ended June 30, 2020 as compared to the six months ended June 30, 2019.
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Depreciation, Depletion and Amortization
Six months ended June 30,
20202019change
($ 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 consisted of $137.6 million in depletion of oil and natural gas properties and $5.2 million in depreciation of other property and equipment, compared to $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 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 2019 as well as a decrease in our production.
Impairment of Oil and Gas Properties. During the six months ended June 30, 2020, we incurred $1.1 billion of oil and natural gas properties impairment charges related primarily to the decline in the twelve month trailing first of month average price for natural gas, oil and NGL compared to no impairment charge of oil and gas properties during the six months ended June 30, 2019.
Equity Investments
Six months ended June 30,
20202019change
($ 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 $125.4 million impairment charge recorded during the six months ended June 30, 2019. The value of our investment in Mammoth was reduced to zero during the first quarter of 2020, and we did not record any similar impairment charges during the six months ended June 30, 2020. See Note 4 to our consolidated financial statements for further discussion on our equity investments.
General and Administrative Expenses
Six months ended June 30,
20202019change
($ 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  $0.09  53 %
The increase in general and administrative expenses, gross was due primarily due to an increase in non-recurring legal and consulting charges for the six months ended June 30, 2020 as compared to the six months ended June 30, 2019. This increase was partially offset by lower employee costs resulting from the reduction in workforce that was completed in the fourth quarter of 2019. Additionally, in June 2020, in response to the continued depressed commodity price environment, we announced several G&A initiatives to reduce our corporate cost structure. The decrease in capitalized general and administrative expenses was due to lower development activities for the six months ended June 30, 2020 as compared to the six months ended June 30, 2019.
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Interest Expense
Six months ended June 30,
 20202019
($ 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 expense for the six months ended June 30, 2020 as compared to the six months ended June 30, 2019 was primarily due to continued repurchases of our 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 June 30, 2020, we had a federal net operating loss carryforward of approximately $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. At June 30, 2020, a valuation allowance of $879.3 million has been maintained against the full net deferred tax asset. Income tax expense recorded during the six months ended 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 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.

Liquidity and Capital Resources
Overview. Historically, our primary sources of capital funding and liquidity have been our operating cash flow, borrowings under our revolving credit facility and issuances of equity and debt securities. Our ability to access 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 $324.1 million utilized for various letters of credit.  See Note 5 of the notes to our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our notes.
Derivatives and Hedging Activities. Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. Our natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to predict with greater certainty the total revenue we will receive.
As of June 30, 2020, we had the following open natural gas, oil and NGL derivative instruments:
Natural Gas Derivatives
YearType of Derivative InstrumentIndexDaily Volume (MMBtu/day)Weighted
Average Price ($)
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  
See Note 10 of the notes to our consolidated financial statements for further discussion of derivatives and hedging activities. Additionally, as discussed in Note 16, we brought forward the value of our oil swaps by monetizing our remaining position in April 2020 and entered into additional contracts to hedge our remaining 2020 and 2021 production in April and 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 June 30, 2020, we had a borrowing base and elected commitment of $700.0 million and $123.0 million in borrowings outstanding. Total funds available for borrowing under our revolving credit facility, after giving effect to an aggregate of $324.1 million of outstanding letters of credit, were $252.9 million as of June 30, 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.
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; undertake fundamental 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; enter into transactions with their 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 Secured Debt to EBITDAX (as defined under the revolving credit agreement) may not be greater than 2.00 to 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 the 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 June 30, 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.We used borrowings under our revolving credit facility to repurchase in the open market approximately $47.5 million and $73.3 million aggregate principal amount of our outstanding Notes for $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 $4.9 million principal amount of the 2023 Notes, $16.3 million principal amount of the 2024 Notes, $13.5 million principal amount of the 2025 Notes, and $12.8 million principal amount of the 2026 Notes. We recognized a $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, during the three and six months ended June 30, 2020, respectively.
Subject to restrictions in our own revolving credit facility, we may use a combination of cash and borrowing 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.

Capital Expenditures. Our capital commitments have been primarily for the execution of our drilling programs and discounted repurchases of our senior notes. Our capital investment strategy is focused on prudently developing our existing properties to generate sustainable cash flow considering current and forecasted commodity prices while also selectively pursuing mergers or acquisitions in our current operating regions in an effort to gain scale and deepen our drilling inventory.
Our capital expenditures for 2020 are currently estimated to be in the range of $265.0 million to $285.0 million for drilling and completion expenditures. In addition, we currently expect to spend $20.0 million to $25.0 million in 2020 for non-drilling and completion expenditures, which includes acreage expenses, primarily lease extensions in the Utica Shale. The midpoint of the 2020 range of capital expenditures is more than 50% lower than the $602.5 million spent in 2019, primarily due to our decision to reduce capital activity in response to lower commodity prices, specifically natural gas prices, and our desire to fund our capital development program primarily with cash flow from operations. As a result of our decreased capital spending program for 2020 and the impact of our 2019 property divestitures, we expect our production volumes in 2020 to 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 borrowing base availability under our revolving credit agreement will be sufficient to meet our normal recurring operating needs and capital requirements for the next twelve months. We have the ability to react quickly to changing commodity prices and accelerate or decelerate our activity within our operating areas as market conditions warrant. Notwithstanding the foregoing, in the event commodity prices decline from current levels or our capital or other costs increase we may be required to obtain additional funds which we would seek to do through 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 merger, acquisition and divestiture opportunities. Capital may not be available to us on acceptable terms or at 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.
Cash 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 Note 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 cash equivalents for the 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 Utica 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, 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, 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 June 30, 2020, our material off-balance sheet arrangements and transactions include $324.1 million in letters of credit outstanding against our revolving credit facility and $119.5 million in surety bonds issued. Both the letters of credit and surety bonds are being used as financial assurance, primarily on certain 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 9 to our consolidated financial statements for further discussion of the various financial guarantees we have issued.
Critical Accounting Policies and EstimatesRESULTS OF OPERATIONS
Our discussion and analysis of our financial condition and results of operations are based upon consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management. We analyze our estimates including those related to oil and natural gas properties, revenue recognition, income taxes and commitments and contingencies, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements:
Oil and Natural Gas Properties. We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including non-productive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book valueComparison of the oilThree Month Periods Ended June 30, 2020 and gas properties. Net capitalized costs are limited to the lower2019
We reported a net loss of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month price for the prior twelve months, adjusted for any contract provisions or financial derivatives, if any, that hedge our oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown is required. Such capitalized costs, including the estimated future development costs and site remediation costs of proved undeveloped properties are depleted by an equivalent units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one barrel of oil. No gain or loss is recognized upon the disposal of oil and natural gas properties, unless such dispositions significantly alter the relationship between capitalized costs and proven oil and natural gas reserves. Oil and natural gas properties not subject to amortization consist of the cost of undeveloped leaseholds and totaled approximately $3.0 billion at September 30, 2017 and $1.6 billion at December 31, 2016. These costs are reviewed quarterly by management for impairment, with the impairment provision included in the cost of oil and natural gas properties subject to amortization. Factors considered by management in its impairment assessment include our drilling results and those of other operators, the terms of oil and natural gas leases not held by production and available funds for exploration and development.
Ceiling Test. Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling (as defined in the preceding paragraph). If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown is required. Ceiling test impairment can give us a significant loss for a particular period; however, future depletion expense would be reduced. A decline in oil and gas prices may result in an impairment of oil and gas properties. For instance, as a result of the decline in commodity prices in 2015 and 2016 and subsequent reduction in our proved reserves, we recognized a ceiling test impairment of $715.5$561.1 million for the yearthree months ended December 31, 2016. At SeptemberJune 30, 2017, the calculated ceiling was greater than the2020 as compared to net book valueincome of our oil and natural gas properties, thus no ceiling test impairment was required$235.0 million for the ninethree months ended SeptemberJune 30, 2017. If prices of oil, natural gas and natural gas liquids decline2019. Included in the future, we may be required to further write downloss for the valuethree months ended June 30, 2020 was a $532.9 million non-cash impairment of our oil and natural gas properties, which could negatively affect our resultsprimarily resulted from a significant decrease in the trailing twelve month first of operations.
Asset Retirement Obligations. We have obligations to remove equipment and restore land at the endmonth 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 $4.5 million decrease in production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells and associated production facilities.
We accounttaxes for abandonment and restoration liabilities under FASB ASC 410 which requires us to record a liability equalthe three months ended June 30, 2020 as compared to the fair valuethree months ended June 30, 2019.
Natural Gas, Oil and NGL Sales
Three months ended June 30,
20202019change
($ 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 estimated costimpact of derivatives was due to retire an asset. a 65% decrease in realized oil and condensate prices and a 36% decrease in oil and condensate sales volumes.
The asset retirement liability is recordeddecrease in NGL sales without the period impact of derivatives was due to a 45% decreasein which the obligation meets the definition ofrealized NGL prices and a liability, which is generally when the asset is placed into service. When the liability is initially recorded, we increase the carrying amount of the related long-lived asset by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related

27% decrease in NGL sales volumes.
40
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Natural Gas, Oil and NGL Derivatives
long-lived asset. Upon settlement
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  $171,140  
See Note 10 to our consolidated financial statements for further discussion of the liability or the sale of the well, the liability is reversed. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements.our derivative activity.
Natural Gas, Oil and NGL Production and Pricing
The fair valuefollowing table summarizes our oil and condensate, natural gas and NGL production and related pricing for the three months ended June 30, 2020, as compared to such data for the three months ended June 30, 2019:
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 Three months ended June 30,
 20202019
($ 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  $0.18  (7)%
 _____________________
(1) Includes WCBB, Hackberry, Niobrara and Bakken.
The decrease in total lease operating expenses ("LOE") for the liability associated with these retirement obligations is determined using significant assumptions, including current estimates of the plugging and abandonment or retirement, annual inflation of these costs, the productive life of the asset and our risk adjusted cost to settle such obligations discounted using our credit adjusted risk free interest rate. Changes in any of these assumptions can result in significant revisionsthree months ended June 30, 2020 as compared to the estimated asset retirement obligation. Revisionsthree months ended June 30, 2019 was primarily the result of our 24% decrease in production and ongoing well optimization and cost initiatives. Per unit LOE was relatively flat for the three months ended June 30, 2020 as compared to the asset retirement obligation are recorded with an offsetting changethree months ended June 30, 2019.
Production Taxes
Three months ended June 30,
20202019change
($ In thousands, except per unit)
Production taxes$3,605  $8,098  (55)%
Production taxes per Mcfe$0.04  $0.07  (41)%
The decrease in production taxes was primarily related to a decrease in realized prices and production for the three months ended June 30, 2020 as compared to the carrying amountthree months ended June 30, 2019.
Midstream Gathering and Processing Expenses
Three months ended June 30,
20202019change
($ 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 is primarily related to Utica Shale production volumes falling below a minimum volume commitment and the resulting deficiency payments during the three months ended June 30, 2020.
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Table of the related long-lived asset, resulting in prospective changes to depreciation,Contents

