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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
☒QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 20202021
OR
☐TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number 000-19514001-19514
Gulfport Energy Corporation
(Exact Name of Registrant As Specified in Its Charter)
Delaware73-152129086-3684669
(State or Other Jurisdiction of Incorporation or Organization)(IRS Employer Identification Number)
3001 Quail Springs Parkway
Oklahoma City,Oklahoma73134
(Address of Principal Executive Offices)(Zip Code)
(405) 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,Stock, $0.0001 par value $0.01 per shareGPORNasdaq Global Select MarketThe New York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     Yes  ý    No  ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or such shorter period that the registrant was required to submit such files).      Yes  ý    No  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated filer  ¨     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
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.
 Yes  ý    No  ¨
As of July 31, 2020, 160,115,82929, 2021, 20,585,599 shares of the registrant’s common stock were outstanding.


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GULFPORT ENERGY CORPORATION
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DEFINITIONS
Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” “Gulfport,” the “Company” and “Registrant” refer to Gulfport Energy Corporation and its consolidated subsidiaries. All monetary values, other than per unit and per share amounts, are stated in thousands of U.S. dollars unless otherwise specified. In addition, the following are other abbreviations and definitions of certain terms used within this Quarterly Report on Form 10-Q:
2023 Notes. 6.625% Senior Notes due 2023.
2024 Notes. 6.000% Senior Notes due 2024.
2025 Notes. 6.375% Senior Notes due 2025.
2026 Notes. 6.375% Senior Notes due 2026.
ASC. Accounting Standards Codification.
ASU. Accounting Standards Update.
Bankruptcy Code. Chapter 11 of Title 11 of the United States Code.
Bankruptcy Court. The United States Bankruptcy Court for the Southern District of Texas.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.
Btu. British thermal unit, which represents the amount of energy needed to heat one pound of water by one degree Fahrenheit and can be used to describe the energy content of fuels.
Building Loan. Loan agreement for our corporate headquarters scheduled to mature in June 2025.
Chapter 11 Cases. Voluntary petitions filed on November 13, 2020 by Gulfport Energy Corporation, Gator Marine, Inc., Gator Marine Ivanhoe, Inc., Grizzly Holdings, Inc., Gulfport Appalachia, LLC, Gulfport Midcon, LLC, Gulfport Midstream Holdings, LLC, Jaguar Resources LLC, Mule Sky LLC, Puma Resources, Inc. and Westhawk Minerals LLC.
CODI. Cancellation of indebtedness income.
Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas, oil and NGL.
Current Combined Quarter. Combined Successor Period and Current Predecessor Quarter.
Current Combined YTD Period. Combined Successor Period and Current Predecessor YTD Period.
Current Predecessor Quarter. Period from April 1, 2021 through May 17, 2021.
Current Predecessor YTD Period. Period from January 1, 2021 through May 17, 2021.
DD&A. Depreciation, depletion and amortization.
Debtors. Collectively, Gulfport Energy Corporation, Gator Marine, Inc., Gator Marine Ivanhoe, Inc., Grizzly Holdings, Inc., Gulfport Appalachia, LLC, Gulfport Midcon, LLC, Gulfport Midstream Holdings, LLC, Jaguar Resources LLC, Mule Sky LLC, Puma Resources, Inc. and Westhawk Minerals LLC.
DIP Credit Facility. Senior secured superpriority debtor-in-possession revolving credit facility in an aggregate principal amount of $262.5 million.
Emergence Date. May 17, 2021.
Exit Credit Agreement. The Second Amended and Restated Credit Agreement with the Bank of Nova Scotia as lead administrative agent and various lender parties providing for the Exit Facility and the First-Out Term Loan Facility.
Exit Credit Facility. Collectively, the First-Out Term Loan Facility and the Exit Facility, with an initial borrowing base and elected commitment amount of up to $580 million.
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Exit Facility. Senior secured reserve-based revolving credit facility with The Bank of Nova Scotia as the lead arranger and administrative agent and various lender parties.
First-Out Term Loan Facility. Senior secured term loan in an aggregate maximum principal amount of $180 million.
Grizzly. Grizzly Oil Sands ULC.
Grizzly Holdings. Grizzly Holdings Inc.
Gross Acres or Gross Wells. Refers to the total acres or wells in which a working interest is owned.
Guarantors. All existing consolidated subsidiaries that guarantee the Company's revolving credit facility or certain other debt.
Indentures. Collectively, the 1145 Indenture and the 4(a)(2) Indenture governing the Successor Senior Notes.
IRC. The Internal Revenue Code of 1986, as amended.
LIBOR. London Interbank Offered Rate.
LOE. Lease operating expenses.
MBbl. One thousand barrels of crude oil, condensate or natural gas liquids.
Mcf. One thousand cubic feet of natural gas.
Mcfe. One thousand cubic feet of natural gas equivalent.
MMBtu. One million British thermal units.
MMcf. One million cubic feet of natural gas.
MMcfe. One million cubic feet of natural gas equivalent.
Natural Gas Liquids (NGL). Hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, adsorption or other methods in gas processing or cycling plants. Natural gas liquids primarily include ethane, propane, butane, isobutene, pentane, hexane and natural gasoline.
Net Acres or Net Wells. Refers to the sum of the fractional working interests owned in gross acres or gross wells.
New Common Stock. $0.0001 par value common stock issued by the Successor on the Emergence Date.
New Preferred Stock. $0.0001 par value preferred stock issued by the Successor on the Emergence Date.
NYMEX. New York Mercantile Exchange.
Petition Date. November 13, 2020.
Plan. The Amended Joint Chapter 11 Plan of Reorganization of Gulfport Energy Corporation and Its Debtor Subsidiaries.
Pre-Petition Revolving Credit Facility. 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 with a maximum facility amount of $580 million.
Prior Predecessor Quarter. Period from April 1, 2020 through June 30, 2020.
Prior Predecessor YTD Period. Period from January 1, 2020 through June 30, 2020.
Restructuring. Restructuring contemplated under the Restructuring Support Agreement including equitizing a significant portion of our pre-petition indebtedness and rejecting or renegotiating certain contracts.
RSA. Restructuring Support Agreement.
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SCOOP. Refers to the South Central Oklahoma Oil Province, a term used to describe a defined area that encompasses many of the top hydrocarbon producing counties in Oklahoma within the Anadarko basin. The SCOOP play mainly targets the Devonian to Mississippian aged Woodford, Sycamore and Springer formations. Our acreage is primarily in Garvin, Grady and Stephens Counties.
SEC. The United States Securities and Exchange Commission.
Predecessor Senior Notes. Collectively, the 2023 Notes, 2024 Notes, 2025 Notes and 2026 Notes.
Successor Period. Period from May 18, 2021 through June 30, 2021.
Successor Senior Notes. 8.000% Senior Notes due 2026.
Undeveloped Acreage. Lease or mineral acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and/or natural gas.
Utica. Refers to the hydrocarbon bearing rock formation located in the Appalachian Basin of the United States and Canada. Our acreage is located primarily in Belmont, Harrison, Jefferson and Monroe Counties in Eastern Ohio.
Working Interest (WI). The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.
WTI. Refers to West Texas Intermediate.


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GULFPORT ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
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  
(In thousands, except share data)

SuccessorPredecessor
June 30, 2021December 31, 2020
(Unaudited)
Assets
Current assets:
Cash and cash equivalents$9,389 $89,861 
Restricted cash29,135 0 
Accounts receivable—oil and natural gas sales140,663 119,879 
Accounts receivable—joint interest and other10,695 12,200 
Prepaid expenses and other current assets24,737 160,664 
Short-term derivative instruments2,223 27,146 
Total current assets216,842 409,750 
Property and equipment:
Oil and natural gas properties, full-cost method
Proved oil and natural gas properties1,737,778 9,359,866 
Unproved properties224,214 1,457,043 
Other property and equipment6,914 88,538 
Total property and equipment1,968,906 10,905,447 
Less: accumulated depletion, depreciation and amortization(150,175)(8,819,178)
Total property and equipment, net1,818,731 2,086,269 
Other assets:
Equity investments0 24,816 
Long-term derivative instruments3,014 322 
Operating lease assets44 342 
Other assets27,557 18,372 
Total other assets30,615 43,852 
Total assets$2,066,188 $2,539,871 

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS–CONTINUED
(In thousands, except share data)
SuccessorPredecessor
June 30, 2021December 31, 2020
(Unaudited)
Liabilities, Mezzanine Equity and Stockholders’ Equity (Deficit)
Current liabilities:
Accounts payable and accrued liabilities$397,800 $244,903 
Short-term derivative instruments192,730 11,641 
Current portion of operating lease liabilities39 0 
Current maturities of long-term debt60,000 253,743 
Total current liabilities650,569 510,287 
Non-current liabilities:
Long-term derivative instruments113,470 36,604 
Asset retirement obligation19,347 0 
Non-current operating lease liabilities5 0 
Long-term debt, net of current maturities773,847 0 
Total non-current liabilities906,669 36,604 
Liabilities subject to compromise0 2,293,480 
Total liabilities$1,557,238 $2,840,371 
Commitments and contingencies (Note 9)
00
Mezzanine Equity:
New Preferred Stock - $0.0001 par value, 110 thousand shares authorized, 55.9 thousand issued and outstanding at June 30, 202155,860 — 
Stockholders’ equity (deficit):
Predecessor common stock - $0.01 par value, 200.0 million shares authorized, 160.8 million issued and outstanding at December 31, 2020— 1,607 
Predecessor accumulated other comprehensive loss— (43,000)
New Common Stock - $0.0001 par value, 42.0 million shares authorized, 20.6 million issued and outstanding at June 30, 20212 — 
Additional paid-in capital693,921 4,213,752 
New Common Stock held in reserve, 937 thousand shares(30,216)— 
Accumulated deficit(210,617)(4,472,859)
Total stockholders’ equity (deficit)$453,090 $(300,500)
Total liabilities, mezzanine equity and stockholders’ equity (deficit)$2,066,188 $2,539,871 

See accompanying notes to consolidated financial statements.
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GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
(Unaudited) 
Three months ended June 30,Six months ended June 30,
2020201920202019SuccessorPredecessor
(In thousands)Period from May 18, 2021 through June 30, 2021Period from April 1, 2021 through May 17, 2021Three Months Ended June 30, 2020
REVENUES:REVENUES:REVENUES:
Natural gas salesNatural gas sales$86,797  $225,257  $195,344  $501,273  Natural gas sales$111,718 $109,069 $140,688 
Oil and condensate salesOil and condensate sales8,390  36,910  31,541  69,392  Oil and condensate sales17,587 10,867 8,390 
Natural gas liquid salesNatural gas liquid sales10,252  25,687  27,165  57,812  Natural gas liquid sales16,077 13,004 10,252 
Net gain on natural gas, oil and NGL derivatives26,971  171,140  125,237  151,095  
Net (loss) gain on natural gas, oil and NGL derivativesNet (loss) gain on natural gas, oil and NGL derivatives(139,658)(107,261)26,971 
Total RevenuesTotal Revenues132,410  458,994  379,287  779,572  Total Revenues5,724 25,679 186,301 
OPERATING EXPENSES:OPERATING EXPENSES:OPERATING EXPENSES:
Lease operating expensesLease operating expenses15,686  22,388  31,672  42,195  Lease operating expenses4,116 6,871 13,078 
Production taxes3,605  8,098  8,404  16,019  
Midstream gathering and processing expenses59,974  72,015  117,870  142,297  
Taxes other than incomeTaxes other than income5,056 3,645 6,300 
Transportation, gathering, processing and compressionTransportation, gathering, processing and compression41,376 55,219 113,865 
Depreciation, depletion and amortizationDepreciation, depletion and amortization64,790  124,951  142,818  243,384  Depreciation, depletion and amortization32,362 21,617 64,790 
Impairment of oil and natural gas propertiesImpairment of oil and natural gas properties532,880  —  1,086,225  —  Impairment of oil and natural gas properties117,813 0 532,880 
General and administrative expensesGeneral and administrative expenses10,470  11,727  26,639  21,784  General and administrative expenses6,518 6,418 9,766 
Restructuring and liability management expensesRestructuring and liability management expenses0 0 617 
Accretion expenseAccretion expense755  1,359  1,496  2,426  Accretion expense226 424 755 
Total Operating ExpensesTotal Operating Expenses688,160  240,538  1,415,124  468,105  Total Operating Expenses207,467 94,194 742,051 
(LOSS) INCOME FROM OPERATIONS(LOSS) INCOME FROM OPERATIONS(555,750) 218,456  (1,035,837) 311,467  (LOSS) INCOME FROM OPERATIONS(201,743)(68,515)(555,750)
OTHER EXPENSE (INCOME):OTHER EXPENSE (INCOME):OTHER EXPENSE (INCOME):
Interest expenseInterest expense32,366  36,418  65,356  72,039  Interest expense8,894 898 32,366 
Interest income(78) (159) (230) (311) 
Gain on debt extinguishmentGain on debt extinguishment(34,257) —  (49,579) —  Gain on debt extinguishment0 0 (34,257)
Loss from equity method investments, netLoss from equity method investments, net45  125,582  10,834  121,309  Loss from equity method investments, net0 0 45 
Other expense7,242  990  9,098  563  
Total Other Expense5,318  162,831  35,479  193,600  
Reorganization items, netReorganization items, net0 (305,617)0 
Other, netOther, net(1,051)1,958 7,164 
Total Other Expense (Income)Total Other Expense (Income)7,843 (302,761)5,318 
(LOSS) INCOME BEFORE INCOME TAXES(LOSS) INCOME BEFORE INCOME TAXES(561,068) 55,625  (1,071,316) 117,867  (LOSS) INCOME BEFORE INCOME TAXES(209,586)234,246 (561,068)
Income Tax Expense (Benefit)—  (179,331) 7,290  (179,331) 
Income tax benefitIncome tax benefit0 (7,968)0 
NET (LOSS) INCOMENET (LOSS) INCOME$(561,068) $234,956  $(1,078,606) $297,198  NET (LOSS) INCOME$(209,586)$242,214 $(561,068)
NET (LOSS) INCOME PER COMMON SHARE:
Dividends on New Preferred StockDividends on New Preferred Stock$(1,031)$0 $0 
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERSNET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS$(210,617)$242,214 $(561,068)
NET INCOME (LOSS) PER COMMON SHARE:NET INCOME (LOSS) PER COMMON SHARE:
BasicBasic$(3.51) $1.47  $(6.75) $1.85  Basic$(10.36)$1.51 $(3.51)
DilutedDiluted$(3.51) $1.47  $(6.75) $1.84  Diluted$(10.36)$1.51 $(3.51)
Weighted average common shares outstanding—BasicWeighted average common shares outstanding—Basic159,934  159,325  159,847  161,065  Weighted average common shares outstanding—Basic20,321 $160,887 159,934 
Weighted average common shares outstanding—DilutedWeighted average common shares outstanding—Diluted159,934  159,507  159,847  161,590  Weighted average common shares outstanding—Diluted20,321 160,887 159,934 

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GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS—CONTINUED
(In thousands, except per share data)
(Unaudited)
SuccessorPredecessor
Period from May 18, 2021 through June 30, 2021Period from January 1, 2021 through May 17, 2021Six Months Ended June 30, 2020
REVENUES:
Natural gas sales$111,718 $344,390 $301,696 
Oil and condensate sales17,587 29,106 31,541 
Natural gas liquid sales16,077 36,780 27,165 
Net (loss) gain on natural gas, oil and NGL derivatives(139,658)(137,239)125,237 
Total Revenues5,724 273,037 485,639 
OPERATING EXPENSES:
Lease operating expenses4,116 19,524 27,773 
Taxes other than income5,056 12,349 12,937 
Transportation, gathering, processing and compression41,376 161,086 224,222 
Depreciation, depletion and amortization32,362 62,764 142,818 
Impairment of oil and natural gas properties117,813 0 1,086,225 
Impairment of other property and equipment0 14,568 0 
General and administrative expenses6,518 19,175 25,388 
Restructuring and liability management expenses0 0 617 
Accretion expense226 1,229 1,496 
Total Operating Expenses207,467 290,695 1,521,476 
(LOSS) INCOME FROM OPERATIONS(201,743)(17,658)(1,035,837)
OTHER EXPENSE (INCOME):
Interest expense8,894 4,159 65,356 
Gain on debt extinguishment0 0 (49,579)
Loss from equity method investments, net0 342 10,834 
Reorganization items, net0 (266,898)0 
Other, net(1,051)1,711 8,868 
Total Other Expense (Income)7,843 (260,686)35,479 
(LOSS) INCOME BEFORE INCOME TAXES(209,586)243,028 (1,071,316)
Income tax (benefit) expense0 (7,968)7,290 
NET (LOSS) INCOME$(209,586)$250,996 $(1,078,606)
Dividends on New Preferred Stock$(1,031)$0 $0 
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS$(210,617)$250,996 $(1,078,606)
NET (LOSS) INCOME PER COMMON SHARE:
Basic$(10.36)$1.56 $(6.75)
Diluted$(10.36)$1.56 $(6.75)
Weighted average common shares outstanding—Basic20,321 160,834 159,847 
Weighted average common shares outstanding—Diluted20,321 160,834 159,847 

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) INCOME
(In thousands)
(Unaudited)
 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  

SuccessorPredecessor
Period from May 18, 2021 through June 30, 2021Period from April 1, 2021 through May 17, 2021Three months ended June 30, 2020
Net income (loss)$(209,586)$242,214 $(561,068)
Foreign currency translation adjustment0 0 6,872 
Other comprehensive income (loss)0 0 6,872 
Comprehensive income (loss)$(209,586)$242,214 $(554,196)
SuccessorPredecessor
Period from May 18, 2021 through June 30, 2021Period from January 1, 2021 through May 17, 2021Six months ended June 30, 2020
Net income (loss)$(209,586)$250,996 $(1,078,606)
Foreign currency translation adjustment0 0 (8,158)
Other comprehensive income (loss)0 0 (8,158)
Comprehensive income (loss)$(209,586)$250,996 $(1,086,764)

See accompanying notes to consolidated financial statements.