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 and accretionconsisted of discount. Because of the subjectivity of assumptions and the relatively long life of most of our oil and natural gas assets, the costs to ultimately retire these assets may vary significantly from previous estimates.
Oil and Gas Reserve Quantities. Our estimate of proved reserves is based on the quantities$62.2 million in depletion of oil and natural gas that engineeringproperties and geological analysis demonstrate, with reasonable certainty,$2.6 million in depreciation of other property and equipment, compared to be recoverable from established reservoirs$122.5 million in the future under current operating and economic parameters. Netherland, Sewell & Associates, Inc. and to a lesser extent our personnel have prepared reserve reports of our reserve estimates at December 31, 2016 on a well-by-well basis for our properties.
Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Our reserve estimates and the projected cash flows derived from these reserve estimates have been prepared in accordance with the guidelines of the Securities and Exchange Commission, or SEC. The accuracy of our reserve estimates is a function of many factors including the following:
the quality and quantity of available data;
the interpretation of that data;
the accuracy of various mandated economic assumptions; and
the judgments of the individuals preparing the estimates.
Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. Therefore, reserve estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered.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$532.9 million oil and natural gas properties impairment charge related primarily to the decline in the twelve month trailing first of month average price for natural gas, oil and NGL, compared to no impairment charge of oil and gas properties during the three months ended June 30, 2019.
Based on prices for the last nine months and the short-term pricing outlook for the third quarter of 2020, we expect to recognize an additional full cost impairment in the third quarter of 2020. The amount of any future impairments is difficult to predict as it depends on changes in commodity prices, production rates, proved reserves, evaluation of costs excluded from amortization, future development costs and production costs.
Equity Investments
Three months ended June 30,
20202019change
($ In thousands, except per unit)
Loss from equity method investments, net$45  $125,582  (100)%
The decrease in loss from equity method investments is primarily related to a $125.4 million impairment charge recorded during the three months ended June 30, 2019. As the value of our investment in Mammoth was reduced to zero during the first quarter of 2020, we did not record any similar impairment charges during the three months ended June 30, 2020. See Note 4 to our consolidated financial statements for further discussion on our equity investments.
General and Administrative Expenses
Three months ended June 30,
20202019change
($ 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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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 months ended June 30, 2019 was primarily due to repurchases of our senior notes in the second half of 2019 and the first half of 2020.
Income Taxes. We userecorded no income tax expense for three months ended June 30, 2020 compared to income tax benefit of $179.3 million for the asset and liability methodthree months ended June 30, 2019. As of accounting for income taxes, underJune 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 assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized in the year in which realization becomes determinable. Periodically,asset. Quarterly, management performs a forecast of itsour 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 SeptemberJune 30, 2017,2020, a valuation allowance of $548.4$879.3 million hadhas been providedmaintained against the full net deferred tax asset, withasset. The tax benefit recorded during the exceptionthree months ended June 30, 2019 was a result of certainmanagement's determination there was sufficient positive evidence that it was more likely than not that the federal and some state net operating losses, or NOL,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 alternative minimum tax, or AMT, credits that we expect2019
We reported net loss of $1.1 billion for the six months ended June 30, 2020 as compared to be able to utilize with NOL carrybacks and tax planningnet income of $297.2 million for the six months ended June 30, 2019. Included in the amountloss for the six months ended June 30, 2020 was a $1.1 billion non-cash impairment of $4.7 million.
Revenue Recognition. We derive almost all of our revenue from the sale of crude oil and natural gas produced from our oil and natural gas properties. Revenue is recordedproperties 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 product is deliveredmain 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 $125.4 million impairment related to our investment in Mammoth Energy, a $100.6 million decrease in DD&A, a $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 $7.6 million decrease in production taxes for the six months ended June 30, 2020 as compared to the purchaser.six months ended June 30, 2019.
Natural Gas, Oil and NGL Sales
Six months ended June 30,
20202019change
($ 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  $628,477  (60)%
The decrease in natural gas sales without the impact of derivatives was due to a 51% decrease in realized natural gas prices and a 20% decreasein natural gas sales volumes.
The decrease in oil and condensate sales without the impact of derivatives was due to an 40% decrease in realized oil and condensate prices and a 25% decrease in oil and condensate sales volumes.
The decrease in NGL sales without the impact of derivatives was due to a 40% decrease in realized NGL prices and a 22% decrease in NGL sales volumes.
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Natural Gas, Oil and NGL Derivatives
Six months ended June 30,
20202019
($ 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  $151,095  
See Note 10 to our consolidated financial statements for further discussion of our derivative activity.
Natural Gas, Oil and NGL Production and Pricing
The following table summarizes our oil and condensate, natural gas and NGL production and related pricing for the six months ended June 30, 2020, as compared to such data for the six months ended June 30, 2019:
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 Six months ended June 30,
 20202019
($ 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  

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Lease Operating Expenses
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  $0.18  (6)%
 _____________________
(1) Includes WCBB, Hackberry, Niobrara and Bakken.
The decrease in total LOE for the six months ended June 30, 2020 as compared to the six months ended June 30, 2019 was primarily the result of our 21% decrease in production. Per unit LOE was relatively flat for the six months ended June 30, 2020 as compared to the six months ended June 30, 2019.
Production Taxes
Six months ended June 30,
20202019change
($ In thousands, except per unit)
Production taxes$8,404  $16,019  (48)%
Production taxes per Mcfe$0.04  $0.07  (34)%
The decrease in production taxes was primarily related to a decrease in realized prices and production for the six months ended June 30, 2020.
Six months ended June 30,
20202019change
($ In thousands, except per unit)
Midstream gathering and processing expenses$117,870  $142,297  (17)%
Midstream gathering and processing expenses per Mcfe$0.62  $0.60  4 %
The decrease in midstream gathering and processing expenses was primarily related to our 21% decrease in our production for the six months ended June 30, 2020 as compared to the six months ended June 30, 2019. Per unit midstream gathering and processing expenses was relatively flat for the six months ended June 30, 2020 as compared to the six months ended June 30, 2019.
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Depreciation, Depletion and Amortization
Six months ended June 30,
20202019change
($ 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 consisted of $137.6 million in depletion of oil and natural gas properties and $5.2 million in depreciation of other property and equipment, compared to $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 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 2019 as well as a decrease in our production.
Impairment of Oil and Gas Properties. During the six months ended June 30, 2020, we incurred $1.1 billion of oil and natural gas properties impairment charges related primarily to the decline in the twelve month trailing first of month average price for natural gas, oil and NGL compared to no impairment charge of oil and gas properties during the six months ended June 30, 2019.
Equity Investments
Six months ended June 30,
20202019change
($ 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 $125.4 million impairment charge recorded during the six months ended June 30, 2019. The value of our investment in Mammoth was reduced to zero during the first quarter of 2020, and we did not record any similar impairment charges during the six months ended June 30, 2020. See Note 4 to our consolidated financial statements for further discussion on our equity investments.
General and Administrative Expenses
Six months ended June 30,
20202019change
($ 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  $0.09  53 %
The increase in general and administrative expenses, gross was due primarily due to an increase in non-recurring legal and consulting charges for the six months ended June 30, 2020 as compared to the six months ended June 30, 2019. This increase was partially offset by lower employee costs resulting from the reduction in workforce that was completed in the fourth quarter of 2019. Additionally, in June 2020, in response to the continued depressed commodity price environment, we announced several G&A initiatives to reduce our corporate cost structure. The decrease in capitalized general and administrative expenses was due to lower development activities for the six months ended June 30, 2020 as compared to the six months ended June 30, 2019.
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Interest Expense
Six months ended June 30,
 20202019
($ 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 expense for the six months ended June 30, 2020 as compared to the six months ended June 30, 2019 was primarily due to continued repurchases of our senior notes.
Income Taxes. We receive paymentrecorded 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 June 30, 2020, we had a federal net operating loss carryforward of approximately $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. At June 30, 2020, a valuation allowance of $879.3 million has been maintained against the full net deferred tax asset. Income tax expense recorded during the six months ended 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 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.

Liquidity and Capital Resources
Overview. Historically, our primary sources of capital funding and liquidity have been our operating cash flow, borrowings under our revolving credit facility and issuances of equity and debt securities. Our ability to access 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 $324.1 million utilized for various letters of credit.  See Note 5 of the notes to our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our notes.
Derivatives and Hedging Activities. Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. Our natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to predict with greater certainty the total revenue we will receive.
As of June 30, 2020, we had the following open natural gas, oil and NGL derivative instruments:
Natural Gas Derivatives
YearType of Derivative InstrumentIndexDaily Volume (MMBtu/day)Weighted
Average Price ($)
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  
See Note 10 of the notes to our consolidated financial statements for further discussion of derivatives and hedging activities. Additionally, as discussed in Note 16, we brought forward the value of our oil swaps by monetizing our remaining position in April 2020 and entered into additional contracts to hedge our remaining 2020 and 2021 production in April and 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 June 30, 2020, we had a borrowing base and elected commitment of $700.0 million and $123.0 million in borrowings outstanding. Total funds available for borrowing under our revolving credit facility, after giving effect to an aggregate of $324.1 million of outstanding letters of credit, were $252.9 million as of June 30, 2020. This facility is secured by substantially all of theseour 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.
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; undertake fundamental changes including selling all or substantially all of our assets; enter into swap contracts and forward sales from onecontracts; dispose of assets; change the nature of their business; enter into transactions with their affiliates; and engage in certain transactions with restricted subsidiaries. The negative covenants are subject to three months after delivery. Atcertain 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 Secured Debt to EBITDAX (as defined under the revolving credit agreement) may not be greater than 2.00 to 1.00 for the
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twelve-month period of the end of each month, we estimatefiscal quarter; and (2) the amountratio of production deliveredEBITDAX to purchasers that month andinterest expense for the price we will receive. Variances between our estimated revenue and actual payment received for all prior months are recordedtwelve-month period at the end of theeach fiscal quarter after payment is received. Historically, our actual payments havemay not significantly deviated from our accruals.