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

Paid-in
Capital		Accumulated
Other
Comprehensive (Loss) Income		Accumulated
Deficit		Total
Stockholders’
Equity		Common Stock Held in Reserve
Paid-in
Capital		Accumulated
Other
Comprehensive Loss		Accumulated
Deficit		Total
Stockholders’
Equity
Common StockCommon StockCommon Stock Held in ReserveAccumulated
Other
Comprehensive Loss		Accumulated
Deficit		Total
Stockholders’
Equity
SharesAmount SharesAmount
(In thousands)
Balance at January 1, 2020159,711  $1,597  $4,207,554  $(46,833) $(2,847,726) $1,314,592  
Balance at January 1, 2020 (Predecessor)Balance at January 1, 2020 (Predecessor)159,711 $1,597 0 $0 $4,207,554 $(46,833)$(2,847,726)1,314,592 
Net LossNet Loss—  —  —  —  (517,538) (517,538) Net Loss— — — — — — (517,538)(517,538)
Other Comprehensive LossOther Comprehensive Loss—  —  —  (15,030) —  (15,030) Other Comprehensive Loss— — — — — (15,030)— (15,030)
Stock CompensationStock Compensation—  —  2,104  —  —  2,104  Stock Compensation— — — — 2,104 — — 2,104 
Shares RepurchasedShares Repurchased(80) (1) (78) —  —  (79) Shares Repurchased(80)(1)— — (78)— — (79)
Issuance of Restricted StockIssuance of Restricted Stock211  2  (2) —  —  —  Issuance of Restricted Stock211 2 — — (2)— — 0 
Balance at March 31, 2020159,842  $1,598  $4,209,578  $(61,863) $(3,365,264) $784,049  
Balance at March 31, 2020 (Predecessor)Balance at March 31, 2020 (Predecessor)159,842 $1,598 0 $0 $4,209,578 $(61,863)$(3,365,264)$784,049 
Net LossNet Loss—  —  —  —  (561,068) (561,068) Net Loss— $— — $— $— $— $(561,068)(561,068)
Other Comprehensive IncomeOther Comprehensive Income—  —  —  6,872  —  6,872  Other Comprehensive Income— — — — — 6,872 — 6,872 
Stock CompensationStock Compensation—  —  1,515  —  —  1,515  Stock Compensation— — — — 1,515 — — 1,515 
Shares RepurchasedShares Repurchased(27) —  (28) —  —  (28) Shares Repurchased(27)— — — (28)— — (28)
Issuance of Restricted StockIssuance of Restricted Stock301  3  (3) —  —  —  Issuance of Restricted Stock301 3 — — (3)— — 0 
Balance at June 30, 2020160,116  $1,601  $4,211,062  $(54,991) $(3,926,332) $231,340  
Balance at June 30, 2020 (Predecessor)Balance at June 30, 2020 (Predecessor)160,116 $1,601 0 $0 $4,211,062 $(54,991)$(3,926,332)$231,340 
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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  

GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT) CONTINUED
(In thousands)

(Unaudited)
Common Stock Held in Reserve
Paid-in
Capital		Accumulated Other
Comprehensive (Loss) Income		Retained Earnings (Accumulated
Deficit)		Total Stockholders’
Equity (Deficit)
Common Stock
 SharesAmountSharesAmount
Balance at January 1, 2021 (Predecessor)160,762 1,607 0 0 4,213,752 (43,000)(4,472,859)(300,500)
Net Loss— — — — — 8,780 8,780 
Other Comprehensive Income— — — — — 2,570 — 2,570 
Stock Compensation— — — — 1,419 — — 1,419 
Shares Repurchased(86)(1)— — (7)— — (8)
Issuance of Restricted Stock203 3 — — (2)— — 1 
Balance at March 31, 2021 (Predecessor)160,879 1,609 0 0 4,215,162 (40,430)(4,464,079)(287,738)
Net Income— — — — — — 242,214 242,214 
Issuance of Restricted Stock25 — — — — — — — 
Shares Repurchased(10)— — — — — — — 
Stock Compensation— — — — 5,095 — — 5,095 
Accumulated other comprehensive income extinguishment— — — — — 40,430 — 40,430 
Cancellation of Predecessor Equity(160,894)(1,609)— — (4,220,256)— 4,221,865 — 
Issuance of New Common Stock21,525 2 — — 693,773 — — 693,775 
Shares of New Common Stock Held in Reserve— — (1,679)(54,109)— — — (54,109)
Balance at May 17, 2021 (Predecessor)21,525 2 (1,679)(54,109)693,774 0 0 639,667 
Balance at May 18, 2021 (Successor)21,525 2 (1,679)(54,109)693,774 0 0 639,667 
Net Loss— — — — — — (209,586)(209,586)
Release of New Common Stock Held in Reserve— — 741 23,893 — — — 23,893 
Conversion of New Preferred Stock10 — — — 147 — — 147 
Dividends on New Preferred Stock— — — — — — (1,031)(1,031)
Balance at June 30, 2021 (Successor)21,535 2 (938)(30,216)693,921 0 (210,617)453,090 
See accompanying notes to consolidated financial statements.
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GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
 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  

SuccessorPredecessor
Period from May 18, 2021 through June 30, 2021Period from January 1, 2021 through May 17, 2021Six Months Ended June 30, 2020
Cash flows from operating activities:
Net income (loss)$(209,586)$250,996 $(1,078,606)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization32,362 62,764 142,818 
Impairment of oil and natural gas properties117,813 0 1,086,225 
Impairment of other property and equipment0 14,568 0 
Loss from equity investments0 342 10,834 
Gain on debt extinguishment0 0 (49,579)
Net loss (gain) on derivative instruments139,658 137,239 (125,237)
Net cash receipts on settled derivative instruments(6,689)(3,361)195,232 
Non-cash reorganization items, net0 (446,012)0 
Deferred income tax expense0 0 7,290 
Other, net(397)1,725 9,844 
Changes in operating assets and liabilities, net(34,796)153,894 48,401 
Net cash provided by operating activities38,365 172,155 247,222 
Cash flows from investing activities:
Additions to oil and natural gas properties(40,424)(102,330)(274,851)
Proceeds from sale of oil and natural gas properties225 15 45,185 
Other, net(77)4,484 (424)
Net cash used in investing activities(40,276)(97,831)(230,090)
Cash flows from financing activities:
Principal payments on pre-petition revolving credit facility0 (318,961)(323,000)
Borrowings on pre-petition revolving credit facility0 26,050 326,000 
Borrowings on exit credit facility113,249 302,751 0 
Principal payments on exit credit facility(131,000)0 0 
Principal payments on DIP credit facility0 (157,500)0 
Debt issuance costs and loan commitment fees(1,206)(7,100)0 
Repurchase of senior notes0 0 (22,827)
Proceeds from issuance of New Preferred Stock0 50,000 0 
Other, net(25)(8)(548)
Net cash used in financing activities(18,982)(104,768)(20,375)
Net decrease in cash, cash equivalents and restricted cash(20,893)(30,444)(3,243)
Cash, cash equivalents and restricted cash at beginning of period59,417 89,861 6,060 
Cash, cash equivalents and restricted cash at end of period$38,524 $59,417 $2,817 
 See accompanying notes to consolidated financial statements.
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GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1.BASIS OF PRESENTATION SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND LIQUIDITY, MANAGEMENT'S PLANS AND GOING CONCERN
Description of Company
Gulfport Energy Corporation (the "Company" or "Gulfport") is an independent natural gas-weighted exploration and production company with assets primarily located in the Appalachia and Anadarko basins. Gulfport filed for voluntary reorganization under Chapter 11 of the Bankruptcy Code on November 13, 2020 and subsequently operated as a debtor-in-possession, in accordance with applicable provisions of the Bankruptcy Code, until its emergence on May 17, 2021. The Company refers to the post-emergence reorganized organization in the condensed financial statements and footnotes as the "Successor" for periods subsequent to May 17, 2021 and the pre-emergence organization as "Predecessor" for periods on or prior to May 17, 2021.
Basis of Presentation
The accompanying unaudited condensed consolidated financial statements have beenof Gulfport were prepared by Gulfport Energy Corporation (the “Company” or “Gulfport”) pursuant toin accordance with GAAP and the rules and regulations of the SecuritiesSEC.
This Quarterly Report on Form 10-Q (this “Form 10-Q”) relates to the financial position and Exchange Commission (the “SEC”periods of May 18, 2021 through June 30, 2021 (“Successor Period”), April 1, 2021 through May 17, 2021 ("Current Predecessor Quarter"), January 1, 2021 through May 17, 2021 (“Current Predecessor YTD Period”), the three months ended June 30, 2020 (“Prior Predecessor Quarter”) and the six months ended June 30, 2020 ("Prior Predecessor YTD Period"). The Company's annual report on Form 10-K for the year ended December 31, 2020 (“2020 Form 10-K”) should be read in conjunction with this Form 10-Q. Except as disclosed herein, and with the exception of information in this report related to our emergence from Chapter 11 and fresh start accounting, there has been no material change in the information disclosed in the notes to the consolidated financial statements included in the 2020 Form 10-K. The accompanying unaudited consolidated financial statements reflect all normal recurring adjustments that,which, in the opinion of management, are necessary for a fair presentationstatement 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.
The consolidated financial statements should be read in conjunction with theour condensed consolidated financial statements and accompanying notes and include the summaryaccounts of significant accounting policiesour wholly-owned subsidiaries. Intercompany accounts and notes included inbalances have been eliminated. The accompanying consolidated financial statements have been prepared assuming the Company’s most recent annual report on Form 10-K. Results for the three and six months ended June 30, 2020 are not necessarily indicative of the results expected for the full year.
COVID-19
In March 2020, the World Health Organization classified the outbreak of COVID-19Company will continue 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.going concern.
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 theyCertain reclassifications have been developing. Gulfport has modified certain business practices (including remote working for its corporate employeesmade to prior period financial statements and restricted employee business travel)related disclosures to conform to government restrictionscurrent period presentation. These reclassifications have no impact on previous reported total assets, total liabilities, net loss or total operating cash flows.
Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code
On the Petition Date, the Debtors filed voluntary petitions of relief under the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas. The Chapter 11 Cases were administered jointly under the caption In re Gulfport Energy Corporation, et al., Case No. 20-35562 (DRJ).
The Bankruptcy Court confirmed the Plan and best practices encouragedentered the confirmation order on April 28, 2021. The Debtors emerged from the Chapter 11 Cases on the Emergence Date. The Company's bankruptcy proceedings and related matters have been summarized below.
During the pendency of the Chapter 11 Cases, the Company continued to operate its business in the ordinary course as debtors-in-possession in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court granted the first day relief requested by the Centers for Disease Control and Prevention,Company that was designed primarily to mitigate 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. Asimpact of the date of this filing, Gulfport has transitioned approximately 60% ofChapter 11 Cases on its corporate employees back to the corporate office. The Company will continue to monitor trendsoperations, vendors, suppliers, customers 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 disruptionswas able to conduct normal business activities and satisfy all associated obligations for the period following the Petition Date and was also authorized to pay mineral interest owner royalties, employee wages and benefits, and certain vendors and suppliers in executing its business operations in 2020.
Gulfport is closely monitoring the impact of COVID-19 on all aspects of its businessordinary course for goods 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 responseservices provided prior to the current commodity price environment,Petition Date. During the Company voluntarily shut-in a portion of its production during the second quarter of 2020 and announced tiered salary reduction for most employees, senior management team and the Board of Directors beginning in June 2020 with such measures expected to last through December 2020. Additionally, select furloughs were implemented to reduce costs and preserve liquidity.
On March 27, 2020, the U.S. government enacted the Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”). The CARES Act did not have a material impact on the Company’s consolidated financial statements.
Liquidity, Management's Plans and Going Concern
As noted above, decreased demand for oil and natural gas as a resultpendency of the COVID-19 pandemic andChapter 11 Cases, all transactions outside the accompanying decrease in commodity prices has significantly impairedordinary course of business required the Company's ability to access capital markets and to refinance itsprior approval of the Bankruptcy Court.
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existing indebtedness. Further, these conditions have made amendments or waiversSubject 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 basecertain specific exceptions under the Company's revolving credit facility could be further reduced at its next scheduled redetermination date in November 2020. Any such reduction would constrainBankruptcy Code, 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 infiling of the Company's capital expenditures would decrease its production, revenues, operating cash flow and EBITDA, which could limit its ability to comply with the restrictive covenants in its revolving credit facility and other existing indebtedness. Finally, the Company's existing revolving credit facility matures in December 2021 and therefore will become a current liability at year end 2020 unlessChapter 11 Cases automatically stayed all judicial or administrative actions against the Company is ableand efforts by creditors to refinance the credit facility with a new credit facilitycollect on 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 indebtednessotherwise exercise rights or failure to comply with any of its covenants, if not waived, would result in an event of default under such indebtedness and result in the potential acceleration of outstanding indebtedness thereunder and,remedies with respect to pre-petition claims. Absent an order from the revolving credit facility,Bankruptcy Court, substantially all of the potential foreclosureDebtors’ pre-petition liabilities were subject to compromise and discharge under the Bankruptcy Code. The automatic stay was lifted on the collateral securing such debt, and could cause a cross-default under its other outstanding indebtedness.Emergence Date.

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

Although management’s actions listed above have helped to improve our liquidity and leverage profile, continued macro headwinds including the depressed state of energy capital markets and the extraordinarily low commodity price environments present significant risks to the Company's ability to fund its operations going forward. Accordingly, management has determined there is substantial doubt about its ability to continue as a going concern over the next twelve months from the issuance of these financial statements. The Company has engaged financial and legal advisors to assist withapplied FASB ASC Topic 852 - Reorganizations ("ASC 852") in preparing 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 contemplatesfor the realization of assetsperiod ended May 17, 2021. ASC 852 specifies the accounting and satisfaction of liabilities and other commitments infinancial reporting requirements for entities reorganizing through Chapter 11 bankruptcy proceedings. These requirements include distinguishing transactions associated with the normal course of business and (ii) do not include any adjustmentsreorganization separate from activities related to reflect the possible future effectsongoing operations of the uncertaintybusiness. Accordingly, pre-petition liabilities that may be impacted by the Chapter 11 proceedings were classified as liabilities subject to compromise on the recoverabilityconsolidated balance sheet as of December 31, 2020. Additionally, certain expenses, realized gains and losses and provisions for losses that are realized or classificationincurred during the Chapter 11 Cases are recorded as reorganization items, net. Refer to Note 3 for more information regarding reorganization items.
Restricted Cash
As of recorded asset amounts orJune 30, 2021, we had restricted cash of $29.1 million. The restricted funds were maintained primarily to pay debtor-related professional fees associated with the amounts or classifications of liabilities.