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Investments—Equity Method. Investments in entities greater than 20% andbe less than 50% and/or investments3.00 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 whichcompliance with these financial covenants at June 30, 2020.
On July 27, 2020, we have significant influence are accounted forentered 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.We used borrowings under the equity method. Under the equity method, our share of investees’ earnings or loss is recognizedrevolving credit facility to repurchase in the statementopen market approximately $47.5 million and $73.3 million aggregate principal amount of operations.
We review our investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, we recognize an impairment provision.outstanding Notes for $12.6 million and $22.8 million during the three and six months ended June 30, 2020, respectively. For the three months ended March 31, 2016,June 30, 2020, this included approximately $4.9 million principal amount of the 2023 Notes, $16.3 million principal amount of the 2024 Notes, $13.5 million principal amount of the 2025 Notes, and $12.8 million principal amount of the 2026 Notes. We recognized a $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, during the three and six months ended June 30, 2020, respectively.
Subject to restrictions in our own revolving credit facility, we recognizedmay use a combination of cash and borrowing 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.

Capital Expenditures. Our capital commitments have been primarily for the execution of our drilling programs and discounted repurchases of our senior notes. Our capital investment strategy is focused on prudently developing our existing properties to generate sustainable cash flow considering current and forecasted commodity prices while also selectively pursuing mergers or acquisitions in our current operating regions in an impairment loss relatedeffort to gain scale and deepen our drilling inventory.
Our capital expenditures for 2020 are currently estimated to be in the range of $265.0 million to $285.0 million for drilling and completion expenditures. In addition, we currently expect to spend $20.0 million to $25.0 million in 2020 for non-drilling and completion expenditures, which includes acreage expenses, primarily lease extensions in the Utica Shale. The midpoint of the 2020 range of capital expenditures is more than 50% lower than the $602.5 million spent in 2019, primarily due to our investmentdecision to reduce capital activity in Grizzlyresponse to lower commodity prices, specifically natural gas prices, and our desire to fund our capital development program primarily with cash flow from operations. As a result of approximately $23.1 million.
Commitments and Contingencies. Liabilitiesour decreased capital spending program for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred2020 and the amount canimpact of our 2019 property divestitures, we expect our production volumes in 2020 to be reasonably estimated. 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 involved in certain litigationprepared to adjust our drilling program if commodity prices dictate. Currently, we believe that our cash flow from operations, cash on hand and borrowing base availability under our revolving credit agreement will be sufficient to meet our normal recurring operating needs and capital requirements for which the outcome is uncertain. Changes in the certainty andnext twelve months. We have the ability to reasonably estimate a loss amount, if any, may resultreact quickly to changing commodity prices and accelerate or decelerate our activity within our operating areas as market conditions warrant. Notwithstanding the foregoing, in the recognitionevent commodity prices decline from current levels or our capital or other costs increase we may be required to obtain additional funds which we would seek to do through borrowings, offerings of debt or equity securities or other means, including the sale of assets. To the extent that access to capital and subsequent paymentother financial markets is adversely affected by the effects of legal liabilities.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 merger, acquisition and divestiture opportunities. Capital may not be available to us on acceptable terms or at 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.
Derivative InstrumentsCash 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 Hedging Activities. We seekreceived $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 exposureoutstanding revolver balance. See Note 3 of the notes to unfavorable changes in oil, natural gasour consolidated financial statements for further discussion.
Use of Funds. The following table presents the uses of our cash and natural gas liquids prices, which are subject to significantcash equivalents for the six months ended June 30, 2020 and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps2019:
 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 various types of option contracts. We follow the provisions of FASB ASC 815, “DerivativesCompletion Costs. During six months ended June 30, 2020, we spud 12 gross (11.1 net) and Hedging,” as amended. It requires that all derivative instruments be recognized as assets or liabilitiescommenced sales from 13 gross and net operated wells in the balance sheet, measured at fair value. 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 Utica 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, 2020.
Contractual and Commercial Obligations
We estimatehave various contractual obligations in the fair valuenormal course of all derivative instruments using industry-standard models that considered various assumptions including current marketour 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 pricesobligations from those disclosed in our Annual Report on Form 10-K for the underlying instruments, implied volatility, time valueyear ended December 31, 2019. 
Off-balance Sheet Arrangements
We may enter into off-balance sheet arrangements and nonperformance risk,transactions that can give rise to material off-balance sheet obligations.  As of June 30, 2020, our material off-balance sheet arrangements and transactions include $324.1 million in letters of credit outstanding against our revolving credit facility and $119.5 million in surety bonds issued. Both the letters of credit and surety bonds are being used as well asfinancial assurance, primarily on certain firm transportation agreements. Management believes these items will expire without being funded. There are no other relevant economic measures.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
The accounting
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resources. See Note 9 to our consolidated financial statements for changes in the fair value of a derivative depends on the intended usefurther discussion of the derivative and the resulting designation. Whilevarious financial guarantees we have historically designated derivative instruments as accounting hedges, effective January 1, 2015, we discontinued hedge accounting prospectively. Our current commodity derivative instruments are not designated as hedges for accounting purposes. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities.issued.
See Item 3. “Quantitative and Qualitative Disclosures About Market Risk” for a summary of our derivative instruments in place as of September 30, 2017.
RESULTS OF OPERATIONS
Comparison of the Three MonthsMonth Periods Ended SeptemberJune 30, 20172020 and 20162019
We reported a net incomeloss of $18.2$561.1 million for the three months ended SeptemberJune 30, 20172020 as compared to a net lossincome of $157.3$235.0 million for the three months ended SeptemberJune 30, 2016. This $175.52019. Included in the loss for the three months ended June 30, 2020 was a $532.9 million period-to-period increase was duenon-cash impairment of our oil and natural gas properties, which primarily toresulted from a $71.8 million increasesignificant decrease in the trailing twelve month first of month prices of natural gas, oil and NGL, revenues and no impairment chargewas 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 three months ended September 30, 2017 as compared tosecond quarter of 2020, resulting in a $212.2$182.4 million impairment ofdecrease in natural gas, oil and NGL sales and a $144.2 million decrease in gain on natural gas, properties for the three months ended September 30, 2016,oil and NGL derivatives. This increase in loss is partially offset by a $23.9$125.5 million increasedecrease 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, an $8.7a $6.7 million increase in loss from equity method investments, net, a $14.3 million increase in interest expense and a $2.5 million increasedecrease in lease operating expenses and a $4.5 million decrease in production taxes for the three months ended SeptemberJune 30, 20172020 as compared to the three months ended SeptemberJune 30, 2016.2019.
Natural Gas, Oil and Gas Revenues. For the three months ended September 30, 2017, we reported natural gas, oil and NGL revenues of $265.5 million as compared to oil and natural gas revenues of $193.7 million during the same period in 2016. This $71.8 million, or 37%, increase in revenues was primarily attributable to the following:Sales
A $58.1 million
Three months ended June 30,
20202019change
($ 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, oil and NGL sales due to an unfavorable change in gains and losses from derivative instruments. Of the total change, $59.3 million was due to unfavorable changes in the fair value of our open derivative positions in each period, offset by a $1.2 million favorable change in settlements related to our derivative positions.

A $101.3 million increase in natural gas sales without the impact of derivatives duewas due to an 8% increasea 49% decrease in realized natural gas market prices and a 68% increase24%decrease in naturalnatural gas sales volumes.

A $9.6 million increaseThe decrease in oil and condensate sales without the impact of derivatives was due to a 9% increase65% decrease in realized oil and condensate market prices and a 31% increase36% decrease in oil and condensate sales volumes.


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A $19.0 million increaseThe decrease in natural gas liquidsNGL sales without the impact of derivatives was due to a 73% increase 45% decreasein natural gas liquids marketrealized NGL prices and a 35% increase27% decrease in natural gas liquidsNGL sales volumes.

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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 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 SeptemberJune 30, 2017,2020, as compared to such data for the three months ended SeptemberJune 30, 2016:

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  $0.83  
45
 Three months ended September 30,
 2017 2016
 ($ In thousands)
Natural gas sales   
Natural gas production volumes (MMcf)97,825
 58,151
    
Total natural gas sales$223,340
 $122,018
    
Natural gas sales without the impact of derivatives ($/Mcf)$2.28
 $2.10
Impact from settled derivatives ($/Mcf)$0.13
 $0.21
Average natural gas sales price, including settled derivatives ($/Mcf)$2.41
 $2.31
    
Oil and condensate sales   
Oil and condensate production volumes (MBbls)685
 521
    
Total oil and condensate sales$31,459
 $21,799
    
Oil and condensate sales without the impact of derivatives ($/Bbl)$45.90
 $41.81
Impact from settled derivatives ($/Bbl)$4.36
 $1.62
Average oil and condensate sales price, including settled derivatives ($/Bbl)$50.26
 $43.43
    
Natural gas liquids sales   
Natural gas liquids production volumes (MGal)59,008
 43,837
    
Total natural gas liquids sales$33,559
 $14,594
    
Natural gas liquids sales without the impact of derivatives ($/Gal)$0.57
 $0.33
Impact from settled derivatives ($/Gal)$(0.03) $—
Average natural gas liquids sales price, including settled derivatives ($/Gal)$0.54
 $0.33
    
Natural gas, oil and condensate and natural gas liquids sales   
Gas equivalents (MMcfe)110,367
 67,541
    
Total natural gas, oil and condensate and natural gas liquids sales$288,358

$158,411
    
Natural gas, oil and condensate and natural gas liquids sales without the impact of derivatives ($/Mcfe)$2.61
 $2.35
Impact from settled derivatives ($/Mcfe)$0.13
 $0.19
Average natural gas, oil and condensate and natural gas liquids sales price, including settled derivatives ($/Mcfe)$2.74
 $2.54
    
Production Costs:   
Average production costs (per Mcfe)$0.18
 $0.26
Average production taxes and midstream costs (per Mcfe)$0.68
 $0.73
Total production and midstream costs and production taxes (per Mcfe)$0.86
 $0.99


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Lease Operating Expenses. Lease
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 or LOE, not including production taxes increased to $20.0 million("LOE") for the three months ended SeptemberJune 30, 2017 from $17.5 million for the three months ended September 30, 2016. This $2.5 million increase was primarily the result of an increase in expenses related to ad valorem taxes, location and facility repairs and maintenance, supervision and labor expenses, chemicals, surface rentals and water hauling, partially offset by a decrease in water disposal and workover expenses. However, due to increased efficiencies and a 63% increase in our production volumes for the three months ended September 30, 20172020 as compared to the three months ended SeptemberJune 30, 2016,2019 was primarily the result of our per24% decrease in production and ongoing well optimization and cost initiatives. Per unit LOE decreased by 30% from $0.26 per Mcfe to $0.18 per Mcfe.

Production Taxes. Production taxes increased $1.9 million to $5.4 millionwas relatively flat for the three months ended SeptemberJune 30, 2017 from $3.5 million2020 as compared to the three months ended June 30, 2019.
Production Taxes
Three months ended June 30,
20202019change
($ In thousands, except per unit)
Production taxes$3,605  $8,098  (55)%
Production taxes per Mcfe$0.04  $0.07  (41)%
The decrease in production taxes was primarily related to a decrease in realized prices and production for the three months ended SeptemberJune 30, 2016. This increase was related2020 as compared to an increase in realized prices and production volumes.the three months ended June 30, 2019.
Midstream Gathering and Processing Expenses. Midstream
Three months ended June 30,
20202019change
($ 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 increased $23.9 millionwas primarily related to $69.4 millionour 24% decrease in our production for the three months ended SeptemberJune 30, 2017 from $45.5 million for2020 as compared to the same periodthree months ended June 30, 2019. The increase in 2016. This increase was primarily attributable toper unit midstream expenses related to our increased production volumes in the Utica Shale resulting from our 2016gathering and 2017 drilling activities, as well as production volumes resulting from our recent SCOOP acquisition.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization, or DD&A, expense increased to $106.7 millionprocessing expenses for the three months ended SeptemberJune 30, 2017,2020 as compared to the three months ended June 30, 2019 is primarily related to Utica Shale production volumes falling below a minimum volume commitment and the resulting deficiency payments during the three months ended June 30, 2020.
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Depreciation, Depletion and Amortization
Three months ended June 30,
20202019change
($ 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 $105.1$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 $1.6$2.5 million in depreciation of other property and equipment as compared to total DD&A expense of $62.3 million for the three months ended SeptemberJune 30, 2016. This increase2019. The decrease in DD&A was due to an increaseboth a decrease in our full cost pooldepletion rate as a result of our SCOOP acquisition and an increasea decrease in our production, partially offset by an increaseamortization base from full cost ceiling test impairments recorded during 2019 and the first quarter of 2020, as well as a decrease in our total proved reserves volume used to calculate our total DD&A expense.production.
GeneralImpairment of Oil and Administrative Expenses. Net general and administrative expenses increased to $13.1 million forGas Properties. During the three months ended SeptemberJune 30, 2017 from $10.52020, we incurred a$532.9 million for the three months ended September 30, 2016. This $2.6 million increase was due to increases in salariesoil and benefits, consulting fees and bank service charges, partially offset by a decrease in employee stock compensation expense and legal fees. However, during the three months ended September 30, 2017, we decreased our unit general and administrative expense by 24% to $0.12 per Mcfe from $0.15 per Mcfe during the three months ended September 30, 2016.
Accretion Expense. Accretion expense remained relatively flat at $0.5 million and $0.3 million for the three months ended September 30, 2017 and 2016, respectively.
Interest Expense. Interest expense increased to $27.1 million for the three months ended September 30, 2017 from $12.8 million for the three months ended September 30, 2016 duenatural gas properties impairment charge related primarily to the issuancedecline in the twelve month trailing first of $600.0 million in aggregate principal amount of our 6.375% Senior Notes due 2025, or the 2025 Notes, in December 2016. In addition, total weightedmonth average debt outstanding under our revolving credit facility was $273.7 millionprice for the three months ended September 30, 2017 asnatural gas, oil and NGL, compared to no debt outstanding under such facility for the same period in 2016. Asimpairment charge of September 30, 2017, amounts borrowed under our revolving credit facility bore interest at the Eurodollar rate of 3.74%. In addition, we capitalized approximately $2.1 million and $4.7 million in interest expense to undeveloped oil and natural gas properties during the three months ended SeptemberJune 30, 20172019.
Based on prices for the last nine months and 2016, respectively.the short-term pricing outlook for the third quarter of 2020, we expect to recognize an additional full cost impairment in the third quarter of 2020. The amount of any future impairments is difficult to predict as it depends on changes in commodity prices, production rates, proved reserves, evaluation of costs excluded from amortization, future development costs and production costs.
Equity Investments
Three months ended June 30,
20202019change
($ In thousands, except per unit)
Loss from equity method investments, net$45  $125,582  (100)%
The decrease in loss from equity method investments is primarily related to a $125.4 million impairment charge recorded during the three months ended June 30, 2019. As the value of our investment in Mammoth was reduced to zero during the first quarter of 2020, we did not record any similar impairment charges during the three months ended June 30, 2020. See Note 4 to our consolidated financial statements for further discussion on our equity investments.
General and Administrative Expenses
Three months ended June 30,
20202019change
($ 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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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 capitalizednon-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 inexpense for three months ended June 30, 2020 as compared to the 2017 periodthree months ended June 30, 2019 was primarily due to a decrease inrepurchases of our average undeveloped leasehold costssenior notes in the Utica, partially offset bysecond half of 2019 and the SCOOP Acquisition.first half of 2020.
Income Taxes. We recorded no income tax expense for three months ended June 30, 2020 compared to income tax benefit of $179.3 million for the three months ended June 30, 2019. As of SeptemberJune 30, 2017,2020, we had a federal net operating loss carryforward of approximately $606.5 million,$1.5 billion, in addition to numerous temporary differences, which gave rise to a net deferred tax asset. Periodically,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 SeptemberJune 30, 2017,2020, a valuation allowance of $548.4$879.3 million hadhas been providedmaintained against the full net deferred tax asset, withasset. The tax benefit recorded during the exceptionthree months ended June 30, 2019 was a result of certainmanagement'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, and AMT credits that we expect to be ableoffset potential future income taxes for federal income tax purposes. See Note 14 of the notes to utilize with NOL carrybacks and tax planning in the amountour consolidated financial statements for more information.


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Comparison of the Nine MonthsSix Month Periods Ended SeptemberJune 30, 20172020 and 20162019
We reported net loss of $1.1 billion for the six months ended June 30, 2020 as compared to net income of $278.6$297.2 million for the ninesix months ended SeptemberJune 30, 2017 as compared to a net2019. Included in the loss of $739.3 million for the ninesix months ended SeptemberJune 30, 2016. This $1.02020 was a $1.1 billion period-to-period increasenon-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 due primarily tothe 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 $600.0$374.4 million increasedecrease in natural gas, oil and NGL revenuessales and no impairment charge for the nine months ended September 30, 2017 as compareda $25.9 million decrease in gain on natural gas, oil and NGL derivatives. The remaining variance related to a $601.8$4.9 million impairment of oilincrease in general and natural gas properties for the nine months ended

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September 30, 2016,administrative expenses, partially offset by a $53.8$110.5 million increasedecrease in loss from equity method investments, including a $125.4 million impairment related to our investment in Mammoth Energy, a $100.6 million decrease in DD&A, a $49.6 million gain on debt extinguishment, a $24.4 million decrease in midstream gathering and processing expenses, a $29.9$10.5 million increase in interest expense and an $11.3 million increasedecrease in lease operating expenses and a $7.6 million decrease in production taxes for the ninesix months ended SeptemberJune 30, 20172020 as compared to the ninesix months ended SeptemberJune 30, 2016.2019.
Natural Gas, Oil and Gas Revenues. For the nine months ended September 30, 2017, we reported oil and natural gas revenues of $922.5 million as compared to oil and natural gas revenues of $322.5 million during the same period in 2016. This $600.0 million, or 186%, increase in revenues was primarily attributable to the following:NGL Sales
A $186.0 million increase in natural gas, oil and NGL sales due to a favorable change in gains and losses from derivative instruments. Of the total change, $313.7 million was due to favorable changes in the fair value of our open derivative positions in each period, offset by $127.7 million unfavorable change in settlements related to our derivative positions.
Six months ended June 30,
20202019change
($ 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)%

A $334.7 million increaseThe decrease in natural gas sales without the impact of derivatives was due to a 48% increase 51% decrease in realized natural gas market prices and a 50% increase 20% decreasein natural gas sales volumes.

A $24.5 million increaseThe decrease in oil and condensate sales without the impact of derivatives was due to a 27% increasean 40% decrease in realized oil and condensate market prices and a 10% increase25% decrease in oil and condensate sales volumes.

A $54.8 million increaseThe decrease in natural gas liquidNGL sales without the impact of derivatives was due to a 90% increase40% decrease in natural gas liquids marketrealized NGL prices and a 39% increase22% decrease in natural gas liquidsNGL sales volumes.