Chapter 11 Cases.
Impact on Previously Reported Results
During the third quarter of 2019,2020, the Company identified that certain activitiesfirm transportation costs incurred in prior periods 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 activitiesdeducts to "natural gas sales" while they should have been presented as additions to oilincluded in "transportation, gathering, processing and natural gas properties in cash flows from investing activities.compression" on its consolidated statements of operations. The Company correctedassessed the materiality of this presentation on prior periods’ consolidated financial statements in accordance with the SEC Staff Accounting Bulletin No. 99, “Materiality”, codified in FASB ASC Topic 250 - Accounting Changes and Error Corrections. Based on this assessment, the Company concluded that the correction is not material to any previously presentedissued financial statements. The correction had no impact on its consolidated balance sheets, consolidated statements of cash flows for these additions and in doing so, for the six months ended June 30, 2019 contained herein, thecomprehensive income, consolidated statements of stockholders' equity or consolidated statements of cash flows andflows. Additionally, the condensed consolidating statements of cash flows were adjusted to increaseerror had no impact on net cash flows provided by operating activities by $90.8 million with a corresponding increase inloss or net cash flows used in investing activities.loss per share. The Company has evaluatedfollowing tables present the effect of the previous presentation, both qualitativelycorrection on all affected line items of our previously issued consolidated statements of operations for the Prior Predecessor Quarter and quantitatively,the Prior Predecessor YTD Period.
Three months ended June 30, 2020
Predecessor
As ReportedAdjustmentsAs Revised
(In thousands)
Natural gas sales$86,797 $53,891 $140,688 
Total Revenues$132,410 $53,891 $186,301 
Transportation, gathering, processing and compression$59,974 $53,891 $113,865 
Total Operating Expenses$688,160 $53,891 $742,051 
Six months ended June 30, 2020
Predecessor
As ReportedAdjustmentsAs Revised
(In thousands)
Natural gas sales$195,344 $106,352 $301,696 
Total Revenues$379,287 $106,352 $485,639 
Transportation, gathering, processing and compression$117,870 $106,352 $224,222 
Total Operating Expenses$1,415,124 $106,352 $1,521,476 
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Accounts Payable and concluded that it did not have a material impact on any previously filed annual or quarterly consolidated financial statements.Accrued Liabilities
Accounts payable and accrued liabilities consisted of the following at June 30, 2021 and December 31, 2020:
SuccessorPredecessor
June 30, 2021December 31, 2020
Accounts payable and other accrued liabilities$147,852 $120,275 
Revenue payable and suspense127,954 124,628 
Accrued contract rejection damages and shares held in reserve121,994 0 
Total accounts payable and accrued liabilities$397,800 $244,903 
Recently Adopted Accounting Standards
On January 1,In August 2020, the FASB issued ASU No. 2020-06, Debt—Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging— Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. This new standard simplifies and adds disclosure requirements for the accounting and measurement of convertible instruments. It eliminates the treasury stock method for convertible instruments and requires application of the “if-converted” method for certain agreements. In addition, the standard eliminates the beneficial conversion and cash conversion accounting models that require separate accounting for embedded conversion features and the recognition of a debt discount and related amortization to interest expense of those embedded features.
The Company elected to early adopt this standard effective on the Emergence Date. The Company adopted ASU No. 2016-13, the new standard using the modified retrospective approach transition method. No cumulative-effect adjustment to retained earnings was required upon adoption of the new standard. The consolidated financial statements for the Successor Period are presented under the new standard, while the predecessor periods and comparative periods are not adjusted and continue to be reported in accordance with the Company's historical accounting policy.
Supplemental Cash Flow and Non-Cash Information
SuccessorPredecessor
Period from May 18, 2021 through June 30, 2021Period from January 1, 2021 through May 17, 2021Six Months Ended June 30, 2020
Supplemental disclosure of cash flow information:
Cash paid for reorganization items, net$15,369 $87,199 $0 
Interest payments$2,072 $7,272 $60,523 
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable - oil and natural gas sales$40,048 $(60,832)$55,565 
(Increase) decrease in accounts receivable - joint interest and other$4,510 $(3,005)$29,159 
Increase (decrease) in accounts payable and accrued liabilities$(80,097)$79,193 $(30,620)
(Increase) decrease in prepaid expenses$681 $135,471 $(5,744)
(Increase) decrease in other assets$62 $3,067 $41 
Total changes in operating assets and liabilities$(34,796)$153,894 $48,401 
Supplemental disclosure of non-cash transactions:
Capitalized stock-based compensation$0 $930 $1,891 
Asset retirement obligation capitalized$36 $546 $1,553 
Asset retirement obligation removed due to divestiture$0 $0 $(2,033)
Interest capitalized$0 $0 $710 
Fair value of contingent consideration asset on date of divestiture$0 $0 $23,090 
Release of New Common Stock Held in Reserve$23,893 $0 $0 
Foreign currency translation gain (loss) on equity method investments$0 $2,570 $(8,158)
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2.Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial InstrumentsCHAPTER 11 EMERGENCE
As described in Note 1, on November 13, 2020, the Debtors filed the Chapter 11 Cases and the Plan, which replaceswas subsequently amended, and entered the incurred loss impairment methodologyconfirmation order on April 28, 2021. The Debtors then emerged from bankruptcy upon effectiveness of the Plan on May 17, 2021. Capitalized terms used but not defined herein shall have the meaning ascribed to them in the Plan.
Plan of Reorganization
In accordance with the Plan confirmed by the Bankruptcy Court, the following significant transactions occurred upon the Company's emergence from bankruptcy on May 17, 2021:
•Shares of the Predecessor's common stock outstanding immediately prior to the Emergence Date were cancelled, and on the Emergence Date, the Company issued 19,845,780 shares of New Common Stock and 55,000 shares of New Preferred Stock, which were the result of the transactions described below. The Company also entered into a methodologyregistration rights agreement and amended its articles of incorporation and bylaws for the authorization of the New Common Stock and New Preferred Stock among other corporate governance actions. See Note 6 for further discussion of the Company's post-emergence equity;
•All outstanding obligations under the Predecessor Senior Notes were cancelled;
•The Predecessor effectuated certain restructuring transactions, including entering into a plan of Merger with Gulfport Merger Sub, Inc., a newly formed, wholly owned subsidiary of Gulfport ("Merger Sub"), pursuant to which Merger Sub was merged with and into Predecessor, resulting in the Predecessor becoming a wholly owned subsidiary of Gulfport;
•The Debtors entered into a Second Amended and Restated Credit Agreement (the "Exit Credit Agreement") with the Bank of Nova Scotia as administrative agent, various lender parties and acknowledged and agreed to by certain of Gulfport's subsidiaries, as guarantors, providing for (i) a new money senior secured reserve-based revolving credit facility in an aggregate maximum principal amount of up to $1.5 billion (the "Exit Facility"); (ii) a senior secured term loan in an aggregate maximum principal amount of up to $180 million (the "First-Out Term Loan Facility") and together with the Exit Facility (the "Exit Credit Facility"), collectively with an initial borrowing base and elected commitment amount of up to $580 million (less the amount of any term loan deemed funded by any RBL Lender that reflects expected credit lossesis not a Consenting RBL Lender);
•The Company entered into an indenture to issue up to $550 million aggregate principal amount of its 8.000% senior notes due 2026, dated as of May 17, 2021, by and requires considerationamong the Issuer, UMB Bank, National Association, as trustee, and the guarantors party thereto (such indenture, the “1145 Indenture,” and such senior notes issued thereunder, the “1145 Notes”), under section 1145 of the Bankruptcy Code (“Section 1145”). Certain eligible holders have made an election (the “4(a)(2) Election”) entitling such holders to receive senior notes issued pursuant to an indenture, dated as of May 17, 2021, by and among the Issuer, UMB Bank, National Association, as trustee, and the guarantors party thereto (such indenture, the “4(a)(2) Indenture,” and such senior notes issued thereunder, the “4(a)(2) Notes”), under Section 4(a)(2) of the Securities Act of 1933, as amended as opposed to its share of the up to $550 million aggregate principal amount of 1145 Notes. The 4(a)(2) Indenture's terms are substantially similar to the terms of the 1145 Indenture. The 1145 Indenture and the 4(a)(2) Indenture are referred to together as the "Indentures". The 1145 Notes and the 4(a)(2) Notes are collectively referred to as the "Successor Senior Notes";
•The DIP Credit Facility indefeasibly converted into the Exit Facility, and all commitments under the DIP Credit Facility terminated. Each holder of an Allowed DIP Claim received, in full and final satisfaction, settlement, release, and discharge of, and in exchange for, each Allowed DIP Claim its Pro Rata share of participation in the Exit Credit Facility;
•Each holder of an Allowed Notes Claim received its pro rata share of 19,714,204 shares of New Common Stock, 54,967 shares of New Preferred Stock and New Unsecured Senior Notes.
•1,678,755 shares of New Common Stock were issued to the Disputed Claims reserve;
•Each holder of a broader rangeClass 4A Claim greater than the Convenience Claim Threshold received its pro rata share of reasonable119,679 shares of New Common Stock (which were issued to the Unsecured Claims Distribution Trust), $10 million in Cash, subject to adjustment by the Unsecured Claims Distribution Trustee, and supportable information to inform credit loss estimates. The measurement100% 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 collectibility of theMammoth Shares;
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reported amount. •Each holder of a Class 4B claim greater than the Convenience Claim Threshold received its pro rata share of 11,897 shares of New Common Stock, 33 shares of New Preferred Stock, the Rights Offering Subscription Rights and the Successor Senior Notes.
•Each holder of a Convenience Class Claim will share in a $3 million Cash distribution pool, which the Unsecured Claims Distribution Trustee may increase by an additional $2 million by reducing the Gulfport Parent Cash Pool;
•Each intercompany claim was cancelled on the Emergence Date and holders of intercompany interests received no recovery or distribution;
•The Company conducted a Rights Offering and issued 50,000 shares of New Preferred Stock at $1,000 per share to holders of claims against the Predecessor Subsidiaries, raising $50 million in proceeds. Additionally, 5,000 shares were issued to the Back Stop Commitment counterparties in lieu of cash consideration as per the Backstop Commitment Agreement.
•The Company adopted the new standard using the prospective transition method, and it did not have a material impactGulfport Energy Corporation 2021 Stock Incentive Plan (the "Incentive Plan") effective on the Emergence Date and reserved 2,828,123 shares of New Common Stock for issuance to Gulfport's employees and non-employee directors pursuant to equity incentive awards to be granted under the Incentive Plan.
Additionally, pursuant to the Plan confirmed by the Bankruptcy Court, the Company's post-emergence Board of Directors is comprised of five directors, including the Company's Interim Chief Executive Officer, Timothy Cutt, and four non-employee directors, David Wolf, Guillermo Martinez, Jason Martinez and David Reganato.
Executory Contracts
Subject to certain exceptions, under the Bankruptcy Code the Debtors were entitled to assume, assign or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and fulfillment of certain other conditions. Generally, the rejection of an executory contract was treated as a pre-petition breach of such contract and, subject to certain exceptions, relieved the Debtors from performing future obligations under such contract but entitled the counterparty to a pre-petition general unsecured claim for damages caused by such deemed breach. Alternatively, the assumption of an executory contract or unexpired lease required the Debtors to cure existing monetary defaults under such executory contract or unexpired lease, if any, and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease with the Debtors in this document, including where applicable quantification of the Company’s obligations under such executory or unexpired lease of the Debtors, is qualified by any overriding rejection rights the Company has under the Bankruptcy Code. Further, nothing herein is or shall be deemed an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and the Debtors expressly preserve all of their rights thereto. Refer to Note 9 for more information on potential future rejection damages related to general unsecured claims.
3.FRESH START ACCOUNTING
In connection with the Company's emergence from bankruptcy and in accordance with ASC 852, the Company qualified for and applied fresh start accounting on the Emergence Date. The Company qualified for fresh start accounting because (1) the holders of existing voting shares of the Company prior to the Emergence Date received less than 50% of the voting shares of the Successor's equity following its emergence from bankruptcy and (2) the reorganization value of the Company's assets immediately prior to confirmation of the Plan of approximately $2.3 billion was less than the post-petition liabilities and allowed claims of $3.1 billion.
In accordance with ASC 852, with the application of fresh start accounting, the Company allocated its reorganization value to its individual assets based on their estimated fair value in conformity with FASB ASC Topic 820 - Fair Value Measurements and FASB ASC Topic 805 - Business Combinations. Accordingly, the consolidated financial statements after May 17, 2021 are not comparable with the consolidated financial statements as of or prior to that date. The Emergence Date fair values of the Successor's assets and related disclosures.liabilities differ materially from their recorded values as reflected on the historical balance sheet of the Predecessor.
Reorganization Value
Reorganization value is derived from an estimate of enterprise value, or fair value of the Company's interest-bearing debt and stockholders' equity. Under ASC 852, reorganization value generally approximates fair value of the entity before considering liabilities and is intended to approximate the amount a willing buyer would pay for the assets immediately after the effects of a restructuring. As set forth in the disclosure statement, amended for updated pricing, and approved by the Bankruptcy Court, the enterprise value of the Successor was estimated to be between $1.3 billion and $1.9 billion. With the
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assistance of third-party valuation advisors, the Company determined the enterprise value and corresponding implied equity value of the Successor using various valuation approaches and methods, including: (i) income approach using a calculation of present value of future cash flows based on our financial projections, (ii) the market approach using selling prices of similar assets and (iii) the cost approach. Deferred income taxes were determined in accordance with FASB ASC Topic 740 - Income Taxes ("ASC 740"). For GAAP purposes, the Company valued the Successor's individual assets, liabilities and equity instruments and determined an estimate of the enterprise value within the estimated range. Management concluded that the best estimate of enterprise value was $1.6 billion. Specific valuation approaches and key assumptions used to arrive at reorganization value, and the value of discrete assets and liabilities resulting from the application of fresh start accounting, are described below in greater detail within the valuation process.
The enterprise value and corresponding implied equity value are dependent upon achieving the future financial results set forth in our valuation using an asset-based methodology of estimated proved reserves, undeveloped properties, and other financial information, considerations and projections, applying a combination of the income, cost and market approaches as of the fresh start reporting date of May 17, 2021. As estimates, assumptions, valuations and financial projections, including the fair value adjustments, the financial projections, the enterprise value and equity value projections, are inherently subject to significant uncertainties, the resolution of contingencies is beyond our control. Accordingly, there is no assurance that the estimates, assumptions, valuations or financial projections will be realized, and actual results could vary materially.
The following table reconciles the enterprise value to the implied fair value of the Successor's equity as of the Emergence Date:
Enterprise Value$1,600,000 
Plus: Cash and cash equivalents(1)
1,526 
Less: Fair value of debt(852,751)
Successor equity value(2)
$748,775 
(1) Restricted cash is not included in the above table.
(2) Inclusive of $55 million of mezzanine equity.
The following table reconciles the enterprise value to the reorganization value as of the Emergence Date:
Enterprise Value$1,600,000 
Plus: Cash and cash equivalents(1)
1,526 
Plus: Current and other liabilities686,489 
Plus: Asset retirement obligations19,084 
Less: Common stock reserved for settlement of claims post Emergence Date(54,109)
Reorganization value of Successor assets$2,252,990 
(1) Restricted cash is not included in the above table.
The fair values of our oil and natural gas properties, other property and equipment, derivative instruments, equity investments and asset retirement obligations were estimated as of the Emergence Date.
Oil and natural gas properties. The Company's principal assets are its oil and natural gas properties, which are accounted for under the full cost method of accounting. The Company determined the fair value of its oil and natural gas properties based on the discounted future net cash flows expected to be generated from these assets. Discounted cash flow models by operating area were prepared using the estimated future revenues and operating costs for all developed wells and undeveloped properties comprising the proved and unproved reserves. Significant inputs associated with the calculation of discounted future net cash flows include estimates of (i) recoverable reserves, (ii) production rates, (iii) future operating and development costs, (iv) future commodity prices escalated by an inflationary rate after seven years, adjusted for differentials and (v) a market-based weighted average cost of capital by operating area. The Company utilized NYMEX strip pricing, adjusted for differentials, to value the reserves. The NYMEX strip pricing inputs used are classified as Level 1 fair value assumptions and all other inputs are classified as Level 3 fair value assumptions. The discount rates utilized were derived using a weighted average cost of capital computation, which included an estimated cost of debt and equity for market participants with similar geographies and asset development type by operating area.
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Other property and equipment. The fair value of other property and equipment, such as land, buildings, vehicles, computer equipment and other equipment, was maintained at net book value as the carrying value reasonably approximated the fair value of the assets.
Asset retirement obligations. In accordance with FASB ASC Topic 410 - Asset Retirement and Environmental Obligations ("ASC 410"), the asset retirement obligations associated with the Company's oil and gas assets was valued using the income approach. The fair value of the Company’s asset retirement obligations was revalued based upon estimated current reclamation costs for our assets with reclamation obligations, updated estimates of timing of reclamation obligations, an appropriate long-term inflation adjustment, and the Company's revised credit adjusted risk-free rate. The credit adjusted risk-free rate was based on an evaluation of an interest rate that equates to a risk-free interest rate adjusted for the effect of the Company's credit standing.
Derivative Instruments. The fair value of derivative instruments was adjusted based on the change in the Company’s credit rating reflecting the Company’s credit standing at the Emergence Date.