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Natural Gas, Oil and NGL Derivatives
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  $151,095  
See Note 10 to our consolidated financial statements for further discussion of our derivative activity.
Natural Gas, Oil and NGL Production and Pricing
The following table summarizes our oil and condensate, natural gas and NGL production and related pricing for the ninesix months ended SeptemberJune 30, 2017,2020, as compared to such data for the ninesix months ended SeptemberJune 30, 2016:
 Nine months ended September 30,
 2017 2016
 ($ In thousands)
Natural gas sales   
Natural gas production volumes (MMcf)247,012
 164,233
    
Total natural gas sales$606,544
 $271,873
    
Natural gas sales without the impact of derivatives ($/Mcf)$2.46
 $1.66
Impact from settled derivatives ($/Mcf)$0.03
 $0.78
Average natural gas sales price, including settled derivatives ($/Mcf)$2.49
 $2.44
    
Oil and condensate sales   
Oil and condensate production volumes (MBbls)1,849
 1,675
    
Total oil and condensate sales$85,338
 $60,799
    
Oil and condensate sales without the impact of derivatives ($/Bbl)$46.15
 $36.31
Impact from settled derivatives ($/Bbl)$2.92
 $6.42
Average oil and condensate sales price, including settled derivatives ($/Bbl)$49.07
 $42.73
    
Natural gas liquids sales   
Natural gas liquids production volumes (MGal)162,483
 117,217
    
Total natural gas liquids sales$88,985
 $34,198
    
Natural gas liquids sales without the impact of derivatives ($/Gal)$0.55
 $0.29
Impact from settled derivatives ($/Gal)$(0.01) $—
Average natural gas liquids sales price, including settled derivatives ($/Gal)$0.54
 $0.29
    
Natural gas, oil and condensate and natural gas liquids sales   
Gas equivalents (MMcfe)281,318
 191,026
    
Total natural gas, oil and condensate and natural gas liquids sales$780,867
 $366,870
    
Natural gas, oil and condensate and natural gas liquids sales without the impact of derivatives ($/Mcfe)$2.78
 $1.92
Impact from settled derivatives ($/Mcfe)$0.04
 $0.73
Average natural gas, oil and condensate and natural gas liquids sales price, including settled derivatives ($/Mcfe)$2.82
 $2.65
    
Production Costs:   
Average production costs (per Mcfe)$0.21
 $0.26
Average production taxes and midstream costs (per Mcfe)$0.68
 $0.69
Total production and midstream costs and production taxes (per Mcfe)$0.89
 $0.95


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  

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Lease Operating Expenses. Lease operating expenses, or
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 not including production taxes increased to $60.0 million for the ninesix months ended SeptemberJune 30, 2017 from $48.8 million for the nine months ended September 30, 2016. This increase was mainly the result of an increase in expenses related to supervision and labor, overhead, compressors, surface rentals, water hauling and treatment, chemicals, workover costs and road, location and equipment repairs and maintenance, partially offset by a decrease in ad valorem taxes and disposal costs. However, due to increased efficiencies and a 47% increase in our production volumes for the nine months ended September 30, 20172020 as compared to the ninesix months ended SeptemberJune 30, 2016,2019 was primarily the result of our per21% decrease in production. Per unit LOE decreased by 16% from $0.26 per Mcfe to $0.21 per Mcfe.
Production Taxes. Production taxes increased $4.9 million to $14.5 millionwas relatively flat for the ninesix months ended SeptemberJune 30, 2017 from $9.5 million for2020 as compared to the same periodsix months ended June 30, 2019.
Production Taxes
Six months ended June 30,
20202019change
($ In thousands, except per unit)
Production taxes$8,404  $16,019  (48)%
Production taxes per Mcfe$0.04  $0.07  (34)%
The decrease in 2016. This increaseproduction taxes was primarily related to an increasea decrease in realized prices and production volumes.for the six months ended June 30, 2020.
Midstream Gathering and Processing Expenses. Midstream
Six months ended June 30,
20202019change
($ 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 midstream gathering and processing expenses increased by $53.8 million to $176.3 million for the nine months ended September 30, 2017 from $122.5 million for the same period in 2016. This increase was primarily attributable to midstream expenses related to our increased21% decrease in our production volumes infor the Utica Shale resulting from our 2016six months ended June 30, 2020 as compared to the six months ended June 30, 2019. Per unit midstream gathering and 2017 drilling activities,processing expenses was relatively flat for the six months ended June 30, 2020 as well as production volumes resulting from our recent SCOOP acquisition.compared to the six months ended June 30, 2019.
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Depreciation, Depletion and Amortization.
Six months ended June 30,
20202019change
($ 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 or ("DD&A,&A") expense increased to $254.9 million for the nine months ended September 30, 2017, and consisted of $250.5$137.6 million in depletion of oil and natural gas properties and $4.4$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 expensewas due to both a decrease in our depletion rate as a result of $183.4 million fora decrease in our amortization base from full cost ceiling test impairments recorded during 2019 and the ninefirst quarter of 2019 as well as a decrease in our production.
Impairment of Oil and Gas Properties. During the six months ended SeptemberJune 30, 2016. This2020, we incurred $1.1 billion of oil and natural gas properties impairment charges related primarily to the decline in the twelve month trailing first of month average price for natural gas, oil and NGL compared to no impairment charge of oil and gas properties during the six months ended June 30, 2019.
Equity Investments
Six months ended June 30,
20202019change
($ 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 $125.4 million impairment charge recorded during the six months ended June 30, 2019. The value of our investment in Mammoth was reduced to zero during the first quarter of 2020, and we did not record any similar impairment charges during the six months ended June 30, 2020. See Note 4 to our consolidated financial statements for further discussion on our equity investments.
General and Administrative Expenses
Six months ended June 30,
20202019change
($ 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 our full cost poolnon-recurring legal and consulting charges for the six months ended June 30, 2020 as a result of our SCOOP acquisition and ancompared to the six months ended June 30, 2019. This increase in our production,was partially offset by an increaselower 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 total proved reserves volume used to calculate our total DD&A expense.
General and Administrative Expenses. Netcorporate cost structure. The decrease in capitalized general and administrative expenses increased to $37.9 million for the nine months ended September 30, 2017 from $32.9 million for the nine months ended September 30, 2016. This $5.0 million increase was due to increases in salaries and benefits, consulting fees, bank service charges, computer support and franchise taxes, partially offset by a decrease in employee stock compensation expense and legal fees. However, duringlower development activities for the ninesix months ended SeptemberJune 30, 2017, we decreased our unit general and administrative expense by 22% to $0.13 per Mcfe from $0.17 per Mcfe during the nine months ended September 30, 2016.
Accretion Expense. Accretion expense was $1.1 million and $0.8 million for the nine months ended September 30, 2017 and 2016, respectively.
Interest Expense. Interest expense increased to $74.8 million for the nine months ended September 30, 2017 from $44.9 million for the nine months ended September 30, 2016 due primarily to the issuance of $600.0 million of the 2025 Notes in December 2016. In addition, total weighted average debt outstanding under our revolving credit facility was $146.0 million for the nine months ended September 30, 20172020 as compared to no debt outstanding under such facility for the same period in 2016. Additionally, we capitalized approximately $8.8 million and $7.7 millionsix months ended June 30, 2019.
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Interest Expense
Six months ended June 30,
 20202019
($ 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 expense to undeveloped oil and natural gas properties duringfor the ninesix months ended SeptemberJune 30, 2017 and September2020 as compared to the six months ended June 30, 2016, respectively. This increase in capitalized interest in the 2017 period2019 was primarily due to the SCOOP Acquisition.continued repurchases of our 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, 2017,2020, we had a federal net operating loss carryforward of approximately $606.5 million,$1.5 billion from prior years, in addition to numerous temporary differences, which gave rise to a net deferred tax asset. Periodically,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 SeptemberJune 30, 2017,2020, a valuation allowance of $548.4$879.3 million hadhas been providedmaintained against the full net deferred tax asset. Income tax expense recorded during the six months ended June 30, 2020 is related to the recognition of a valuation allowance against a state deferred tax asset withduring the exceptionfirst quarter of certain2020. The tax benefit recorded during the six 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 NOLs and AMT credits that we expect tonet operating loss carryforwards would be able to utilize with NOL carrybacks and tax planning in the amount of $4.7 million.realized.

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 prices or oil and natural gas production.

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Net cash flow provided by operating activities was $491.7 million for the nine months ended September 30, 2017 as compared to net cash flow provided by operating activities of $245.3 million for the same period in 2016. This increase was primarily thea result of an increasethe COVID-19 pandemic and the accompanying decrease in cash receipts fromcommodity prices has significantly reduced our oilability to access capital markets and natural gas purchasers due to a 57% increase in net revenues after giving effectrefinance our existing indebtedness. Further, these conditions have made amendments or waivers to settled derivative instruments, partially offset by an increase in our operating expenses.
Net cash used in investing activities forrevolving credit facility more difficult to obtain and available on terms less favorable to us. If depressed commodity prices persist or decline further, the nine months ended September 30, 2017 was $2.0 billion as compared to $420.3 million for the same period in 2016. During the nine months ended September 30, 2017, we spent $789.7 million in additions to oil and natural gas properties, of which $528.2 million was spent on our 2017 drilling, completion and recompletion activities, $86.3 million was spent on expenses attributable to wells spud, completed and recompleted during 2016, $1.9 million was spent on facility enhancements, $96.5 million was spent on lease related costs, primarily the acquisition of leases in the Utica Shale and $7.2 million was spent on seismic, with the remainder attributable mainly to future location development and capitalized general and administrative expenses. We also spent $1.3 billion to fund the cash portion of the purchase price for our SCOOP acquisition. In addition, $1.8 million was invested in Grizzly and $39.4 million was invested in Strike Force, net of distributions, during the nine months ended September 30, 2017. We did not make any investments in our other equity investments during the nine months ended September 30, 2017.
Net cash provided by financing activities for the nine months ended September 30, 2017 was $354.1 million as compared to $426.3 million for the same period in 2016. The 2017 amount provided by financing activities is primarily attributable to borrowingsborrowing 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. The 2016 amount provided by financing activitiesAs a result of these uncertainties and other factors, management has concluded that there is primarily attributablesubstantial 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 proceedsworking capital deficit of approximately $411.7$176.2 million fromas 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 March 2016 equity offering.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 $324.1 million utilized for various letters of credit.  See Note 5 of the notes to our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our notes.
Derivatives and Hedging Activities. Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. Our natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to predict with greater certainty the total revenue we will receive.
As of June 30, 2020, we had the following open natural gas, oil and NGL derivative instruments:
Natural Gas Derivatives
YearType of Derivative InstrumentIndexDaily Volume (MMBtu/day)Weighted
Average Price ($)
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  
See Note 10 of the notes to our consolidated financial statements for further discussion of derivatives and hedging activities. Additionally, as discussed in Note 16, we brought forward the value of our oil swaps by monetizing our remaining position in April 2020 and entered into additional contracts to hedge our remaining 2020 and 2021 production in April and 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 certain lenders from time to time party thereto.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, 2017,2020, we had a borrowing base and elected commitment of $1.0 billion$700.0 million and $365.0$123.0 million in borrowings outstanding, and totaloutstanding. Total funds available for borrowing under our revolving credit facility, after giving effect to an aggregate of $237.5$324.1 million of outstanding letters of credit, were $397.5 million.$252.9 million as of June 30, 2020. This facility is secured by substantially all of our assets. Our wholly-ownedwholly owned subsidiaries, excluding Grizzly Holdings Inc. ("Grizzly Holdings") and Mule Sky LLC ("Mule Sky"), guarantee our obligations under our revolving credit facility.
In connection with our fall redetermination under our revolving credit facility, the lead lenders have proposed to increase our borrowing base from $1.0 million to $1.2 billion, with an elected commitment of $1.0 billion, and decrease the interest rate by 50 basis points, subject to the approval of the additional banks within the syndicate.
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 1.00% to 2.00%, 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 2.00% to 3.00%, 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. As of September 30, 2017, amounts borrowed under our revolving credit facility bore interest at the Eurodollar rate of 3.74%.
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