Equity Investments. The fair value of the Company's investment in Grizzly Sands ULC was reduced by $27 million. The reduction in valuation was based upon the assessment of the investment by the Company's new management and its priority for future funding in its portfolio. In particular, Grizzly’s operations remained suspended, even with improvements in the pricing environment since its initial suspension in 2015. Additionally, the Company does not anticipate funding future capital calls which will lead to further dilution of its equity ownership interest.
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2.
Consolidated Balance Sheet
The following consolidated balance sheet is as of May 17, 2021. This consolidated balance sheet includes adjustments that reflect the consummation of the transactions contemplated by the Plan (reflected in the column “Reorganization Adjustments”) as well as fair value adjustments as a result of the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”) as of the Emergence Date. The explanatory notes following the table below provide further details on the adjustments, including the assumptions and methods used to determine fair value for its assets and liabilities.
As of May 17, 2021
PredecessorReorganization AdjustmentsFresh Start AdjustmentsSuccessor
(In thousands)
Assets
Current assets:
Cash and cash equivalents$146,545 $(145,019)(a)$0 $1,526 
Restricted cash057,891(b)057,891
Accounts receivable—oil and natural gas sales180,71100180,711
Accounts receivable—joint interest and other15,4310015,431
Prepaid expenses and other current assets86,189(60,894)(c)025,295
Short-term derivative instruments3,324—141(r)3,465
Total current assets432,200(148,022)141284,319
Property and equipment:
Oil and natural gas properties, full-cost method
Proved oil and natural gas properties9,558,1210(7,843,072)(s)1,715,049
Unproved properties1,375,6810(1,163,148)(s)212,533
Other property and equipment38,0260(31,133)(t)6,893
Total property and equipment10,971,8280(9,037,353)1,934,475
Accumulated depletion, depreciation and amortization(8,870,723)08,870,723(u)0
Total property and equipment, net2,101,1050(166,630)1,934,475
Other assets:
Equity investments27,0440(27,044)(v)0
Long-term derivative instruments7,4680715(w)8,183
Operating lease assets470047
Other assets18,8667,100(d)025,966
Total other assets53,4257,100(26,329)34,196
Total assets$2,586,730 $(140,922)$(192,818)$2,252,990 
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PredecessorReorganization AdjustmentsFresh Start AdjustmentsSuccessor
(In thousands)
Liabilities and Stockholders’ Equity (Deficit)
Current liabilities:
Accounts payable and accrued liabilities$384,200 $122,599 (e)$0 $506,799 
Short-term derivative instruments96,116 0 2,784 (x)98,900 
Current portion of operating lease liabilities0 38 (f)0 38 
Current maturities of long-term debt280,251 (220,251)(g)0 60,000 
Total current liabilities760,567 (97,614)2,784 665,737 
Non-current liabilities:
Long-term derivative instruments69,331 0 11,411 (y)80,742 
Asset retirement obligation0 65,341 (h)(46,257)(z)19,084 
Non-current operating lease liabilities0 9 (i)0 9 
Long-term debt, net of current maturities0 792,751 (j)0 792,751 
Total non-current liabilities69,331 858,101 (34,846)892,586 
Liabilities subject to compromise2,224,449 (2,224,449)(k)— — 
Total liabilities$3,054,347 $(1,463,962)$(32,062)$1,558,323 
Commitments and contingencies (Note 9)
0000
Mezzanine Equity:
New Preferred Stock— 55,000 (l)— 55,000 
Stockholders’ equity (deficit):
Predecessor common stock1,609 (1,609)(m)— — 
New Common Stock— 2 (n)— 2 
Additional paid-in capital4,215,838 (3,522,064)(o)0 693,774 
New Common Stock held in reserve0 (54,109)(p)0 (54,109)
Accumulated other comprehensive loss(40,430)40,430 (q)0 0 
Retained earnings (accumulated deficit)(4,644,634)4,805,390 (q)(160,756)(aa)0 
Total stockholders’ equity (deficit)$(467,617)$1,268,040 $(160,756)$639,667 
Total liabilities, mezzanine equity and stockholders’ equity (deficit)$2,586,730 $(140,922)$(192,818)$2,252,990 
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Reorganization Adjustments
(a)The table below reflects changes in cash and cash equivalents on the Emergence Date from implementation of the Plan:
Release of escrow funds by counterparties as a result of the Plan$63,068 
Preferred stock rights offering proceeds50,000 
Funds required to rollover the DIP Credit Facility and Pre-Petition Revolving Credit Facility into the Exit Facility(175,000)
Payment of accrued Pre-Petition Revolving Credit Facility and DIP Credit Facility interest(1,022)
Payment of issuance costs related to the Exit Credit Facility(10,250)
Funding of the Professional Fee Escrow(43,891)
Payment of professional fees at Emergence Date(7,964)
Transfer to restricted cash for the Unsecured Claims Distribution Trust(1,000)
Transfer to restricted cash for the Convenience Claims Cash Pool(3,000)
Transfer to restricted cash for the Parent Cash Pool(10,000)
Payment of severance costs at Emergence Date(5,960)
Net change in cash and cash equivalents$(145,019)
(b)Changes in restricted cash reflect the net effect of transfers from cash and cash equivalents for the Professional Fee Escrow and various claims class cash pools.
(c)Changes in prepaid expenses and other current assets include the following:
Release of escrow funds as a result of the Plan$(63,068)
Recognition of counterparty credits due to settlements effectuated at Emergence4,247 
Prepaid compensation earned at Emergence(2,073)
Net change in prepaid expenses and other current assets$(60,894)
(d)Changes in other assets were due to capitalization of debt issuance costs related to the Exit Credit Facility.
(e)Changes in accounts payable and accrued liabilities included the following:
Payment of accrued Pre-Petition Revolving Credit Facility and DIP Credit Facility interest$(1,022)
Payment of professional fees at emergence(7,964)
Accrued payable for claims to be settled via Unsecured Claims Distribution Trust1,000 
Accrued payable for claims to be settled via Convenience Claims Cash Pool3,000 
Accrued payable for claims to be settled via Parent Cash Pool10,000 
Professional fees payable at Emergence18,047 
Accrued payable for General Unsecured Claims against Gulfport Parent to be settled via 4A Claims distribution from common shares held in reserve23,894 
Accrued payable for General Unsecured Claims against Gulfport Subsidiary to be settled via 4B Claims distribution from common shares held in reserve30,216 
Reinstatement of payables due to Plan effects45,428 
Net change in accounts payable and accrued liabilities$122,599 
(f)Changes to current operating lease liabilities reflect the reinstatement of lease liabilities due to contract assumptions.
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(g)Changes in the current maturities of long-term debt include the following:
Current portion of Term Notes issued under the Exit Facility$60,000 
Payment of DIP Facility to effectuate Exit Facility(157,500)
Transfer of post-petition RBL borrowings to Exit Facility(122,751)
Net changes to current maturities of long-term debt$(220,251)
(h)Reflects the reclassification of asset retirement obligations from liabilities subject to compromise.
(i)Changes to non-current operating lease liabilities reflect the reinstatement of lease liabilities due to contract assumptions.
(j)Changes in long-term debt include the following:
Emergence Date draw on Exit Facility122,751 
Noncurrent portion of First-Out Term Loan issued under the Exit Credit Facility120,000 
Issuance of Successor Senior Notes550,000 
Net impact to long-term debt, net of current maturities$792,751 
(k)On the Emergence Date, liabilities subject to compromise were settled in accordance with the Plan as follows:
General Unsecured Claims settled via Class 4A, 4B, and 5B distributions$74,098 
Predecessor Senior Notes and associated interest1,842,035 
Pre-Petition Revolving Credit Facility197,500 
Reinstatement of Predecessor Claims as Successor liabilities45,475 
Reinstatement of Predecessor asset retirement obligations65,341 
Total liabilities subject to compromise settled in accordance with the Plan$2,224,449 
The resulting gain on liabilities subject to compromise was determined as follows:
Pre-petition General Unsecured Claims Settled at Emergence$74,098 
Predecessor Senior Notes Claims settled at Emergence1,842,035 
Pre-Petition Revolving Credit Facility197,500 
Rollover of Pre-Petition Revolving Credit Facility into Exit RBL Facility(197,500)
Accrued payable for claims to be settled via Unsecured Claims Distribution Trust(1,000)
Accrued payable for claims to be settled via Convenience Claims Cash Pool(3,000)
Accrued payable for claims to be settled via Parent Cash Pool(10,000)
Accrued payable for shares to be transferred to trust(54,109)
Issuance of New Common Stock to settle Predecessor liabilities(639,666)
Issuance of Successor Senior Notes in settlement of Class 4B and 5B claims(550,000)
Gain on settlement of liabilities subject to compromise$658,358 
(l)Changes to New Preferred Stock reflect the fair value of preferred shares issued in the Rights Offering.
(m)Changes in Predecessor common stock reflect the extinguishment of Predecessor equity as per the Plan.
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(n)Changes in New Common Stock included the following:
Issuance of common stock to settle General Unsecured Claims against Gulfport Parent (par value)$0 
Issuance of common stock to settle General Unsecured Claims against Gulfport Subsidiaries (par value)2 
Common stock reserved for settlement of claims post Emergence Date (par value)0 
Net change to New Common Stock$2 
(o)Changes to paid in capital included the following:
Issuance of common stock to settle General Unsecured Claims against Gulfport Parent$27,751 
Issuance of common stock to settle General Unsecured Claims against Gulfport Subsidiaries666,022 
Extinguishment of Predecessor stock based compensation4,419 
Extinguishment of Predecessor paid in capital(4,220,256)
Net change to paid in capital$(3,522,064)
(p)New Common Stock held in reserve to settle Allowed General Unsecured Claims include:
Shares held in reserve to settle Allowed Claims against Gulfport Parent(23,894)
Shares held in reserve to settle Allowed Claims against Gulfport Subsidiary(30,215)
Total New Common Stock held in reserve$(54,109)
(q)Change to retained earnings (accumulated deficit) included the following
Gain on settlement of liabilities subject to compromise$658,358 
Extinguishment of Predecessor common stock and paid in capital4,221,864 
Recognition of counterparty credits due to settlements effectuated at Emergence4,247 
Deferred compensation earned at Emergence(2,073)
Extinguishment of Predecessor accumulated other comprehensive income(40,430)
Write-off of debt issuance costs related to Exit Credit Facility Notes(3,150)
Severance costs incurred as a result of the Plan(5,961)
Professional fees earned at Emergence(18,047)
Rights offering backstop commitment fee(5,000)
Extinguishment of Predecessor stock based compensation(4,418)
Net change to retained earnings (accumulated deficit)$4,805,390 
Fresh Start Adjustments
(r)The change in fair value of short-term derivative instruments is due to the change in the Company's post-emergence credit rating.
(s)The change in oil and natural gas properties represents the fair value adjustment to the Company's properties due to the adoption of fresh start accounting.
(t)Predecessor accumulated depreciation and amortization for other property and equipment was net against the gross value of the assets with the adoption of fresh start accounting.
(u)Predecessor accumulated depreciation and amortization was eliminated with the adoption of fresh start accounting.
(v)The change in equity investments is due to the fair value adjustment to the Company's Grizzly investment.
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(w)The change in fair value of long-term derivative instruments is due to the change in the Company's post-emergence credit rating.
(x)The change in fair value of liabilities related to short-term derivative instruments is due to the change in the Company's post-emergence credit rating.
(y)The change in fair value of liabilities related to long-term derivative instruments is due to the change in the Company's post-emergence credit rating.
(z)The fair value of asset retirement obligation were reduced due to the change in the Company's credit adjusted risk-free rate and expected economic life estimates.
(aa)Changes to retained earnings represent the total impact of fresh start adjustments to the post-reorganization balance sheet.
Reorganization Items, Net
The Company has incurred significant expenses, gains and losses associated with the reorganization, primarily the gain on settlement of liabilities subject to compromise, provision for allowed claims and legal and professional fees incurred subsequent to the Chapter 11 filings for the restructuring process. The accrual for allowed claims primarily represents damages from contract rejections and settlements attributable to the midstream savings requirement as stipulated in the Plan. While the claims reconciliation process is ongoing, the estimate of liabilities related to the rejection of certain midstream contracts reflects the best estimate of the most probable outcomes of ongoing litigation and settlement negotiations. The amount of these items, which were incurred in reorganization items, net within the accompanying unaudited condensed consolidated statements of operations, have significantly affected the Company's statements of operations.
The following table summarizes the components in reorganization items, net included in the Company's unaudited consolidated statements of operations:
SuccessorPredecessor
Period from May 18, 2021 through June 30, 2021Period from April 1, 2021 through May 17, 2021Period from January 1, 2021 through May 17, 2021
Legal and professional advisory fees$0 $(40,782)$(81,565)
Net gain on liabilities subject to compromise0 571,032 575,182 
Fresh start adjustments, net0 (160,756)(160,756)
Elimination of predecessor accumulated other comprehensive income— (40,430)(40,430)
Debt issuance costs0 (3,150)(3,150)
Other items, net0 (20,297)(22,383)
Total reorganization items, net$0 $305,617 $266,898 
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4.PROPERTY AND EQUIPMENT
The major categories of property and equipment and related accumulated depletion, depreciation, amortization ("DD&A")&A and impairment as of June 30, 20202021 and December 31, 20192020 are as follows:
June 30, 2020December 31, 2019SuccessorPredecessor
(In thousands)June 30, 2021December 31, 2020
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  
Proved oil and natural gas propertiesProved oil and natural gas properties$1,737,778 $9,359,866 
Unproved propertiesUnproved properties224,214 1,457,043 
Other depreciable property and equipmentOther depreciable property and equipment91,317  91,198  Other depreciable property and equipment5,407 85,530 
LandLand5,521  5,521  Land1,507 3,008 
Accumulated DD&A(41,708) (36,703) 
Other property and equipment, net55,130  60,016  
Total property and equipmentTotal property and equipment1,968,906 10,905,447 
Accumulated DD&A and impairmentAccumulated DD&A and impairment(150,175)(8,819,178)
Property and equipment, netProperty and equipment, net$2,370,366  $3,463,794  Property and equipment, net$1,818,731 $2,086,269 

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 June 30, 2020,2021, the net book value of the Company's oil and gas properties less related deferred income taxes, was above the calculated ceiling primarily as a result of reduced commodity prices for the period leading up to June 30, 2020.2021. As a result, the Company was required to recordrecorded impairment of its oil and natural gas properties of $117.8 million for the Successor Period. NaN impairments were recorded in either of the Current Predecessor Quarter or the Current Predecessor YTD Period. The Company recorded an impairment of its oil and natural gas properties of $532.9 million and $1.1 billion for the three and six months ended June 30, 2020, 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 monthsPrior Predecessor Quarter and the short-term pricing outlook forPrior Predecessor YTD Period, respectively, as a result of the third quarter of 2020, the Company expects to recognize additional full cost impairmentssignificant decrease in the 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 production costs. Any future full cost impairments are not expected to have an impact to the Company's future cash flows or liquidity.prices.
GeneralCertain general and administrative costs are capitalized to the full cost pool and represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other costs associated with overseeing exploration and development activities. All general and administrative costs not directly associated with exploration and development activitiescapitalized are charged to expense as they are incurred. Capitalized general and administrative costs were approximately $2.2 million for the Successor Period, $2.5 million, for the Current Predecessor Quarter, and $8.0 million for Current Predecessor YTD Period. Capitalized general and administrative costs were approximately $8.2 million and $13.6 million for the three and six months ended June 30, 2020, respectively, and $8.8 million and $16.5 million for the three and six months ended June 30, 2019, respectively.
The average depletion rate per Mcfe, which is a function of capitalized costs, future development costsPrior Predecessor Quarter 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,Prior Predecessor YTD Period, respectively.
The following table summarizes the Company’s unevaluated properties excluded from amortization by area at June 30, 2020:
June 30, 2020
(In thousands)
Utica$874,886 
MidContinent687,169 
Other2,134 
$1,564,189 
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At December 31, 2019, approximately $1.7 billion of unevaluated properties were not subject to amortization.
The Company evaluates the costs excluded from its amortization calculation at least annually. Individually insignificant unevaluated properties are grouped for evaluation and periodically transferred to evaluated properties over a timeframe consistent with their expected development schedule.
Asset Retirement Obligation
A reconciliation ofThe following table summarizes the Company’s asset retirement obligation for the six months endedunevaluated properties excluded from amortization by area at June 30, 20202021:
Successor
June 30, 2021
(In thousands)
Utica$186,036 
SCOOP38,178 
Total unproved properties$224,214 
Impairment of Other Property and 2019 is as follows:Equipment
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
Sale of Water Infrastructure Assets
On January 2, 2020,During the Current Predecessor YTD Period, the Company closed on the salerecorded an impairment of $14.6 million related to 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 operationscorporate headquarters as a result of changes in the sale.

4.EQUITY INVESTMENTS
Investments accounted for by the equity method consist of the following as of June 30, 2020 and December 31, 2019:
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 June 30, 2020 and December 31, 2019.
Summarized balance sheet information:expected future use.
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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 results of operations: 
 Three months ended June 30,Six months ended June 30,
 2020201920202019
(In thousands)
Gross revenue$60,109  $179,114  $157,492  $443,958  
Net (loss) income$(14,922) $(4,072) $(99,953) $20,684  
Grizzly Oil Sands ULCAsset Retirement Obligation
The Company, through its wholly owned subsidiary Grizzly Holdings Inc. (“Grizzly Holdings”), owns an approximate 24.6% interest in Grizzly Oil Sands ULC (“Grizzly”),following table provides a Canadian unlimited liability company. The remaining interest in Grizzly is owned by Grizzly Oil Sands Inc. Asreconciliation of June 30, 2020, Grizzly had approximately 830,000 acres under lease in the Athabasca, Peace River and Cold Lake oil sands regions of Alberta, Canada. The Company reviewed its investment in Grizzly for impairment at June 30, 2020 and 2019 and determined 0 impairment was required. The Company paid $0.4 million in cash calls during the six months ended June 30, 2019 prior to its election to cease funding further capital calls. Grizzly’s functional currency is the Canadian dollar. The Company’s investment in Grizzly increased by $6.9 million as a result of a foreign currency translation gain and decreased by $7.8 million as a result of a foreign currency translation lossasset retirement obligation for the three and six months ended June 30, 2020, respectively. The Company's investment in Grizzly was increased by $3.5 million and $7.3 millionperiods presented:
Asset retirement obligation at January 1, 2021 (Predecessor)$63,566 
Liabilities incurred546 
Accretion expense1,229 
Ending balance as of May 17, 2021 (Predecessor)65,341 
Fresh start adjustments(1)
(46,257)
Asset retirement obligation at May 18, 2021 (Successor)19,084 
Liabilities incurred37 
Accretion expense226 
Asset retirement obligation at June 30, 2021$19,347 
(1) See Note 3 for the three and six months ended June 30, 2019, respectively, as a resultadditional discussion of a foreign currency translation gain.
Mammoth Energy Services, Inc.
At June 30, 2020, the Company 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, therefore, the Company's investment value remained at 0 at June 30, 2020.
The Company received 0 distributions from Mammoth Energy during the six months ended June 30, 2020 and distributions of $2.5 million during the six months ended June 30, 2019 as a result of $0.125 per share dividends in February 2019 and May 2019. The loss (income) from equity method investments presented in the table above reflects any intercompany profit eliminations.
Windsor Midstream LLC
At June 30, 2020, the Company held a 22.5% interest in Windsor Midstream LLC (“Midstream”), an entity controlled and managed by an unrelated third party. The Company received 0 distributions from Midstream during the six months ended June 30, 2020.
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Tatex Thailand II, LLC
The Company has an indirect ownership interest in Tatex Thailand II, LLC ("Tatex") and received 0 distributions and $2.1 million in distributions from Tatex during the six months ended June 30, 2020 and 2019, respectively. Tatex previously held an 8.5% interest in APICO, LLC (“APICO”), an international oil and gas exploration company, before selling its interest in June 2019. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately 108,000 acres which includes the Phu Horm Field.

fresh start adjustments.
5.LONG-TERM DEBT
Long-term debt consisted of the following items as of June 30, 20202021 and December 31, 2019:2020:
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  
SuccessorPredecessor
June 30, 2021December 31, 2020
Exit Facility$105,000 $0 
First-Out Term Loan180,000 0 
8.000% senior unsecured notes due 2026550,000 0 
DIP Credit Facility0 157,500 
Pre-petition revolving credit facility0 292,910 
6.625% senior unsecured notes due 20230 324,583 
6.000% senior unsecured notes due 20240 579,568 
6.375% senior unsecured notes due 20250 507,870 
6.375% senior unsecured notes due 20260 374,617 
Building loan0 21,914 
Debt issuance costs(1,153)0 
Total Debt833,847 2,258,962 
Less: current maturities of long-term debt(60,000)(253,743)
Less: amounts reclassified to liabilities subject to compromise0 (2,005,219)
Total Debt reflected as long term$773,847 $0 
(1) Successor Debt
Our post-emergence debt consists of the Exit Credit Facility and the Successor Senior Notes.
Exit Credit Facility
As discussed in Note 2, on the Emergence Date, pursuant to the terms of the Plan, the Company entered into the Exit Credit Agreement, which provides for (i) the Exit Facility in an aggregate principal amount of up to $1.5 billion and (ii) the First-Out Term Loan in an aggregate maximum amount of up to $180.0 million. The Exit Facility has an initial borrowing base and elected commitment amount of up to $580.0 million.
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The borrowing base will be redetermined semiannually on or around May 1 and November 1 of each year. The next scheduled redetermination will be on or around November 1, 2021.
Loans drawn under the Exit Facility will not be subject to amortization, while loans drawn under the First-Out Term Loan will amortize with $15.0 million quarterly installments, commencing on the closing date and occurring every three months after the closing date. The Exit Credit Facility matures on May 17, 2024.
The Exit Facility provides for a $150.0 million sublimit of the aggregate commitments that is available for the issuance of letters of credit. The Exit Facility also includes a $40 million availability blocker that remains in place until Successful Midstream Resolution (as defined in the Exit Credit Agreement), as discussed in Note 9.