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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, 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, 2017.2020.
Senior Notes.
In October 2012, December 2012On July 27, 2020, we entered into the sixteenth amendment to the Amended and August 2014, we issued an aggregate of $600.0Restated Credit Agreement. The sixteenth amendment allows us to issue up to $750 million in principal amount ofsecond lien debt subject to certain conditions.
Senior Notes.We used borrowings under our 7.75% Senior Notes due 2020 which were issued under an indenture among us, our subsidiary guarantorsrevolving credit facility to repurchase in the open market approximately $47.5 million and Wells Fargo Bank, National Association, as the trustee, and are referred to collectively as the 2020 Notes. In October 2016, we repurchased (in a cash tender offer) or redeemed all of the 2020 Notes, of which $600.0$73.3 million in aggregate principal amount was then outstanding, with the net proceeds from the issuance of our 6.000% Senior Notes due 2024, which are discussed below and are referred to herein as the 2024 Notes, and cash on hand, and the indenture governing the 2020 Notes was fully satisfied and discharged.
In April 2015, we issued an aggregate of $350.0 million in principal amount of our 6.625% Senior Notes due 2023. Interest on these senior notes, which we refer to as the 2023 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 the 2024 Notes in aggregate principal amount of $650.0 million. 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. We received approximately $638.9 million in net proceeds from the offering of the 2024 Notes, which was used, together with cash on hand, to purchase the outstanding 2020 Notes in a concurrent cash tender offer, to pay fees and expenses thereof, and to redeem any of the 2020 Notes that remained outstanding after the completion of the tender offer.
On December 21, 2016, we issued $600.0 million in aggregate principal amount of 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. We received approximately $584.7 million in net proceeds from the offering of the 2025 Notes, which we used, together with the net proceeds from our December 2016 offering of common stock and cash on hand, to fund the cash portion of the purchase price for the SCOOP acquisition.
In connection with the issuance of the 2024 Notes and the 2025 Notes, we and our subsidiary guarantors entered into two registration rights agreements, pursuant to which we agreed to file a registration statement with respect to offers to exchange the 2024 Notes and the 2025 Notes for new issues of substantially identical debt securities registered under the Securities Act. The exchange offers for the 2024 Notes and the 2025 Notes were completed on September 13, 2017.
On October 11, 2017, we issued $450.0 million in aggregate principal amount of our 2026 Notes. Interest onoutstanding Notes for $12.6 million and $22.8 million during the 2026 Notes accrues at a rate of 6.375% per annum onthree and six months ended June 30, 2020, respectively. For the outstandingthree months ended June 30, 2020, this included approximately $4.9 million 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. A portion of the net proceeds from2023 Notes, $16.3 million principal amount of the issuance2024 Notes, $13.5 million principal amount of the 2025 Notes, and $12.8 million principal amount of the 2026 Notes was usedNotes. We recognized a $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, during the three and six months ended June 30, 2020, respectively.
Subject to repay all ofrestrictions in our outstanding borrowings under our securedown revolving credit facility, on October 11, 2017we may use a combination of cash and the balance will be used to fund the remaining anticipated outspend related toborrowing under our 2017 capital development plans.
All of our existing and future restricted subsidiaries that guarantee our secured revolving credit facility or certain otherto retire our outstanding debt, guarantee the 2023 Notes, 2024 Notes and 2025 Notes; provided, however, that the 2023 Notes, 2024 Notes and 2025 Notes are not guaranteed by Grizzly Holdings, Inc. 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 2023 Notes, 2024 Notes and 2025 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 ofthrough privately negotiated transactions, open market repurchases,

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the collateral securing such indebtedness, and structurally subordinated to all indebtedness and other liabilities of any of our subsidiaries that do not guarantee the 2023 Notes, 2024 Notes and 2025 Notes.
If we experience a change of control (as defined in the senior note indentures relating to the 2023 Notes, 2024 Notes and 2025 Notes), we will be required to make an offer to repurchase the 2023 Notes, 2024 Notes and 2025 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 2023 Notes, 2024 Notes and 2025 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 2023 Notes, 2024 Notes and 2025 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, sellredemptions, tender offers 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 indenture relatingbut we are under no obligation to the 2023 Notes, 2024 Notes and 2025 Notes, certain of these covenants are subject to termination upon the occurrence of certain events, including in the event the 2023 Notes, 2024 Notes and 2025 Notes are ranked as “investment grade.”do so.
Construction Loan.
On June 4, 2015, we entered into a construction loan agreement, or 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 was payable on the last day of the month through May 31, 2017. Monthly interest and principal payments are due beginning June 30, 2017, with the final payment due June 4, 2025. As of September 30, 2017, the total borrowings under the construction loan were approximately $23.8 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 recent SCOOP acquisition, 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, workover, sidetrack and recompletion projects to exploitfocused on prudently developing our existing properties subject to economicgenerate sustainable cash flow considering current and industry conditions, (2) pursue acquisitionforecasted commodity prices while also selectively pursuing mergers or acquisitions in our current operating regions in an effort to gain scale and disposition opportunities and (3) pursue business integration opportunities.deepen our drilling inventory.
Of our net reserves at December 31, 2016, 63.0% were categorized as proved undeveloped. Our proved reserves will generally decline as reservescapital expenditures for 2020 are depleted, exceptcurrently estimated 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.
From January 1, 2017 through November 1, 2017, we spud 89 gross (84.1 net) wellsbe in the Utica Shale. We currently expectrange of $265.0 million to spud 96 gross (91 net) horizontal wells and commence sales from 68 gross (61 net) wells on our Utica Shale acreage during 2017. As of November 1, 2017, we had four operated horizontal rigs drilling in the play. We also anticipate an additional 24 gross (eight net) horizontal wells will be drilled, and sales commenced from 45 gross (nine net) horizontal wells, on our Utica Shale acreage by other operators during 2017. We currently anticipate our 2017 capital expenditures to be approximately $735.0$285.0 million related to our operated and non-operated Utica Shalefor drilling and completion activity.
From January 1, 2017 through November 1, 2017, 16 gross (13.6 net) wells were spud in the SCOOP. We currently anticipate our 2017 capital expenditures to be approximately $215.0 million related to our operated and non-operated SCOOP drilling and completion activity. We currently expect to spud 22 gross (18 net) wells and commence sales from 18 gross (16 net) wells on the SCOOP acreage during 2017. As of November 1, 2017, we had four operated horizontal rigs drilling in the play. We also anticipate 30 gross (one net) wells will be drilled, and sales commenced from 11 gross (one net) wells on this SCOOP acreage by other operators during 2017.
expenditures. In addition, we currently expect to spend an aggregate of approximately $130.0$20.0 million to $25.0 million in 20172020 for non-drilling and completion expenditures, which includes acreage expenses, primarily lease extensions in the Utica Shale and SCOOP.

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From January 1, 2017 through November 1, 2017, we spud ten new wells and recompleted 59 existing wells at our WCBB field. In our Hackberry fields, from January 1, 2017 through November 1, 2017, we spud five new wells and recompleted 20 existing wells. We currently expect to spend approximately $35.0 million in 2017 to drill 15 gross and net wells and perform recompletion activities in Southern Louisiana.
From January 1, 2017 through November 1, 2017, no new wells were spud on our Niobrara Formation acreage. We do not currently anticipate any capital expenditures in the Niobrara Formation in 2017.
As of September 30, 2017, our net investment in Grizzly was approximately $58.7 million. We do not currently anticipate any material capital expenditures in 2017 related to Grizzly’s activities.
We had no capital expenditures during the nine months ended September 30, 2017 related to our interests in Thailand. We do not currently anticipate any capital expenditures in Thailand in 2017.
In an effort to facilitate the development of our Utica Shale and other domestic acreage, we have invested in entities that can provide services that are required to support our operations. See Note 3 to our consolidated financial statements included elsewhere in this report for additional information regarding these other investments. During the nine months ended September 30, 2017, we paid $39.4 million in net cash calls related to Strike Force. We currently anticipate that we will make approximately $45.0 million in cash contributions to Strike Force in 2017. We did not make any investments in any other of these entities during the nine months ended September 30, 2017, and we do not currently anticipate any capital expenditures related to these entities in 2017.
During 2015 and 2016, we continued to focus on operational efficiencies in an effort to reduce our overall well costs and deliver better results in a more economical manner, particularly in lightShale. The midpoint of the continued downturn in commodity prices. We have successfully leveraged the lower commodity price environment to gain access to higher-quality equipment and superior services for reduced costs, which has contributed to increased productivity. We have also renegotiated the contracts for our horizontal drilling rigs and locked in approximately 85% of our currently anticipated Utica Shale drilling and completion costs for 2017. This has allowed us to secure a base level of activity for 2017, hedge against expected increases in service costs and ensure access to quality equipment and experienced crews, all of which we expect to contribute to further efficiency gains.
In 2017, we focused our leasehold efforts on adding acreage organically within units scheduled in our near-term development plan. This strategy has allowed us to focus our leasehold spend on the highest return potential for deployed capital, resulting in the acquisition of additional core acreage in the dry gas window of the Utica play. These efforts, coupled with our active leasehold trading efforts, have led to a significant increase in our working interests on wells spud in the Utica Shale during 2017, equating to an incremental 22.0 net wells spud, thereby resulting in an increase in our anticipated capital expenditures this year.
Our total capital expenditures for 2017 are currently estimated to be $985.0 million for drilling and completion expenditures, of which $846.0 million was spent as of September 30, 2017. In addition, we currently expect to spend approximately $130.0 million in 2017 for acreage expenses, primarily lease extensions in the Utica Shale, of which $98.0 million was spent as of September 30, 2017, and approximately $45.0 million to fund our investment in Strike Force, of which $39.4 million was spent as of September 30, 2017. Approximately 75% and 22% of our 2017 estimated drilling and completion capital expenditures are currently expected to be spent in the Utica Shale and in the SCOOP play in Oklahoma, respectively. The 20172020 range of capital expenditures is highermore than 50% lower than the $549.5$602.5 million spent in 2016,2019, primarily due to the increaseour decision to reduce capital activity in currentresponse to lower commodity prices, specifically natural gas prices, and our expansion intodesire to fund our capital development program primarily with cash flow from operations. As a result of our decreased capital spending program for 2020 and exploratory activitiesthe impact of our 2019 property divestitures, we expect our production volumes in the SCOOP play2020 to 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 Oklahoma.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 loan agreementsrevolving credit agreement 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 our Utica Basin and Mid-Continent operating areas or to scale back our activity, 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 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