The Exit Facility bears interest at a rate equal to, at the Company’s election, either (a) LIBOR plus an applicable margin that varies from 3.00% to 4.00% per annum or (b) a base rate plus an applicable margin that varies from 2.00% to 3.00% per annum. The First-Out Term Loan Facility bears interest at a rate equal to, at Gulfport’s election, either (a) LIBOR (subject to a 1.00% floor) plus 4.50% or (b) a base rate (subject to a 2.00% floor) plus 3.50%. As of June 30, 2021, the Exit Facility and the First-Out Term Loan Facility bore interest at weighted average rates of 4.50% and 5.50%, respectively.

The Company is required to pay a commitment fee of 0.50% per annum on the average daily unused portion of the current aggregate commitments under the Exit Facility and is also required to pay customary letter of credit and fronting fees.

The Exit Credit Agreement requires the Company to maintain (i) a net funded leverage ratio of less than or equal to 3.00 to 1.00, (ii) a net senior secured leverage ratio of less than or equal to 2.00 to 1.00, and (iii) a current ratio of greater than or equal to 1.00 to 1.00.
The Exit Credit Agreement also contains customary affirmative and negative covenants, including, among other things, as to compliance with laws (including environmental laws and anti-corruption laws), delivery of quarterly and annual financial statements and borrowing base certificates, conduct of business, maintenance of property, maintenance of insurance, restrictions on the incurrence of liens, indebtedness, asset dispositions, restricted payments, and other customary covenants.
Additionally, the Exit Credit Agreement contains customary events of default and remedies for credit facilities of this nature. If the Company does not comply with the financial and other covenants in the Exit Credit Agreement, the Lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Exit Credit Agreement and any outstanding unfunded commitments may be terminated.
The obligations under the Exit Credit Facility are guaranteed by the Company and the Guarantors (collectively, the “Loan Parties”) and secured by substantially all of the Loan Parties’ assets (subject to customary exceptions), including mortgages on at least 85% of the PV-10 of the borrowing base properties as set forth on the reserve report.
As of June 30, 2021, the Company had $105.0 million of outstanding borrowings under the Exit Facility, $180 million outstanding borrowings under the First-Out Term Loan and $114.8 million in letters of credit outstanding.
Successor Senior Notes
As discussed in Note 2, on the Emergence Date, pursuant to the terms of the Plan, the Company issued $550 million aggregate principal amount of its 8.000% senior notes due 2026.
The Successor Senior Notes are guaranteed on a senior unsecured basis by each of the Company's subsidiaries that guarantee the Exit Credit Facility.
The Successor Senior Notes were issued under the Indentures, dated as of May 17, 2021, by and among the Issuer, UMB Bank, National Association, as trustee, and the Guarantors.
Interest on the Successor Senior Notes will be payable semi-annually, on June 1 and December 1 of each year, commencing on December 1, 2021, to holders of record on the immediately preceding May 15 or November 15. Interest on the Successor Senior Notes will accrue from the most recent date to which interest has been paid or, if no interest has been paid, from May 17, 2021. Interest will be computed on the basis of a 360-day year of twelve 30-day months.
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The Successor Senior Notes are the Company’s senior unsecured obligations. Each guarantee of the Successor Senior Notes by a guarantor is a general, unsecured, senior obligation of such guarantor.
The covenants of the 1145 Indenture (other than the payment covenant) require that the Company comply with the covenants of the 4(a)(2) Indenture, as amended. The 4(a)(2) Indenture contains covenants limiting the Issuer’s and its restricted subsidiaries’ ability to (i) incur additional debt, (ii) pay dividends or distributions in respect of certain equity interests or redeem, repurchase or retire certain equity interests or subordinated indebtedness, (iii) make certain investments, (iv) create restrictions on distributions from restricted subsidiaries, (v) engage in specified sales of assets, (vi) enter into certain transactions among affiliates, (vii) engage in certain lines of business, (viii) engage in consolidations, mergers and acquisitions, (ix) create unrestricted subsidiaries and (x) incur or create liens. These covenants contain important exceptions, limitations and qualifications. At any time that the Successor Senior Notes are rated investment grade, certain covenants will be terminated and cease to apply.
Chapter 11 Proceedings - Predecessor Debt
Filing of the Chapter 11 Cases constituted an event of default with respect to certain of our secured and unsecured debt obligations. As a result of the Chapter 11 Cases, the principal and interest due under these debt instruments became immediately due and payable. However, Section 362 of the Bankruptcy Code stayed the creditors from taking any action as a result of the default.
The principal amounts from the Predecessor Senior Notes, Building Loan and Pre-Petition Revolving Credit Facility, other than letters of credit drawn on the Pre-Petition Revolving Credit Facility after the Petition Date, have been classified as liabilities subject to compromise on the accompanying consolidated balance sheet as of December 31, 2020.
Debtor-in-Possession Credit Agreement
Pursuant to the RSA, the Consenting RBL Lenders agreed to provide the Company with a senior secured superpriority debtor-in-possession revolving credit facility in an aggregate principal amount of $262.5 million consisting of (a) $105 million of new money and (b) $157.5 million to roll up a portion of the existing outstanding obligations under the Pre-Petition Revolving Credit Facility. The terms and conditions of the DIP Credit Facility are set forth in that certain form of credit agreement governing the DIP Credit Facility. The proceeds of the DIP Credit Facility were used for, among other things, post-petition working capital, permitted capital investments, general corporate purposes, letters of credit, administrative costs, premiums, expenses and fees for the transactions contemplated by the Chapter 11 Cases and payment of court approved adequate protection obligations. On the Emergence Date, the DIP Facility was terminated and the lenders indefeasibly converted into the Exit Facility. Each holder of an allowed DIP Claim received, in full and final satisfaction, settlement, release, and discharge of, and in exchange for, each Allowed DIP Claim its Pro Rata share of participation in the Exit Credit Facility.
Pre-Petition Revolving Credit Facility
Prior to the Emergence Date, the Company had entered into a senior secured revolving credit facility agreement, as amended, (the "revolving credit facility"), with The Bank of Nova Scotia, as the lead arranger and administrative agent and other lenders.certain lenders from time to time party thereto. The credit agreement provides forPre-Petition Revolving Credit Facility had a maximum facilityborrowing base of $1.5 billion$580 million. On the Emergence Date, the Pre-Petition Revolving Credit Facility was terminated and matures on December 13, 2021. On May 1, 2020, the Company enteredlenders indefeasibly converted into the fifteenth amendment to the Amended and RestatedExit Credit Agreement. As partFacility. Each holder of the amendment, the Company's borrowing base and elected commitment were reduced from $1.2 billion and $1.0 billion, respectively, to $700.0 million. Additionally, the amendment added a requirement to maintain a ratio of Net Secured Debt to EBITDAX (as definedan allowed claim under the revolving credit agreement) not exceeding 2.00 to 1.00, deferredPre-Petition Revolving Credit Facility received, in full and final satisfaction, settlement, release, and discharge of, and in exchange for, each Allowed DIP Claim its Pro Rata share of participation in 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.
On July 27, 2020, the Company entered into the sixteenth amendment to the Amended and RestatedExit 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 June 30, 2020, $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 $324.1 million letters of credit, was $252.9 million. The Company’s wholly owned subsidiaries have guaranteed the obligations of the Company under the revolving credit facility.
At June 30, 2020, amounts borrowed under the revolving credit facility bore interest at a weighted average rate of 2.44%.
The Company was in compliance with its financial covenants under the revolving credit facility at June 30, 2020.
(2) Loan issuance costs related to the 6.625% Senior Notes due 2023 (the "2023 Notes"), the 6.000% Senior Notes due 2024 (the "2024 Notes"), the 6.375% Senior Notes due 2025 (the "2025 Notes") and the 6.375% Senior Notes due 2026 (the "2026 Notes") (collectively the “Notes”) have been presented as a reduction to the principal amount of the Notes. At June 30, 2020, total unamortized debt issuance costs were $2.8 million for the 2023 Notes, $6.1 million for the 2024 Notes, $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 were $0.1 million at June 30, 2020.
The Company capitalized approximately $0.5 million and $0.7 million in interest expense to its unevaluated oil and natural gas properties during the three and six months ended June 30, 2020, respectively. The Company capitalized approximately $1.0Facility.
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Predecessor Senior Notes
On the Emergence Date, all outstanding obligations under the Predecessor Senior Notes were cancelled in accordance with the Plan and each holder of an allowed unsecured notes claim received their pro-rata share of 19.7 million shares of New Common Stock and $1.8$550 million of the Successor Senior Notes.
Predecessor Building Loan
In June 2015, the Company entered into a loan for the construction of the Company's corporate headquarters in Oklahoma City, which was substantially completed in December 2016. On the Emergence Date, ownership of the Company's corporate headquarters reverted to the Building Loan lender and the Company entered into a short-term lease agreement for the headquarters with the lender. As a result, the building loan liability was discharged as of the Emergence Date.
Capitalization of Interest
The Company did 0t capitalize interest expense for the Successor Period or the Current Predecessor YTD Period related to its unevaluated oil and natural gas properties and capitalized approximately $0.5 million and $0.7 million in interest expense during the threePrior Predecessor Quarter and six months ended June 30, 2019,the Prior Predecessor YTD Period, 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 open market at discounted values to par. The Company used borrowings under its revolving credit facility to repurchase in the open 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 included $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 the 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, 2020,2021, the carrying value of the outstanding debt represented by the Successor Senior Notes was approximately $1.8 billion.$548.8 million. Based on the quoted market prices (Level 1), the fair value of the Successor Senior Notes was determined to be approximately $930.2$592.6 million at June 30, 2020.

2021.
6.CHANGES IN CAPITALIZATIONEQUITY
As discussed in Note 2, on the Emergence Date, the Company filed an amended and restated certificate of incorporation with the Delaware Secretary of State to provide for, among other things, the authority to issue 42 million shares of New Common Stock Repurchaseswith a par value of $0.0001 per share and (ii) the designation of 110,000 shares of New Preferred Stock, with a par value of $0.0001 per share and a liquidation preference of $1,000 per share.
In January 2019,New Common Stock
On the Company's BoardEmergence Date, all existing shares of Directors approvedthe Predecessor's common stock were cancelled. The Successor issued approximately 19.8 million shares of New Common Stock and 1.7 million shares of New Common Stock were issued to the Disputed Claims reserve.
New Preferred Stock
On the Emergence Date, the Successor issued 55,000 shares of New Preferred Stock.
Holders of Preferred Stock are entitled to receive cumulative quarterly dividends at a stock repurchase programrate of 10% per annum of the Liquidation Preference (as defined below) with respect to acquirecash dividends and 15% per annum of the Liquidation Preference with respect to dividends paid in kind as additional shares of Preferred Stock (“PIK Dividends”). Gulfport must pay PIK Dividends for so long as the quotient obtained by dividing (i) Total Net Funded Debt (as defined in the Exit Credit Facility) by (ii) the last twelve (12) months of EBITDAX (as defined in the Exit Credit Facility) calculated as at the applicable record date is equal to or greater than 1.50. If such ratio is less than 1.50 such dividend may be paid in either cash or as PIK Dividends, subject to certain conditions under the Exit Credit Agreement.
Each holder of shares of Preferred Stock has the right (the “Conversion Right”), at its option and at any time, to convert all or a portion of the Company's outstanding common stock withinshares of Preferred Stock that it holds into a 24-month period. The program was suspendednumber of shares of Common Stock equal to the quotient obtained by dividing (x) the product obtained by multiplying (i) the Liquidation Preference times (ii) an amount equal to one (1) plus the Per Share Makewhole Amount (as defined in the fourth quarterPreferred Terms) on the date of 2019, andconversion, by (y) $14.00 per share (as may be adjusted under the May 1, 2020 amendmentPreferred Terms) (the “Conversion Price”).
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Following the Emergence Date, upon or after the payment of the First-Out Payment in Full (as defined in the Exit Credit Facility), Gulfport shall have the right, but not the obligation, to redeem all, but not less than all, of the outstanding shares of New Preferred Stock by notice to the Company's revolving credit facility prohibits further stock repurchases.
Forholders of New Preferred Stock, at the greater of (i) the aggregate value of the New Preferred Stock, calculated by the Current Market Price (as defined in the Preferred Terms) of the number of shares of Common Stock into which, subject to redemption, such New Preferred Stock would have been converted if such shares were converted pursuant to the Conversion Right at the time of such redemption and (ii) (y) if the date of such redemption is on or prior to the three year anniversary of the Emergence Date, the sum of the Liquidation Preference plus the sum of all unpaid PIK Dividends through the three year anniversary of the Emergence Date, or (x) if the date of such redemption is after the three year anniversary of the Emergence Date, the Liquidation Preference (the “Redemption Price”).
Following the Emergence Date, if there is a Fundamental Change (as defined in the Preferred Terms), Gulfport is required to, after the payment of the First-Out Payment in Full (as defined in the Exit Credit Facility) or to the extent not prohibited under the Exit Credit Facility, redeem all, but not less than all, of the outstanding shares of New Preferred Stock by cash payment of the Redemption Price per share of New Preferred Stock within three (3) business days of the occurrence of such Fundamental Change. Notwithstanding the foregoing, in the event of a redemption pursuant to the preceding sentence, if Gulfport lacks sufficient cash to redeem all outstanding shares of New Preferred Stock, the Company is required to redeem a pro rata portion of each holder’s shares of New Preferred Stock.
The New Preferred Stock has no stated maturity and six months endedwill remain outstanding indefinitely unless repurchased or redeemed by Gulfport or converted into Common Stock.
The New Preferred Stock has been classified as mezzanine equity in the accompanying consolidated balance sheets due to the redemption features noted above.
Dividends
On June 30, 2019,2021, the Company repurchased 0.2 millioncompany paid dividends on its New Preferred Stock, which included 1,006 shares of New Preferred Stock paid in kind and 3.8 million shares for a costapproximately $25 thousand of approximately $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 costcash-in-lieu of $28 thousand and $0.1 million, respectively, to satisfy tax withholding requirements incurred upon the vesting of restricted stock. During the three and six months ended June 30, 2019, the Company repurchased approximately 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 unissuedfractional shares.

7.STOCK-BASED COMPENSATION
As discussed in Note 2, on the Emergence Date, the Company's predecessor common stock was cancelled and New Common Stock was issued. Accordingly, the Company's then existing stock-based compensation awards were also cancelled, which resulted in the recognition of previously unamortized expense of $4.4 million related to the cancelled awards on the date of cancellation, which was included in reorganization items, net on the accompanying consolidated statements of operations. Stock-based compensation for the Predecessor and Successor periods are not comparable.
Successor Stock-Based Compensation
As of the Emergence Date, the Board of Directors adopted the Incentive Plan with a share reserve equal to 2,828,123 shares of New Common Stock. The Incentive Plan provides for the grant of incentive stock options, nonstatutory stock options, restricted stock, restricted stock units, stock appreciation rights, dividend equivalents and performance awards or any combination of the foregoing. NaN shares were granted under this plan as of June 30, 2021.
Predecessor 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 threeCurrent Predecessor Quarter and six months ended June 30, 2020,the Current Predecessor YTD Period, the Company’s stock-based compensation cost was $1.5 million and $4.4 million, respectively, of which the Company capitalized $0.3 million and $0.9 million, respectively, relating to its exploration and development efforts. During the Prior Predecessor Quarter and the Prior Predecessor YTD Period, the Company’s stock-based compensation cost was $2.2 million and $4.3 million, respectively, of which the Company capitalized $1.0 million and $1.9 million, respectively, relating to its exploration and development efforts. During the three and six months ended June 30, 2019, the Company’s stock-based compensation cost was $2.8 million and $5.6 million, respectively, of which the Company capitalized $1.1 million and $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 six months ended June 30, 2020:
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Number of
Unvested
Restricted Stock Units		Weighted
Average
Grant Date
Fair Value		Number of
Unvested
Performance Vesting Restricted Stock Units		Weighted
Average
Grant Date
Fair Value
Unvested shares as of January 1, 20204,098,318  $4.73  1,783,660  $2.96  
Granted1,985,452  0.67  —  —  
Vested(512,283) 7.19  —  —  
Forfeited(979,929) 3.82  (830,323) 1.98  
Unvested shares as of June 30, 20204,591,558  $3.00  953,337  $3.82  
The following table summarizes restricted stock unit activity for the Current Predecessor Quarter:
Number of
Unvested
Restricted Stock Units		Weighted
Average
Grant Date
Fair Value		Number of
Unvested
Performance Vesting Restricted Stock Units		Weighted
Average
Grant Date
Fair Value
Unvested shares as of April 1, 20211,480,223 $4.26 840,595 $4.07 
Granted0 0 0 0 
Vested(24,549)9.49 0 0 
Forfeited/canceled(1,455,674)4.17 (840,595)4.07 
Unvested shares as of May 17, 20210 $0 0 $0 
The following table summarizes restricted stock unit activity for the Current Predecessor YTD Period:
Number of
Unvested
Restricted Stock Units		Weighted
Average
Grant Date
Fair Value		Number of
Unvested
Performance Vesting Restricted Stock Units		Weighted
Average
Grant Date
Fair Value
Unvested shares as of January 1, 20211,702,513 $4.74 840,595 $4.07 
Granted0 0 0 0 
Vested(227,132)8.45 0 0 
Forfeited/canceled(1,475,381)4.16 (840,595)4.07 
Unvested shares as of May 17, 20210 $0 0 $0 
Predecessor Restricted Stock Units
Restricted stock units awarded under the 2019 Plan generally vestvested over a period of one year in the case of directors and three years in the case of employees and vesting iswas 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. UnrecognizedAll unrecognized compensation expense was recognized as of June 30, 2020 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.the Emergence Date.
Predecessor Performance Vesting Restricted Stock Units
The Company haspreviously awarded performance vesting restricted stock units to certain of its executive officers under the 2019 Plan. The number of shares of common stock issued pursuant to the award will bewas 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 willwere to 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. UnrecognizedAll unrecognized compensation expense was recognized as of June 30, 2020 related to performance vesting restricted shares was $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 1.62 years.Emergence Date.