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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. “Quantitative and Qualitative Disclosures about Market Risk” for information regarding our open fixed price swaps at September 30, 2017.
Commitments
In connection with our acquisition in 1997Note 3 of the remaining 50% interestnotes to our consolidated financial statements for further discussion.
Use of Funds. The following table presents the uses of our cash and cash equivalents for the 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 WCBB properties,Utica Shale for a total cost of approximately $141.5 million. During the six months ended June 30, 2020, we assumedspud six gross (5.2 net) and commenced sales from four gross (3.8 net) operated wells in the seller’s (Chevron) obligationSCOOP 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 contribute approximately $18,000 per month through March 2004,sales by other operators on our Utica Shale acreage. In addition, 5.00 gross (0.03 net) wells were spud and 5.00 gross (3.5 net) wells were turned to a plugging and abandonment trust andsales by other operators on our SCOOP acreage during the obligation to plug a minimum of 20 wells per year for 20 years commencing March 11, 1997. Chevron retained a security interest in production from these properties until our abandonment obligations to Chevron have been fulfilled. Beginning in 2009, we can access the trust for use in plugging and abandonment charges associated with the property. As of Septembersix months ended June 30, 2017, the plugging and abandonment trust totaled approximately $3.1 million. At September 30, 2017, we have plugged 551 wells at WCBB since we began our plugging program in 1997, which management believes fulfills our minimum plugging obligation.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, 2016.    2019. 
Off-balance Sheet Arrangements
We had nomay enter into off-balance sheet arrangements as of September 30, 2017.
New Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers, which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The core principle of the new standard is for the recognition of revenue to depict the transfer of goods or services to customers in amounts that reflect the payment to which we expect to be entitled in exchange for those goods or services. The new standard will also result in enhanced revenue disclosures, provide guidance for transactions that were not previously addressed comprehensivelycan give rise to material off-balance sheet obligations.  As of June 30, 2020, our material off-balance sheet arrangements and improve guidance for multiple-element arrangements. The ASU is effective for annual periods beginning after December 15, 2016,transactions include $324.1 million in letters of credit outstanding against our revolving credit facility and interim periods within those years. The new standard permits retrospective application using either$119.5 million in surety bonds issued. Both the letters of the following methodologies: (i) restatementcredit and surety bonds are being used as financial assurance, primarily on certain 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 each prior reporting period presented (full retrospective method) or (ii) recognitionour capital
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resources. See Note 9 to defer the effective date by one year (until 2018). We are evaluating the impact of this ASU on our consolidated financial statements and working to identify any potential differences that would result from applying the requirementsfor further discussion of the ASU to existing contractsvarious financial guarantees we have issued.
Critical Accounting Policies and currentEstimates
As of June 30, 2020, there have been no significant changes in our critical accounting policies and practices. This evaluation requires, among other things, a review of the contracts we have with customers within each of three revenue streams identified withinfrom those disclosed in our business. including natural gas sales, oil and condensate sales and natural gas liquid sales. We do not believe further disaggregation of revenue will be required under the new standard. Substantially all of our revenue is earned pursuant to agreements under which we have currently interpreted one performance obligation, which is satisfied at a point-in-time. As part of the evaluation work to-date, we have substantially completed our contract reviews and documentation. Due to industry-wide ongoing discussions2019 Annual Report on certain application issues, we cannot reasonably estimate the expected financial statement impact; however, we do not expect the impact of the application of the new standard to be material on net income or cash flows based on the reviews performed to-date. We are currently assessing the requirements of additional disclosures and documentation of new policies, procedures, system, control and data requirements. Our expectation is to adopt the standard on January 1, 2018, using the modified retrospective method. Based on the analysis to-date, we have not identified any material impact on our consolidated financial statements other than additional disclosures requirements.
In February 2016, the FASB issued ASU No. 2016-02, Leases. The guidance requires the lessee to recognize most leases on the balance sheet thereby resulting in the recognition of lease assets and liability for those leases currently classified as operating leases. The accounting for lessors is largely unchanged. The guidance is effective for periods after December 15,

Form 10-K.
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2018, with early adoption permitted. We are in the process of evaluating the impact of this guidance on our consolidated financial statements and related disclosures; however, based on our current operating leases, it is not expected to have a material impact.

In March 2016, the FASB issued ASU No. 2016-05, Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships. The guidance was issued to clarify that change in the counterparty to a derivative instrument that had been designated as the hedging instrument under Topic 815, does not require designation of that hedging relationship provided that all other hedge accounting criteria continue to be met. We adopted the standard as of January 1, 2017. There was no impact on our consolidated financial statements because all current derivative instruments are not designated for hedge accounting.
In March 2016, the FASB issued ASU No. 2016-09, Improvements to Employee Share-Based Payment Accounting. This guidance was intended to simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. We adopted the standard as of January 1, 2017. We elected to recognize forfeitures of awards as they occur. The adoption of this standard did not have a material impact on our consolidated financial statements.

In May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition and Derivatives and Hedging: Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting. This guidance rescinds SEC Staff Observer comments that are codified in Topic 606, Revenue from Contracts with Customers, and Topic 932, Extractive Activities--Oil and Gas. This amendment is effective upon adoption of Topic 606. We are in the process of evaluating the impact of this guidance on our consolidated financial statements.

In June 2016, 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 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 GAAP and instead, requires an entity to reflect its current estimate of all expected credit losses. The amendments 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 have the contractual right to receive cash. We are currently evaluating the impact this standard will have on our financial statements and related disclosures and do not anticipate it to have a material affect.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments. This ASU provides guidance of eight specific cash flow issues. This ASU is effective for periods after December 15, 2017, with early adoption permitted. We are in the process of evaluating the impact of this guidance on our consolidated financial statements.

In December 2016, the FASB issued ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers. This guidance updates narrow aspects of the guidance issued in Update 2014-09. This amendment is effective for periods after December 15, 2017, with early adoption permitted. We in the process of evaluating the impact of this ASU on our consolidated financial statements.
In January 2017, the FASB issued ASU No. 2017-01, Clarifying the Definition of a Business. Under the current business combination guidance, there are three elements of a business: inputs, processes and outputs. The revised guidance adds an initial screen test to determine if substantially all of the fair value of the gross assets acquired is concentrated in a single asset or group of similar assets. If that screen is met, the set of assets is not a business. The new framework also specifies the minimum required inputs and processes necessary to be a business. This amendment is effective for periods after December 15, 2017, with early adoption permitted. We are in the process of evaluating the impact of this ASU on our consolidated financial statements.

ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Natural Gas, Oil and Natural Gas Liquids Derivative Instruments. Our revenues, operating results profitability, future rate of growthoperations and the carrying valuecash 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 revenue 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 properties depend primarily upon the prevailing pricesstorage inventory levels, industry decline rates for oilbase production and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuationsweather trends. Executive management is involved 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

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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;all risk management activities and the overall economic environment.Board of Directors reviews our derivative program at its quarterly board meetings. We believe we have sufficient internal controls to prevent unauthorized trading.
These factorsWe use derivative instruments to achieve our risk management objectives, including swaps, options and the volatilitycostless collars. All of these are described in more detail below. We typically use swaps for a large portion of the energy markets make it extremely difficult to predict future oil and natural gas price movementsrisk we hedge. We have also sold calls, taking advantage of premiums associated with any certainty. During the past seven years, the posted price for WTI, has ranged from a low of $26.05 per barrel, or Bbl, in February 2016 to a high of $113.39 per Bbl in April 2011. The Henry Hub spot 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 natural gas has rangedexisting producing reserve estimates and estimates of likely production from a lownew 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 $1.61 per MMBtuour 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 actual fixed price on our derivative instruments is derived from the reference NYMEX price, as reflected in March 2016 to a highcurrent NYMEX trading. The pricing dates of $7.51 per MMBtuour derivative contracts follow NYMEX futures. All of our commodity derivative instruments are net settled based on the difference between the fixed price as stated in January 2010. On October 27, 2017, the WTI posted price for crude oil was $53.90 per Bblcontract and the Henry Hub spotfloating-price, resulting in a net amount due to or from the counterparty.
We review our derivative positions continuously and if future market priceconditions change and prices are at levels we believe could jeopardize the effectiveness of natural gas was $2.78 per MMBtu. Ifa position, we will mitigate this risk by either negotiating a cash settlement with our counterparty, restructuring the prices of oil and natural gas decline fromposition or entering a new trade that effectively reverses the current levels, our operations, financial condition and level of expenditures forposition. The factors we consider in closing or restructuring a position before the development of our oil and natural gas reserves maysettlement date are identical to those we review when deciding to enter the original derivative position. Gains or losses related to closed positions will be materially and adversely affected. In addition, lower oil and natural gas prices may reducerecognized in the amount of oil and natural gas that we can produce economically. This may resultmonth specified 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 carryingoriginal 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 reasonableness. 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 our 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 subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. See Note 10 of the notes to our consolidated financial statements for further discussion of the fair value measurements associated with our derivatives.
As of June 30, 2020, our natural gas, oil and natural gas properties. ReductionsNGL 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.
•Basis Swaps: These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point. We receive the fixed price differential and pay the floating market price differential to the counterparty for the hedged commodity.
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•Options: We sell, and occasionally buy, call options in our reserves could also negatively impactexchange for a premium. At the borrowing base under our revolving credit facility, which could further limit our liquiditytime 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 ability to conduct additional explorationwe 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.
•Costless Collars: These instruments have a set floor and development activities.ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, we will cash-settle the difference with the counterparty.
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, 2017:2020:
LocationDaily Volume (MMBtu/day)Weighted
Average Price
Remaining 2020NYMEX Henry Hub357,000  $2.86  
 LocationDaily Volume (MMBtu/day) Weighted
Average Price
Remaining 2017NYMEX Henry Hub765,000
 $3.19
2018NYMEX Henry Hub898,000
 $3.06
2019NYMEX Henry Hub112,000
 $3.01
LocationDaily Volume
(Bbls/day)		Weighted
Average Price
Remaining 2020NYMEX WTI3,000  $35.49  
 LocationDaily Volume
(Bbls/day)		 Weighted
Average Price
Remaining 2017ARGUS LLS1,500
 $53.12
2018ARGUS LLS1,000
 $53.91
Remaining 2017NYMEX WTI4,500
 $54.89
2018NYMEX WTI3,000
 $52.24