8.EARNINGS (LOSS) PER SHARE
Reconciliations of the components of basic and dilutedBasic income or loss per share attributable to common stockholders is computed as (i) net income or loss less (ii) dividends paid to holders of New Preferred Stock less (iii) net income or loss attributable to participating securities divided by (iv) weighted average basic shares outstanding. Diluted net income or loss per share attributable to common share are presented in the tables below:stockholders is computed as (i) basic net income or loss attributable to common stockholders plus (ii) diluted adjustments to income allocable to participating securities divided by (iii) weighted average diluted shares outstanding. The "if-converted" method is used to
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Three months ended June 30,
 20202019
LossSharesPer
Share		IncomeSharesPer
Share
(In thousands, except share data)
Basic:
Net (loss) income$(561,068) 159,933,739  $(3.51) $234,956  159,324,909  $1.47  
Effect of dilutive securities:
Stock awards—  —  —  181,917  
Diluted:
Net (loss) income$(561,068) 159,933,739  $(3.51) $234,956  159,506,826  $1.47  
Six months ended June 30,
20202019
LossSharesPer
Share		IncomeSharesPer
Share
(In thousands, except share data)
Basic:
Net (loss) income$(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  

There were 1,281,773 and 1,610,572 shares of common stock that were considered anti-dilutivedetermine the dilutive impact for the threeCompany's convertible New Preferred Stock and six months ended June 30, 2020, respectively. the treasury stock method is used to determine the dilutive impact of unvested restricted stock.
There were 0 potential shares of common stock that were considered dilutive for the Successor Period, Current Predecessor Quarter, or the Current Predecessor YTD Period. There were 4.0 million shares of potential common shares issuable due to the Company's convertible New Preferred Stock that were considered anti-dilutive for the threeSuccessor Period due to the Company's net loss. There were 1.3 million and six months ended June 30, 2019.1.6 million potential shares of unvested restricted stock that were considered anti-dilutive for the Prior Predecessor Quarter and the Prior Predecessor YTD Period, respectively.

Reconciliations of the components of basic and diluted net (loss) income per common share are presented in the tables below:
SuccessorPredecessor
Period from May 18, 2021 through June 30, 2021Period from April 1, 2021 through May 17, 2021Three Months Ended June 30, 2020
Net (loss) income$(209,586)$242,214 $(561,068)
Dividends on New Preferred Stock(1,031)0 0 
Participating securities - New Preferred Stock(1)
0 0 0 
Net (loss) income attributable to common stockholders$(210,617)$242,214 $(561,068)
Basic Shares20,321 160,887 159,934 
Basic and Dilutive EPS$(10.36)$1.51 $(3.51)
SuccessorPredecessor
Period from May 18, 2021 through June 30, 2021Period from January 1, 2021 through May 17, 2021Six Months Ended June 30, 2020
Net income (loss) attributable to Gulfport$(209,586)$250,996 $(1,078,606)
Dividends on New Preferred Stock(1,031)0 0 
Participating securities - New Preferred Stock(1)
0 0 0 
Net (loss) income attributable to common stockholders$(210,617)$250,996 $(1,078,606)
Basic Shares20,321 160,834 159,847 
Basic and Dilutive EPS$(10.36)$1.56 $(6.75)
(1)
New Preferred Stock represents participating securities because they participate in any dividends on shares of common stock on a pari passu, pro rata basis. However, New Preferred Stock does not participate in undistributed net losses.
9.COMMITMENTS AND CONTINGENCIES
Commitments
Future Firm Transportation and Gathering Agreements
    The Company has contractual commitments with midstream and pipeline companies for future gathering and transportation of natural gas from the Company's producing wells to downstream markets. Under certain of these agreements, the Company has minimum daily volume commitments. The Company is also obligated under certain of these arrangements to pay a demand charge for firm capacity rights on pipeline systems regardless of the amount of pipeline capacity utilized by the Company. If the Company does not utilize the capacity, it often can release it to other counterparties, thus reducing the cost of these commitments. Working interest owners and royalty interest owners, where appropriate, will be responsible for their proportionate share of these costs. Commitments related to future firm transportation and gathering agreements are not
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recorded as obligations in the accompanying consolidated balance sheets; however, costs associated with utilized future firm transportation and gathering agreements are reflected in the Company's estimates of proved reserves.
A summary of these commitments at June 30, 2021 are set forth in the table below, excluding contracts in the process of being rejected as discussed in the Litigation and Regulatory Proceedings section below:
(In thousands)
Remaining 2021$112,881 
2022226,544 
2023224,737 
2024217,873 
2025139,124 
Thereafter1,013,822 
Total$1,934,981 
Future Firm Sales Commitments
The Company 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 haveoperated production has generally been sufficient to satisfy its delivery commitments during the three most recent years,periods presented, and it expects such reservesits operated production will continue to be the primary means of fulfilling its future commitments. However, where the Company's proved reserves areoperated production is not sufficient to satisfy its delivery commitments, it can and may use spot market purchases to satisfy the commitments.
A summary of these volume commitments at June 30, 20202021 are set forth in the table below:
(MMBtu per day)
Remaining 2020311,000  
2021192,000  
202270,000  
202317,000  
Total590,000
(MMBtu per day)
Remaining 202116,000 
20224,000 
20230 
20240 
20250 
Thereafter0 
Future Firm Transportation Commitments
The Company has contractual commitments with pipeline carriers for future transportation of natural gas from the Company's production areas to downstream markets. Commitments related to future firm transportation agreements are not
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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 1,455,000 MMBtu per day for the remainder of 2020 and 2021, respectively. Under these firm transportation contracts, the Company is obligated to deliver minimum daily volumes or pay fees for any deficiencies in deliveries. As a result of the reduced production from the Company's Utica Shale or SCOOP acreage due to decreased developmental activities, taking into consideration the current low commodity price environment, the Company expects that it will be unable to meet its obligations under the existing firm transportation contracts, resulting in fees, which may be significant and may have a material adverse effect on its operations.
Other Commitments
Effective October 1, 2014, the Company entered into a Sand Supply Agreement with Muskie Proppant LLC (“Muskie”), a subsidiary of Mammoth Energy and a related party. Pursuant to this agreement, as amended effective August 3, 2018, the Company agreed to purchase annual and monthly amounts of proppant sand subject to exceptions specified in the agreement at agreed pricing plus agreed costs and expenses through 2021. Failure by either Muskie or the Company to deliver or accept the minimum monthly amount results in damages calculated per ton based on the difference between the monthly obligation amount and the amount actually delivered or accepted, as applicable. The Company incurred $1.9 million and $3.8 million in non-utilization fees under this agreement during the three and six months ended June 30, 2020, respectively. The Company did not incur any non-utilization fees under this agreement during the three months ended June 30, 2019 and incurred $0.3 million of such fees during the six months ended June 30, 2019.
Future minimum commitments under this agreement at June 30, 2020 are:
(In thousands)
Remaining 2020$3,750  
20217,500  
Total$11,250  

Litigation and Regulatory Proceedings
The Company is involved in a number of litigation and regulatory proceedings including those described below. Many of these proceedings are in early stages, and many of them seek or may seek damages and penalties, the amount of which is 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. In accordance with ASC Topic 450, Contingencies, an accrual is recorded for a material loss contingency when its occurrence is probable and damages are reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes.

Litigation and Regulatory Proceedings
Commencement of the Chapter 11 Cases automatically stayed the proceedings and actions against us that are described below, in addition to actions seeking to collect pre-petition indebtedness or to exercise control over the property of the Company's bankruptcy estates.The Plan in the Chapter 11 Cases, which became effective on May 17, 2021, provided for the treatment of claims against the Company's bankruptcy estates, including pre-petition liabilities that had not been satisfied or addressed during the Chapter 11 Cases.
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As part of its Chapter 11 Cases and restructuring efforts as discussed in Note 2, the Company filed motions to reject certain firm transportation agreements between the Company and affiliates of TC Energy Corporation and Rover Pipeline LLC (the “Pending Motions to Reject”). The Pending Motions to Reject were removed to the United States District Court for the Southern District of Texas. While the Pending Motions to Reject are litigated, the Company isn’t required to perform under these firm transportation agreements.The Company believes that the Pending Motions to Reject will be ultimately granted, and that the Company does not have any ongoing obligations pursuant to the contracts; however, in the event that the Company is not permitted to reject these firm transportation contracts, it could be liable for demand charges, attorneys' fees and interest in excess of $80 million.

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 15th Judicial
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District of the State of Louisiana in the 15th Judicial District Court for the Parish of Vermilion on July 29, 2016 (together, the "Complaints"). The Complaints allege that certain of the defendants’ operations violated the State and Local Coastal Resources Management Act of 1978, as amended, and the rules, regulations, orders and ordinances adopted thereunder (the "CZM Laws") by causing substantial damage to land and waterbodies located in the coastal zone of the relevant Parish. The plaintiffs seek damages and other appropriate relief under the CZM Laws, including the payment of costs necessary to clear, re-vegetate, detoxify and otherwise restore the affected coastal zone of the relevant Parish to its original condition, actual restoration of such coastal zone to its original condition, and the payment of reasonable attorney fees and legal expenses and interest. The United States District Court for the Western District of Louisiana issued orders remanding the cases to their respective state court, and the defendants have appealed the remand orders to the 5th Circuit Court of Appeals.
In July 2019, Pigeon Land Company, Inc., a successor in interest to certain of the Company’s legacy Louisiana properties, filed an action against the Company and 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 Oklahoma. The complaint alleges, among other things, that the members of Mammoth Energy’s board of directors breached their fiduciary duties and violated the Securities Exchange Act of 1934, as amended, in connection with Mammoth Energy’s activities in Puerto Rico following Hurricane Maria. The complaint seeks unspecified damages, the payment of reasonable attorney fees and legal expenses and interest and to force Mammoth Energy and its board of directors to make specified corporate governance reforms.
In October 2019, Kelsie Wagner, in her capacity as trustee of various trusts and on behalf of the trusts and other similarly situated royalty owners, filed an action against the Company in the District Court of Grady County, Oklahoma.  The suit alleges that the Company underpaid royalty owners and seeks unspecified damages for violations of the Oklahoma Production Revenue Standards Act and fraud.
In March 2020, Robert F. Woodley, individually and on behalf of all others similarly situated, filed a federal securities class action against the Company, David M. Wood, Keri Crowell and Quentin R. Hicks in the United States District Court for the Southern District of New York. The complaint alleges that the Company made materially false and misleading statements regarding the Company’s business and operations in violation of the federal securities laws and seeks unspecified damages, the payment of reasonable attorneys’ fees, expert fees and other costs, pre-judgment and post-judgment interest, and such other and further relief that may be deemed just and proper.
In June 2020, Sam L. Carter, derivatively on behalf of the Company, filed an action against certain of our current and former executive officers and directors in the United States District Court for the District of Delaware. The complaint alleges that the defendants breached their fiduciary duties to the Company in connection with certain alleged materially false and misleading statements regarding our business and operations in violation of the federal securities laws. The complaint seeks to recover unspecified damages from the defendants, the implementation of specified corporate governance reforms, reasonable attorneys’ and experts’ fees, costs and expenses, and such other relief as may be deemed just and proper.

In December 2019, the Company filed a lawsuit against Stingray Pressure Pumping LLC, a subsidiary of Mammoth Energy (“Stingray”), for breach of contract and to terminate the Master Services Agreement for pressure pumping services, effective as of October 1, 2014, as amended (the “Master Services Agreement”), between Stingray and the Company. In March 2020, Stingray filed a counterclaim against the Company in the Superior Court of the State of Delaware. The counterclaim alleges that the Company has breached the Master Services Agreement. The counterclaim seeks actual damages, whichand Stingray filed claims in the Chapter 11 proceedings exceeding $80 million related to breach of contract damages, attorneys' fees and interest.
In August 2020, Muskie filed an action against the Company in the Superior Court of the State of Delaware for breach of contract. The complaint calculatesalleges that the Company breached its obligation to be approximately $28.0 millionpurchase a certain amount of proppant sand each month or make designated shortfall payments under the Sand Supply Agreement, effective October 1, 2014, as of June 2020 (such amount to increase each month)amended (the “Sand Supply Agreement”), between Muskie and the Company, and seeks payment of reasonable attorney feesunpaid shortfall payments, and legal expenses and pre- and post-judgment interest as allowed, and such other and further relief which it may be justly entitled.Muskie filed a claim in the Chapter 11 proceedings for $3.4 million.
In April 2020, Bryon Lefort, individually and on behalf of similarly situated individuals, filed an action against the Company in the United States District Court for the Southern District of Ohio Eastern Division. The complaint alleges that the Company violated the Fair Labor Standards Act (“FLSA”), the Ohio Wage Act and the Ohio Prompt Pay Act by classifying the plaintiffs as independent contractors and paying them a daily rate with no overtime compensation for hours worked in excess of 40 hours per week. The complaint seeks to recover unpaid regular and overtime wages, liquidated damages in an amount equal
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to 6 percent of all unpaid overtime compensation, the payment of reasonable attorney fees and legal expenses and pre-judgment and post-judgment interest, and such other damages that may be owed to the workers.
These cases are still in their early stages. As a result, the Company has not had the opportunity to evaluate the allegations madeworkers, and claims were filed in the plaintiffs' complaints and intends to vigorously defend the suits.Chapter 11 proceedings totaling $5.8 million.
SEC Investigation
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The SEC has commenced an investigationCompany, along with respectother oil and gas companies, have been named as a defendant in J&R Passmore, LLC, individually and on behalf of all others similarly situated, in the United States District Court for the Southern District of Ohio on December 6, 2018. Plaintiffs assert their respective leases are limited to certain actions by former Company management, including alleged improper personal usethe Marcellus and Utica Shale geological formations and allege that Defendants have willfully trespassed and illegally produced oil, natural gas, and other hydrocarbon products beyond these respective formations. Plaintiffs seek the full value of Company assets,any production from below the Marcellus and potential violations by former managementUtica shale formations, unspecified damages from the diminution of value to their mineral estate, unspecified punitive damages, and the Companypayment of the Sarbanes-Oxley Act of 2002 in connection with such actions. The Company has fully cooperatedreasonable attorney fees, legal expenses, 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.interest.
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. TheyGulfport and its subsidiaries have implemented various policies, programs, procedures, training and audits to reduce and mitigate environmental risks. They conductThe Company conducts 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 purchase of those assets. The sites were permitted utilizing the “permit by rule” regulation but actually required Title V air permits. The Company has agreed in a draft Consent Order to obtain the proper permits and to pay the costs from not having the proper permits in place in the amount of $180,000 to the ODEQ. The Order received final approval at the ODEQ and is expected to be finalized in the third quarter of 2020.
Other Matters
Based on management’s current assessment, they are of the opinion that no pending or threatened lawsuit or dispute relating to its business operations is likely to have a material adverse effect on their future consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.
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10.DERIVATIVE INSTRUMENTS
Natural Gas, Oil and Natural Gas Liquids Derivative Instruments
Gulfport has established policies and procedures for managing commodity price volatility through the use of derivative instruments. The Company seeks to reduce its exposuremitigate risks related to unfavorable changes in natural gas, oil and natural gas liquids ("NGL")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 contractsThe derivative instruments allow the Company to predict with greater certaintymitigate the effective natural gas, oil and NGLimpact of declines in future commodity prices to be receivedby effectively locking in a floor price for hedged production and benefit operating cash flows and earnings when market prices are less thana certain level of the fixed prices provided in the contracts.Company’s production. However, these instruments also limit future gains from favorable price movements. The volume of commodity derivative instruments utilized by the Company will not benefitmay vary from market prices that are higher than the fixed prices in the contracts for hedgedyear to year based on forecasted production.
Fixed price swaps are settled monthly based on differences between the fixed price specified in the contract and the referenced settlement price. When the referenced settlement price is less than the price specified in the contract, the Company receives an amount from the counterparty based on the price difference multiplied by the volume. Similarly, when the referenced settlement price exceeds the price specified in the contract, the Company pays the counterparty an amount based on the price difference multiplied by the volume. The prices contained in these fixed price swaps are based on the NYMEX Henry Hub for natural gas, the NYMEX West Texas IntermediateWTI for oil and Mont Belvieu for propane, pentane and ethane. Below is a summary of the Company’s open fixed price swap positions as of June 30, 2020.2021. 
LocationDaily Volume
(MMBtu/day)		Weighted
Average Price
Remaining 2020NYMEX Henry Hub357,000  $2.86  
LocationDaily VolumeWeighted
Average Price
Natural Gas (MMBtu/day)
Remaining 2021NYMEX Henry Hub221,500 $2.79 
2022NYMEX Henry Hub80,411 $2.80 
Oil (Bbl/day)
Remaining 2021NYMEX WTI3,250 $57.35 
2022NYMEX WTI1,000 $67.00 
NGL (Bbl/day)
Remaining 2021Mont Belvieu C33,100 $27.80 
2022Mont Belvieu C3496 $27.30 
LocationDaily Volume
(Bbls/day)		Weighted
Average Price
Remaining 2020NYMEX WTI3,000  $35.49  