 LocationDaily Volume
(Bbls/day)		 Weighted
Average Price
Remaining 2017Mont Belvieu C33,000
 $26.63
2018Mont Belvieu C33,500
 $28.03
Remaining 2017Mont Belvieu C5250
 $49.14
2018Mont Belvieu C5500
 $46.62
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. Each shortWe 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 short 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 volume.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  
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 LocationDaily Volume (MMBtu/day) Weighted Average Price
Remaining 2017NYMEX Henry Hub65,000
 $3.11
2018NYMEX Henry Hub103,000
 $3.25
2019NYMEX Henry Hub135,000
 $3.07
For a portion of the combined natural gas derivative instruments containing fixed price swaps and sold call options, the counterparty has an option to extend the original terms an additional twelve months for the period January 2018 through December 2018. The option to extend the terms expires in December 2017. If extended, we would have additional fixed price swaps for 30,000 MMBtu per day at a weighted average price of $3.36 per MMBtu and additional short call options for 30,000 MMBtu per day at a weighted average ceiling price of $3.36 per MMBtu.
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. The option to extend the terms expires in December 2018. If executed, we would have additional fixed price swaps for 100,000 MMBtu per day at a weighted average price of $3.05 per MMBtu.
In addition, we have entered into natural gas basis swap positions, which settle on the pricing index to basis differential of NGPL Mid-Continent to NYMEX Henry Hub natural gas price. As of SeptemberJune 30, 2017, we2020, the Company had the following natural gas basis swap positions open:
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 NGPL Mid-Continent.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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 LocationDaily Volume (MMBtu/day) Hedged Differential
Remaining 2017NGPL Mid-Continent50,000
 $(0.26)
2018NGPL Mid-Continent12,000
 $(0.26)
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Under our 20172020 contracts, we have hedged approximately 62%59% to 64%63% of our estimated 20172020 production. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oilcommodity prices increase. At SeptemberJune 30, 2017,2020, we had a net liabilityasset derivative position of $7.1$3.3 million as compared to a net liabilityasset derivative position of $2.5$139.5 million as of SeptemberJune 30, 2016,2019, 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 $147.9$48.8 million, while a 10% decrease in underlying commodity prices would have increased the fair value of these instruments by approximately $147.9$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, 2017,2020, we had $365.0$123.0 million in borrowings outstanding under our revolving credit facility which bore interest at the eurodollara weighted average rate of 3.74%2.44%. A 1.0% increase in the average interest rate for the nine months ended September 30, 2017 would have resulted in an estimated $0.8 million increase in interest expense. As of SeptemberJune 30, 2017,2020, 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, 2017,2020, 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

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evaluation, our Chief Executive Officer and President and our Chief Financial Officer have concluded that, as of SeptemberJune 30, 2017,2020, 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
InLitigation 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, 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.
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 VermillionVermilion on July 29, 2016 we were named as a defendant, among 26 oil and gas companies, in(together, the Cameron Parish complaint and among more than 40 oil and gas companies in the Vermillion Parish complaint, or the Complaints."Complaints"). The Complaints were filed underallege 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 which we referred to collectively as the CZM Laws, and allege that certain of the defendants’ oil and gas exploration, production and transportation operations associated with the development of the East Hackberry and West Hackberry oil and gas fields, in the case of the Cameron Parish complaint, and the Tigre Lagoon and Lac Blanc oil and gas fields, in the case of the Vermillion Parish complaint, were conducted in violation of the CZM Laws. The Complaints allege that such activities caused(the "CZM Laws") by causing substantial damage to land and waterbodies located in the coastal zone of the relevant Parish, including due to defendants’ design, construction and use of waste pits and the alleged failure to properly close the waste pits and to clear, re-vegetate, detoxify and return the property affected to its original condition, as well as the defendants’ alleged discharge of waste into the coastal zone.Parish. The Complaints also allege that the defendants’ oil and gas activities have resulted in the dredging of numerous canals, which had a direct and significant impact on the state coastal waters within the relevant Parish and that the defendants, among other things, failed to design, construct and maintain these canals using the best practical techniques to prevent bank slumping, erosion and saltwater intrusion and to minimize the potential for inland movement of storm-generated surges, which activities allegedly have resulted in the erosion of marshes and the degradation of terrestrial and aquatic life therein. The Complaints also allege that the defendants failed to re-vegetate, refill, clean, detoxify and otherwise restore these canals to their original condition. In these two petitions, 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 pre-judgment and post judgment interest.
We were served with The United States District Court for the Cameron complaint in early May 2016 and with the Vermillion complaint in early September 2016.  TheWestern District of Louisiana Attorney General and the Louisiana Department of Natural Resources intervened in both the Cameron Parish suit and the Vermillion Parish suit.  Shortly after the Complaints were filed, certain defendants removedissued orders remanding the cases to their respective state court, and the lawsuitdefendants 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 many 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 Louisiana.  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 both cases,October 2019, Kelsie Wagner, in her capacity as trustee of various trusts and on behalf of the plaintiffstrusts and other similarly situated royalty owners, filed a motion to remand, and the plaintiffs agreed to an extension of time for all defendants to file responsive pleadings until the District Courts ruled on the motions to remand.  In the Vermilion Parish case,action against us in the District Court enteredof 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 order on September 26, 2017 remandingaction against certain of our current and former executive officers and directors in the lawsuitUnited States District Court for the District of Delaware. The complaint alleges that the defendants breached their fiduciary duties to the 15th JudicialCompany 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 State of Louisiana, Parish of Vermilion.  Pursuant to an agreement with plaintiffs’ counsel, all defendants have an extension of time through November 27, 2017 to file responsive pleadings to plaintiffs’ petitions in the Vermilion Parish lawsuit.  In the Cameron Parish lawsuit, the District Court has not ruled on plaintiffs’ motion to remand.  Briefing on the motion to remand has been completed; however, no hearing has been set for the motion to remand,Southern District of Ohio Eastern Division. The complaint alleges that we violated the Fair Labor Standards Act (“FLSA”), the Ohio Wage Act and the District Court has not givenOhio Prompt Pay Act by classifying the parties any indication regarding whenplaintiffs as independent contractors and paying them a ruling shoulddaily 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 expected. Dueowed to the procedural posture of lawsuits, the fact that responsive pleadings have not been filed and the fact that the parties have not begun discovery,workers.
These cases are still in their early stages. As a result, we have not had the opportunity to evaluate the applicability of the allegations made in the plaintiffs' complaints and intend to vigorously defend the suits.
SEC Investigation
The SEC has commenced an investigation with respect to certain actions by our former management, including alleged improper personal use of company assets, and potential violations by our former management and the company 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 management cannot determinecontract 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 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. 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, 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.
We received several Finding of Violation (“FOVs”) from the United States Environmental Protection Agency ("USEPA") alleging violations of the Clean Air Act at approximately 17 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 resulted in monetary sanctions of 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 loss, if any, that may result.
In addition, due$180,000 to the natureODEQ. The Order received final approval at the ODEQ and expects to be finalized in the third quarter of our business, we2020.
Other Matters
Based on management’s current assessment, they are from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment related disputes. Inof the opinion of our management, none of thethat no pending litigation, disputes or claims against us, if decided adversely, willthreatened lawsuit or dispute relating to its business operations is likely to have a material adverse effect on ourtheir future consolidated financial condition, cash flows orposition, results of operations.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, 2016.2019. 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
None.

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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 June 30, 2020 was as follows:
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)During the three months ended June 30, 2020, we repurchased and canceled 27,294 shares of our common stock at a weighted average price of $1.04 to satisfy tax withholding requirements incurred upon the vesting of restricted stock unit awards.
(2)In January 2019, our board of directors approved a new stock repurchase program to acquire up to $400.0 million of our outstanding common stock within a 24 month period. The program was suspended in the fourth quarter of 2019, and the May 1, 2020 amendment to our 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).
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).
4.6
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).
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 October 11, 2017, among Gulfport Energy Corporation, the subsidiary guarantors party and J.P. Morgan Securities LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 4.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 11, 2017).
17,060

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TableAdditionally, on February 27, 2020, the following named executive officer disposed of Contents


shares to satisfy tax withholding obligations:
4.10Named Executive Officer
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).
Restricted Stock Units
Donnie Moore
10.1
Tenth Amendment to Amended and Restated Credit Agreement, dated as of October 4, 2017, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 5, 2017).
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.
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.
19,498
*Filed herewith.



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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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Table of Contents

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 2, 2017August 6, 2020
 
GULFPORT ENERGY CORPORATION
GULFPORT ENERGY CORPORATIONBy:/s/    Quentin Hicks
By:/s/    Keri Crowell
Keri Crowell
Quentin Hicks
Executive Vice President & Chief Financial Officer



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