LocationDaily Volume
(Bbls/day)		Weighted
Average Price
Remaining 2020Mont Belvieu C31,500  $20.27  
TheIn the second half of 2019, the Company sold 2022 and 2023 natural gas call options in exchange for a premium, and used the associated premiums to enhance the fixed price for a portion of the fixed priceon certain natural gas swaps primarily for 2020 listed above.that settled in 2020. Each call option has an established ceiling price. When the referenced settlement price isof $2.90/MMBtu. If monthly NYMEX natural gas prices settle above the price$2.90 ceiling established by these call options,price, the Company pays itsis required to pay the option counterparty an amount equal to the difference between the referenced NYMEX natural gas settlement price and the price ceiling$2.90 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  
Below is a summary of the Company's sold natural gas call option positions as of June 30, 2021.
LocationDaily VolumeWeighted Average Price
Natural Gas (MMBtu/day)
2022NYMEX Henry Hub152,675 $2.90 
2023NYMEX Henry Hub627,675 $2.90 
The Company entered into costless collars based off the NYMEX WTI and Henry Hub oil and natural gas index.indices. Each two-way price collar has a set floor and 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, the Company will cash-settle the difference with the hedge counterparty.
LocationDaily Volume (MMBtu/day)Weighted Average Floor PriceWeighted Average Ceiling Price
2021NYMEX Henry Hub250,000  $2.46  $2.81  
Below is a summary of the Company's costless collar positions as of June 30, 2021.
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LocationDaily VolumeWeighted Average Floor PriceWeighted Average Ceiling Price
Natural Gas (MMBtu/day)
Remaining 2021NYMEX Henry Hub575,000 $2.58 $2.97 
2022NYMEX Henry Hub406,747 $2.58 $2.91 
Oil (Bbl/day)
2022NYMEX WTI1,500 $55.00 $60.00 
In addition, the Company entered into natural gas basis swap positions. Ashedge contracts. If the applicable monthly price indices are outside of June 30, 2020,the ranges set forth in the various natural gas basis swap contracts, the Company hadwill cash-settle the followingdifference with the hedge counterparty.
Below is a summary of the Company's 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) 
19

During the three months endedas of 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.2021.
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.
Gulfport PaysGulfport ReceivesDaily VolumeWeighted Average Fixed Spread
Natural Gas (MMBtu/day)
Remaining 2021Rex Zone 3NYMEX Plus Fixed Spread66,576 $(0.16)
2022Rex Zone 3NYMEX Plus Fixed Spread24,658 $(0.10)
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 June 30, 20202021 and December 31, 2019:2020:
June 30, 2020December 31, 2019SuccessorPredecessor
(In thousands)June 30, 2021December 31, 2020
Commodity Contracts:
Short-term derivative assetShort-term derivative asset$53,188  $125,383  Short-term derivative asset$2,223 $27,146 
Long-term derivative assetLong-term derivative asset4,298  —  Long-term derivative asset3,014 322 
Short-term derivative liabilityShort-term derivative liability(8,540) (303) Short-term derivative liability(192,730)(11,641)
Long-term derivative liabilityLong-term derivative liability(45,615) (53,135) Long-term derivative liability(113,470)(36,604)
Total commodity derivative positionTotal commodity derivative position$3,331  $71,945  Total commodity derivative position$(300,963)$(20,777)
Contingent consideration arrangement:
Short-term derivative asset$—  $818  
Long-term derivative asset—  563  
Total contingent consideration derivative position$—  $1,381  
Total net asset derivative position$3,331  $73,326  
Gains and Losses
The following table presentstables present the gain and loss recognized in net (loss) gain on natural gas, oil and NGL derivatives in the accompanying consolidated statements of operations for the three and six months ended June 30, 2020 and 2019.operations:
Net (loss) gain on derivative instruments
SuccessorPredecessor
Period from May 18, 2021 through June 30, 2021Period from April 1, 2021 through May 17, 2021Three Months Ended June 30, 2020
Natural gas derivatives$(126,953)$(101,029)$35,689 
Oil derivatives$(5,357)$(4,395)$(7,937)
NGL derivatives$(7,348)$(1,837)$(781)
Total$(139,658)$(107,261)$26,971 
2037

Net gain (loss) on derivative instruments
Three months ended June 30,Six months ended June 30,Net (loss) gain on derivative instruments
2020201920202019SuccessorPredecessor
(In thousands)Period from May 18, 2021 through June 30, 2021Period from January 1, 2021 through May 17, 2021Six Months Ended June 30, 2020
Natural gas derivativesNatural gas derivatives$35,689  $152,475  $81,542  $136,044  Natural gas derivatives$(126,953)$(126,442)$81,542 
Oil derivativesOil derivatives(7,937) 11,871  44,937  11,417  Oil derivatives$(5,357)$(6,126)$44,937 
NGL derivativesNGL derivatives(781) 6,794  139  3,634  NGL derivatives$(7,348)$(4,671)$139 
Contingent consideration arrangementContingent consideration arrangement—  —  (1,381) —  Contingent consideration arrangement$0 $0 $(1,381)
TotalTotal$26,971  $171,140  $125,237  $151,095  Total$(139,658)$(137,239)$125,237 
Offsetting of Derivative Assets and Liabilities
As noted above, the Company records the fair value of derivative instruments on a gross basis. The following table presents the gross amounts of recognized derivative assets and liabilities in the consolidated balance sheets and the amounts that are subject to offsetting under master netting arrangements with counterparties, all at fair value.
As of June 30, 2020Successor
Gross Assets (Liabilities)Gross AmountsAs of June 30, 2021
Presented in theSubject to MasterNetGross Assets (Liabilities)Gross Amounts
Consolidated Balance SheetsNetting AgreementsAmountPresented in theSubject to MasterNet
(In thousands)Consolidated Balance SheetsNetting AgreementsAmount
Derivative assetsDerivative assets$57,486  $(48,761) $8,725  Derivative assets$5,237 $(5,237)$0 
Derivative liabilitiesDerivative liabilities$(54,155) $48,761  $(5,394) Derivative liabilities$(306,200)$5,237 $(300,963)
As of December 31, 2019Predecessor
Gross Assets (Liabilities)Gross AmountsAs of December 31, 2020
Presented in theSubject to MasterNetGross Assets (Liabilities)Gross Amounts
Consolidated Balance SheetsNetting AgreementsAmountPresented in theSubject to MasterNet
(In thousands)Consolidated Balance SheetsNetting AgreementsAmount
Derivative assetsDerivative assets$126,764  $(53,438) $73,326  Derivative assets$27,468 $(25,730)$1,738 
Derivative liabilitiesDerivative liabilities$(53,438) $53,438  $—  Derivative liabilities$(48,245)$25,730 $(22,515)
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 withspread between 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
The Company recordsmeasures and discloses certain financial and non-financial assets and liabilities on the balance sheet at fair value.value in accordance with the provisions of ASC Topic 820, Fair Value Measurements and Disclosures. Fair value is the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. Fair value measurements are classified and disclosed in one of the following categories:

Level 1 – Quoted prices in active markets for identical assets and liabilities.
Level 2 – Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active and model-derived valuations whose inputs are observable or whose significant value drivers are observable.
Level 3 – Significant inputs to the valuation model are unobservable.
Valuation techniques that maximize the use of observable inputs are favored. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter.
Financial assets and liabilities
The following tables summarize the Company’s financial and non-financial assets and liabilities by valuation level as of June 30, 20202021 and December 31, 2019:2020:
June 30, 2020
Level 1Level 2Level 3
(In thousands)
Assets:
Derivative Instruments$— $57,486 $— 
Liabilities:
Derivative Instruments$— $54,155 $— 
Successor
 June 30, 2021
Level 1Level 2Level 3
Assets:
Derivative Instruments$0 $5,237 $0 
Contingent consideration arrangement$0 $0 $6,500 
Total assets$0 $5,237 $6,500 
Liabilities:
Derivative Instruments$0 $306,200 $0 
December 31, 2019
Level 1Level 2Level 3
(In thousands)
Assets:
Derivative Instruments$— $126,764 $— 
Liabilities:
Derivative Instruments$— $53,438 $— 
Predecessor
 December 31, 2020
Level 1Level 2Level 3
Assets:
Derivative Instruments$0 $27,468 $0 
Contingent consideration arrangement$0 $0 $6,200 
Total assets$0 $27,468 $6,200 
Liabilities:
Derivative Instruments$0 $48,245 $0 

The Company estimates the fair value of all derivative instruments using industry-standard models that consider various assumptions, including current market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data.
As discussed in Note 3, the Company adjusted the fair value of its derivative instruments as a fresh start adjustment at the Emergence Date as a result of changes in the Company's credit adjustment to reflect its new credit standing at emergence.
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The Company's SCOOP water infrastructure sale, which closed in the first quarter of 2020, included a contingent consideration arrangement. As of June 30, 2020,2021, the fair value of the contingent consideration was $19.8$6.5 million, of which $0.8$0.5 million is included in prepaid expenses and other assets and $19.0$6.0 million is included in other assets in the accompanying consolidated balance sheets. The fair value of the contingent consideration arrangement is calculated using discounted cash flow techniques and is based on internal estimates of the Company's future development program and water production levels. Given the unobservable nature of the inputs, the fair value measurement of the contingent consideration arrangement is deemed to use Level 3 inputs. The Company has elected the fair value option for this contingent consideration arrangement and, therefore, records changes in fair value in earnings. The Company recognized a loss$1.1 million gain for the Successor Period and a nominal gain for the Current Predecessor Quarter and Current Predecessor YTD Period, respectively, which is included in other expense (income) in the accompanying consolidated statements of operations. The Company recognized losses of $3.2 million and $3.0 million on changes in fair value of the contingent consideration during the threePrior Predecessor Quarter and six months ended June 30, 2020, respectively, which is included in other expense (income) in
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the accompanying consolidated statements of operations.Prior Predecessor YTD Period, respectively. Settlements under the contingent consideration arrangement totaled $0.6 million during the Successor Period, $0.2 million during the Current Predecessor YTD Period, and $0.3 million during the six months ended June 30, 2020.Prior Predecessor YTD Period, respectively.
Non-financial assets and liabilities
The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 24 for further discussion of the Company’s asset retirement obligations. Asset retirement obligations incurred
As discussed in Note 4, the Company recorded an impairment during the six months ended June 30, 2020 were approximately $1.6 million.Current Predecessor YTD Period on its corporate headquarters. The estimated fair value of the building was primarily based on third party estimates and, therefore, is deemed to use Level 3 inputs.
Fair value of other financial instruments
The carrying amounts on the accompanying consolidated balance sheet for cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, and current debt are carried at cost, which approximates market value due to their short-term nature. Long-term debt related to the Company's constructionbuilding loan is carried at cost, which approximates market value based on the borrowing rates currently available to the Company with similar terms and maturities.
Chapter 11 Emergence and Fresh Start Accounting
On the Emergence Date, the Company adopted fresh start accounting, which resulted in the Company becoming a new entity for financial reporting purposes. Upon the adoption of fresh start accounting, the Company’s assets and liabilities were recorded at their fair values as of May 17, 2021. The inputs utilized in the valuation of the Company’s most significant asset, its oil and natural gas properties and related assets, included mostly unobservable inputs which fall within Level 3 of the fair value hierarchy. Such inputs included estimates of future oil and gas production from the Company’s reserve reports, commodity prices based on forward strip price curves (adjusted for basis differentials) as of May 17, 2021, operating and development costs, expected future development plans for the properties and discount rates based on a weighted-average cost of capital computation. The Company also recorded its asset retirement obligations at fair value as a result of fresh start accounting. The inputs utilized in valuing the asset retirement obligations were mostly Level 3 unobservable inputs, including estimated economic lives of oil and natural gas wells as of the Emergence Date, anticipated future plugging and abandonment costs and an appropriate credit-adjusted risk free rate to discount such costs. Refer to Note 3 for a detailed discussion of the fair value approaches used by the Company.
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
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contracts typically include variable consideration that is based on pricing tied to market indices and volumes delivered in the current month. As such, this market pricing may be constrained (i.e., not estimable) at the inception of the contract but will be recognized based on the applicable market pricing, which will be known upon transfer of the goods to the customer. The payment date is usually within 30 days of the end of the calendar month in which the commodity is delivered.
Gathering, processing and compression fees attributable to gas processing, as well as any transportation fees, including firm transportation fees, incurred to deliver the product to the purchaser, are presented as transportation, gathering, processing and compression expense in the accompanying consolidated statements of operations.
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$140.7 million and $121.2$119.9 million as of June 30, 20202021 and December 31, 2019,2020, 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,Current Predecessor YTD Period and the Successor Period, revenue recognized in the reporting periodperiods related to performance obligations satisfied in prior reporting periods was not material.
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13.EQUITY INVESTMENTS
Investments accounted for by the equity method consist of the following as of June 30, 2021 and December 31, 2020:
Carrying valueLoss from equity method investments
SuccessorPredecessorSuccessorPredecessorSuccessorPredecessor
June 30, 2021December 31, 2020Period from May 18, 2021 through June 30, 2021Period from April 1, 2021 through May 17, 2021Three months ended June 30, 2020Period from May 18, 2021 through June 30, 2021Period from January 1, 2021 through May 17, 2021Six months ended June 30, 2020
Investment in Grizzly Oil Sands ULC24.5 %$0 $24,816 $0 $0 $(45)$0 $(342)$(188)
Investment in Mammoth Energy0 %0 0 0 0 0 0 0 (10,646)
$0 $24,816 $0 $0 $(45)$0 $(342)$(10,834)
The tables below summarize financial information for the Company’s equity investments as of June 30, 2021 and December 31, 2020.
Summarized balance sheet information:
June 30, 2021December 31, 2020
(In thousands)
Current assets$462,478 $483,303 
Noncurrent assets$1,079,557 $1,092,495 
Current liabilities$125,359 $132,978 
Noncurrent liabilities$124,628 $148,240 
Summarized results of operations:    
 Three months ended June 30,Six months ended June 30,
 2021202020212020
(In thousands)
Gross revenue$66,805 $60,109 151,855 157,492 
Net loss$(13,606)$(14,922)(22,533)(99,953)
Grizzly Oil Sands ULC
The Company, through its wholly owned subsidiary Grizzly Holdings, owns an approximate 24.5% interest in Grizzly, a Canadian unlimited liability company. As of June 30, 2021, Grizzly had approximately 830,000 acres under lease in the Athabasca, Peace River and Cold Lake oil sands regions of Alberta, Canada. The Company reviewed its investment in Grizzly for impairment at June 30, 2021 and 2020 and determined 0 impairment was required. The Company has 0t paid any cash calls since its election to cease funding further capital calls in 2019. Grizzly’s functional currency is the Canadian dollar. The Company's investment in Grizzly increased by $6.9 million and decreased by $7.8 million as a result of foreign currency translation gains and losses for the Prior Predecessor Quarter and the Prior Predecessor YTD Period, respectively.
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Effective as of the Emergence Date, the Company elected to begin reporting its proportionate share of Grizzly's earnings on a one-quarter lag as permitted under FASB ASC Topic 323 - Equity Method and Joint Ventures. This change in accounting policy did not have a material impact on any periods presented in the accompanying consolidated financial statements.
As discussed in Note 3, the Company reduced its carrying value of its investment in Grizzly to 0 upon the Emergence Date. The reduction in valuation was based upon the Company's new management's assessment of the investment and its priority for future funding in its portfolio. In particular, Grizzly’s operations remained suspended, even with improvements in the pricing environment since its initial suspension in 2015. Additionally, the Company does not anticipate funding future capital calls which will lead to further dilution of our equity ownership interest.
Mammoth Energy Services, Inc.
As discussed in Note 2, the Company's previously owned shares of the outstanding common stock of Mammoth Energy were used to settle Class 4A claims. The Company's investment carrying value was reduced to 0 in the first quarter of 2020 due to the Company's share of cumulative net loss and impairments and the carrying value remained at 0 through the Emergence Date.
13.14.LEASES
Nature of Leases
The Company has operating leases associated with drilling rig commitments,on certain equipment and field offices and other equipment with remaining lease terms with contractual durations in excess of one year. The Company recognizes a right-of-use asset and lease liability on the balance sheet for all leases with lease terms of greater than one year. Short-term leases that have an initial term of one year or less are not capitalized.
The Company has entered into a contractcontracts with varying terms for a drilling rig with a third party to ensure rig availability.rigs. The CompanyCompany 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'sHowever, at June 30, 2021, the Company did not have any active long-term 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 volatilitycontracts 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.place.
The Company rents office space for its corporate headquarters and 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. The lease for the Company's corporate headquarters has a primary term of one year and is classified as a short-term operating lease.
Discount Rate
As most of the Company's leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The Company's incremental borrowing rate reflects the estimated rate of interest that it would pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment.
Maturities of operating lease liabilities as of June 30, 2021 were as follows:
(In thousands)
Remaining 2021$20 
202225 
20230 
20240 
Total lease payments$45 
Less: Imputed interest(1)
Total$44 
24
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Maturities of operatingThe table below summarizes 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 three and six months ended June 30, 2020 and 2019 consisted of the following:periods presented:
Three months ended June 30,Six months ended June 30,
2020201920202019SuccessorPredecessor
(In thousands)Period from May 18, 2021 through June 30, 2021Period from April 1, 2021 through May 17, 2021Three months ended June 30, 2020
Operating lease costOperating lease cost$2,196  $7,748  $6,278  $16,284  Operating lease cost$8 $9 $2,196 
Operating lease cost—related party—  5,610  —  11,220  
Variable lease costVariable lease cost235  531  460  960  Variable lease cost$0 $0 $235 
Variable lease cost—related party—  28,158  —  59,611  
Short-term lease costShort-term lease cost2,629  183  5,439  183  Short-term lease cost$2,160 $2,307 $2,629 
Total lease cost(1)
Total lease cost(1)
$5,060  $42,230  $12,177  $88,258  
Total lease cost(1)
$2,168 $2,316 $5,060 
SuccessorPredecessor
Period from May 18, 2021 through June 30, 2021Period from January 1, 2021 through May 17, 2021Six months ended June 30, 2020
Operating lease cost$8 $41 $6,278 
Variable lease cost$0 $0 $460 
Short-term lease cost$2,160 $4,496 $5,439 
Total lease cost(1)
$2,168 $4,537 $12,177 
(1)The majority of the Company's total lease cost was capitalized to the full cost pool, and the remainder was included in general and administrative expenses in the accompanying consolidated statements of operations.
Supplemental cash flow information for the six months ended June 30, 2020 and 2019 related to leases was as follows:
Six months ended June 30,SuccessorPredecessor
20202019Period from May 18, 2021 through June 30, 2021Period from January 1, 2021 through May 17, 2021Six months ended June 30, 2020
Cash paid for amounts included in the measurement of lease liabilitiesCash paid for amounts included in the measurement of lease liabilities(In thousands)Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases Operating cash flows from operating leases$72  $120   Operating cash flows from operating leases$15 $48 $72 
Investing cash flow from operating leases Investing cash flow from operating leases$7,727  $12,288   Investing cash flow from operating leases$0 $0 $7,727 
Investing cash flow from operating leases—related party Investing cash flow from operating leases—related party$6,800  $43,925   Investing cash flow from operating leases—related party$0 $0 $6,800 
The weighted-average remaining lease term as of June 30, 20202021 was 0.831.14 years. The weighted-average discount rate used to determine the operating lease liability as of June 30, 20202021 was 2.47%3.98%.
15.INCOME TAXES
As discussed in Note 2, elements of the Plan provided that the Company’s indebtedness related to Predecessor Senior Notes and certain general unsecured claims were exchanged for New Common Stock in settlement of those claims. Absent an exception, a debtor recognizes CODI upon discharge of its outstanding indebtedness for an amount of consideration that is less than its adjusted issue price. The IRC provides that a debtor in a Chapter 11 bankruptcy case may exclude CODI from taxable income, but must reduce certain of its tax attributes by the amount of any CODI realized as a result of the consummation of a plan of reorganization. The amount of CODI realized by a taxpayer is determined based on the fair market value of the consideration received by the creditors in settlement of outstanding indebtedness. As a result of the market value of equity upon emergence from Chapter 11 bankruptcy proceedings, the estimated amount of CODI is approximately $708.8 million, which will reduce the value of the Company’s net operating losses. The actual reduction in tax attributes does not occur until the first day of the Company’s tax year subsequent to the date of emergence, or January 1, 2022. The reduction of net operating losses is expected to be fully offset by a corresponding decrease in valuation allowance. As of June 30, 2021, the Company had an estimated federal net operating loss carryforward of approximately $1.1 billion after giving effect to the estimated reduction in tax attributes as discussed above.
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14.INCOME TAXES
Emergence from Chapter 11 bankruptcy proceedings resulted in a change in ownership for purposes of IRC Section 382. The Company records its quarterly tax provision based on an estimate of the annual effective tax rate expectedcurrently expects to apply rules under IRC Section 382(l)(5) that would allow the Company to continuing operations formitigate the various jurisdictions in which it operates.limitations imposed under the regulations with respect to the Company’s remaining tax attributes. 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 itsCompany’s deferred tax assets. During the first quarter of 2020, the Company recognized $7.3 million of income tax expense discretely in the quarter as a result of the sale of assets and a corresponding adjustmentliabilities, prior to the valuation allowance, have been computed on remaining state net operating loss carryforwards.such basis. Taxpayers who qualify for this provision may, at their option, elect not to apply the election. If the provision does not apply, the Company’s ability to realize the value of its tax attributes would be subject to limitation and the amount of deferred tax assets and liabilities, prior to the valuation allowance, may differ. Additionally, under IRC Section 382(l)(5), an ownership change subsequent to the Company’s emergence could severely limit or effectively eliminate its ability to realize the value of its tax attributes.

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

On March 27, 2020, Based upon the CARES ActCompany’s analysis, the Company determined a full valuation allowance 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 onnecessary against its ability to realizednet deferred tax assets.assets as of both May 17, 2021 and June 30, 2021.

The Company’s abilityCompany will continue to utilize NOL carryforwards and other tax attributes to reduceevaluate whether the valuation allowance is needed in future federal taxable income is subject to potential limitations under Internal Revenue Code Section 382 (“Section 382”) and its related tax regulations.reporting periods. The utilization of these attributes may be limited if certain ownership changes by 5% stockholders (as defined in Treasury regulations pursuant to Section 382) and the effects of stock issuances by the Company during any three-year period result in a cumulative change of more than 50% in the beneficial ownership of Gulfport. The Company updates its Section 382 analysis to determine if an ownership change has occurred at each reporting period. Ifvaluation allowance will remain until it is determined that an ownership change has occurred under these rules,the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead us to conclude that it is more likely than not that its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in oil prices, and taxable events that could result from one or more transactions. The valuation allowance does not prevent future utilization of the tax attributes if the Company would generally be subject to an annual limitation onrecognizes taxable income. As long as the use of pre-ownership change NOL carryforwards and certain other losses and/or credits. In addition, certain future transactions regardingCompany concludes that 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 ofvaluation allowance against its net deferred tax assets. On April 30, 2020, the board of directors ofassets is necessary, the Company adopted a tax benefits preservation plan in order to protect against a possible limitation on the Company’s ability to use its tax net operating losses and certain other tax benefits to reduce potential future U.S. federallikely will not have any additional deferred income tax obligations. The Tax Benefits Preservation Plan is intended to prevent against such an ownership change by deterring any personexpense or group from acquiring beneficial ownership of 4.9% or more of the Company’s securities.
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15.CONDENSED CONSOLIDATING FINANCIAL INFORMATION
The 2023 Notes, the 2024 Notes, the 2025 Notes and the 2026 Notes are guaranteed on a senior unsecured basis by all existing consolidated subsidiaries that guarantee the Company’s secured revolving credit facility or certain other debt (the “Guarantors”). The Notes are not guaranteed by Grizzly Holdings or Mule Sky LLC ("Mule Sky") (the “Non-Guarantors”). The Guarantors are 100% owned by Gulfport (the “Parent”), and the guarantees are full, unconditional, joint and several. There are no significant restrictions on the ability of the Parent or the Guarantors to obtain funds from each other in the form of a dividend or loan. Effective June 1, 2019, the Parent contributed interests in certain oil and gas assets and related liabilities to certain of the Guarantors.
The following condensed consolidating balance sheets, statements of operations, statements of comprehensive income and statements of cash flows are provided for the Parent, the Guarantors and the Non-Guarantors and include the consolidating adjustments and eliminations necessary to arrive at the information for the Company on a condensed consolidated basis. The information has been presented using the equity method of accounting for the Parent’s ownership of the Guarantors and the Non-Guarantors.benefit.

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For the Current Predecessor Quarter and Current Predecessor YTD Period, the Company has an effective tax rate of (3.3)% and an income tax benefit of $8.0 million. The tax benefit is entirely attributable to an Oklahoma refund claim associated with an examination relating to historical tax returns. The effective tax rate differs from the statutory tax rate due to the Company’s valuation allowance position and the permanent adjustments relating to the Chapter 11 Emergence. For the Successor Period, the Company has an effective tax rate of 0% and tax expense of 0 due to the Company’s valuation allowance position. For the Prior Predecessor Quarter, the Company had an effective tax rate of 0% and tax expense of 0 due to the Company’s valuation allowance position. For the Prior Predecessor YTD Period, the Company had an effective tax rate of 0.7% and tax expense of $7.3 million as a result of the sale of assets and a corresponding adjustment to the valuation allowance on remaining state net operating loss carryforwards.
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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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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  
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CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(Amounts in thousands)
Three months ended June 30, 2020
ParentGuarantorsNon-GuarantorsEliminationsConsolidated
Total revenues$26,970  $105,440  $—  $—  $132,410  
Costs and expenses:
Lease operating expenses—  15,686  —  —  15,686  
Production taxes—  3,605  —  —  3,605  
Midstream gathering and processing expenses—  59,974  —  —  59,974  
Depreciation, depletion and amortization2,388  62,236  166  —  64,790  
Impairment of oil and natural gas properties—  532,880  —  —  532,880  
General and administrative expenses21,731  (11,374) 113  —  10,470  
Accretion expense—  755  —  —  755  
Total Operating Expenses24,119  663,762  279  —  688,160  
INCOME (LOSS) FROM OPERATIONS2,851  (558,322) (279) —  (555,750) 
OTHER EXPENSE (INCOME):
Interest expense32,825  (459) —  —  32,366  
Interest income(28) (50) —  —  (78) 
Gain on debt extinguishment(34,257) —  —  —  (34,257) 
Loss from equity method investments and investments in subsidiaries562,502  —  45  (562,502) 45  
Other expense2,877  4,365  —  —  7,242  
Total Other Expense563,919  3,856  45  (562,502) 5,318  
LOSS BEFORE INCOME TAXES(561,068) (562,178) (324) 562,502  (561,068) 
INCOME TAX EXPENSE—  —  —  —  —  
NET LOSS$(561,068) $(562,178) $(324) $562,502  $(561,068) 

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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  

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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) 

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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  

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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  
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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  
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16.SUBSEQUENT EVENTS
AmendmentNatural Gas and Oil Derivative Instruments
Subsequent to Credit FacilityJune 30, 2021 and as of July 31, 2021, the Company entered into the following natural gas and oil derivative contracts:
Type of Derivative InstrumentIndexDaily VolumeWeighted
Average Price
Natural Gas (MMBtu/day)
April 2022 - December 2022Fixed price swapNYMEX Henry Hub80,073 $2.99
January 2023 - March 2023Fixed price swapNYMEX Henry Hub20,000 $3.13
Oil (Bbl/day)
January 2022 - December 2022Fixed price swapNYMEX WTI1,104 $65.54

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

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%

Derivatives
In August 2020, the Company 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.
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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’sIntroduction
Management's Discussion and Analysis of Financial Condition and Results of Operations” sectionOperations (MD&A) is intended to provide the reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and audited consolidatedcertain other factors that may affect the Company's operating results. MD&A should be read in conjunction with the financial statements and related notesNotes included in our Annual Report on Form 10-K and with the unaudited consolidated financial statements and related notes thereto presented inPart I, Item 1 of this Quarterly Report on Form 10-Q.

Cautionary Note Regarding Forward-Looking Statements
This Form 10-Q may include forward-looking statements withinThe following information updates the meaningdiscussion of Section 27A of the Securities Act of 1933, as amended (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 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, includedGulfport’s financial condition provided in this Form 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 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 our expectations and beliefs 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 that 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 the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed in Item 1A. “Risk Factors” in ourits Annual Report on Form 10-K for the year ended December 31, 20192020 (“2020 Form 10-K”), and elsewhereanalyzes the changes in this Form 10-Q. All forward-looking statements speak only asthe results of operations between the dateperiods of this Form 10-Q.
All forward-looking statements, expressed or implied, includedMay 18, 2021 through June 30, 2021 (“Successor Period”), April 1, 2021 through May 17, 2021 ("Current Predecessor Quarter"), January 1, 2021, through May 17, 2021 (“Current Predecessor YTD Period”), the three months ended June 30, 2020 (“Prior Predecessor Quarter”) and the six months ended June 30, 2020 ("Prior Predecessor YTD Period"). For definitions of commonly used natural gas and oil terms found in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report.

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

10-Q, please refer to the “Definitions” provided in this report and in our 2020 Form 10-K.
Overview
We areGulfport is an independent natural gas-weighted exploration and production company focused on the exploration, acquisition and production of natural gas, crude oil and natural gas liquids ("NGL")with assets primarily located in the United States with primary focus in the
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Appalachia and Mid-ContinentAnadarko basins. Our principal properties are located in Eastern Ohio targeting the Utica formation and in central Oklahoma targeting the SCOOP Woodford and SCOOP Springer formations. Our strategy is to develop our assets in a manner that generates sustainable cash flow and improves margins and operating efficiencies, while improving our Environmental, Social and Governance ("ESG") and safety performance. To accomplish these goals, we allocate capital to projects we believe offer the highest rate of return and we deploy leading drilling and completion techniques and technologies in our development efforts. We believe our plan to generate free cash flow on an annual basis will allow us to further strengthen our balance sheet and ultimately return capital to shareholders.
Our results of operations as reported in our consolidated financial statements for the 2021 Successor Period, Current Predecessor Quarter and Current Predecessor YTD Period are in accordance with GAAP. Although GAAP requires that we report on our results for these periods separately, management views our operating results for the three months and six months ended June 30, 2021 by combining the results of the 2021 Successor Period, Current Predecessor Quarter and Current Predecessor YTD Period because management believes such presentation provides the most meaningful comparison of our results to prior periods. We do not believe reviewing these periods in isolation would be useful in identifying any trends in or reaching any conclusions regarding our overall operating performance. We believe the key performance indicators such as operating revenues and operating expenses for the 2021 Successor Period combined with Current Predecessor Quarter and Current Predecessor YTD period provide more meaningful comparisons to other periods and are useful in understanding operational trends. Additionally, there were no changes in policies between the periods and any material impacts as a result of fresh start accounting were included within the discussion of these changes. These combined results do not comply with GAAP and have not been prepared as pro forma results under applicable regulations, but are presented because we believe they provide the most meaningful comparison of our results to prior periods.
Recent Developments
Emergence from voluntary reorganization under Chapter 11
On November 13, 2020, we and our subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the Southern District of Texas. The Chapter 11 Cases were being administered jointly under the caption In re Gulfport Energy Corporation, et al., Case No. 20-35562 (DRJ). The Bankruptcy Court confirmed the Plan and entered the confirmation order on April 28, 2021, and the Debtors emerged from the Chapter 11 Cases on the Emergence Date. On May 18, 2021, we began trading on the New York Stock Exchange under the symbol "GPOR".

Although we are no longer a debtor-in-possession, we operated as debtors-in-possession through the pendency of the Chapter 11 Cases. See Note 1 and Note 2 of the notes to our consolidated financial statements included in Item 1 of Part I of this report for a complete discussion of the Chapter 11 Cases.
COVID-19
In March 2020,We believe we have emerged from the World Health Organization classified the outbreak of COVID-19Chapter 11 Cases as a pandemic and recommended containment and mitigation measures worldwide. The measures have ledfundamentally stronger company, built to worldwide shutdowns and haltinggenerate sustainable free cash flow with a strengthened balance sheet. As a result of commercial and interpersonal activity, as governments around the world imposed regulationsChapter 11 Cases, we reduced our total
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indebtedness by $1.4 billion by issuing equity in effortsa reorganized entity 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-beingholders of our employeesunsecured notes and the communities in which we operate while assuring the continuity of our business operations. We have implemented preventative measuresallowed general unsecured claimants.

Chief Executive Officer 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.Chief Financial Officer Separations
On May 18, 2020, we began our phased transition back to17, 2021, the office for our corporate employees. As part of this transition, we have put into place preventative measures to focus on social distancingBoard reached agreements with David M. Wood and minimizing unnecessary risk of exposure. Such measures include, but are not limited to, daily health surveys, protective masks in public areasQuentin R. Hicks that Messrs. Wood and Hicks would no longer serve as Chief Executive Officer and a member of the building, no outside visitors, limitingBoard, in the numbercase of employees on elevators, additional sanitizingMr. Wood, and 100%Chief Financial Officer, in the case of Mr. Hicks.

Appointments of Interim Chief Executive Officer and Chief Financial Officer

On May 17, 2021, the Board accepted the departure of David M. Wood as Chief Executive Officer and Director. The Board appointed Timothy Cutt as Interim Chief Executive Officer and Chair of the corporate employees working remotelyBoard. Mr. Cutt is generally expected to serve as Interim Chief Executive Officer until December 31, 2021.

On May 17, 2021, the Board appointed William Buese as Chief Financial Officer.

COVID-19 Pandemic and Impact on Fridays to provide additional timeGlobal Demand 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 trendsOil and governmental guidelines and may adjust our return to office plans accordingly to ensure the health and safety of our employees.Natural Gas

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.due to COVID-19. While we havedid not experiencedexperience significant disruptions to our operations in 2020,the first half of 2021, 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 and reliability of service providers and potential supply chain disruption. TheAdditionally, 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 discussionWhile we have seen meaningful recovery in demand during the second half 2020 and into 2021, significant uncertainty remains 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 teamduration 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 resultextent 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 stateimpact 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 foreclosurepandemic on the collateral securing such debt,energy industry, including demand and could cause a cross-default under our other outstanding indebtedness.commodities pricing.
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.
20202021 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,Current Combined Quarter, 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.Emerged from Chapter 11 proceedings.
•ContinuedWe 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 18.518.1 days in the first half of 2020,Current Combined Quarter, which was a 6%3% 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 20192020 levels.
•Closed on the saleWe have continued to decrease costs as a result of our SCOOP water infrastructure assets on January 2, 2020. We received $50.0 millionongoing cost reduction initiatives highlighted by a 13% decrease in cash upon closing and have an opportunitylease operating expenses per Mcfe for the Current Combined Quarter as compared to earn additional incentive payments over the next 15 years, subject to ourPrior Predecessor Quarter.

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ability to meet certain thresholds which will be driven by, among other things, our future development program and future water production levels. Proceeds from the divestiture were used to reduce our outstanding revolver balance.


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20202021 Production and Drilling Activity
Production Volumes
Three months ended June 30,
2020% of Total2019% of TotalChange% ChangeSuccessorPredecessorNon-GAAP CombinedPredecessor
($ In thousands)Period from May 18, 2021 through June 30, 2021Period from April 1, 2021 through May 17, 2021Three Months Ended June 30, 2021Three Months Ended June 30, 2020
Natural gas (Mcf/day)Natural gas (Mcf/day)Natural gas (Mcf/day)
Utica Shale775,070  83 %1,014,302  83 %(239,232) (24)%
UticaUtica691,876 748,885 721,321 775,070 
SCOOPSCOOP158,813  17 %211,898  17 %(53,085) (25)%SCOOP194,513 154,224 173,704 158,813 
OtherOther53  — %205  — %(152) (74)%Other127 29 76 53 
TotalTotal933,936  1,226,405  (292,469) (24)%Total886,516 903,138 895,101 933,936 
Oil and condensate (Bbls/day)
Utica Shale308  7 %621  9 %(313) (50)%
Oil and condensate (Bbl/day)Oil and condensate (Bbl/day)
UticaUtica1,125 1,208 1,168 308 
SCOOPSCOOP4,186  91 %4,899  69 %(713) (15)%SCOOP4,824 2,757 3,756 4,186 
OtherOther83  2 %1,614  22 %(1,531) (95)%Other71 24 47 83 
TotalTotal4,577  7,134  (2,557) (36)%Total6,020 3,989 4,971 4,577 
NGL (Gal/day)
Utica Shale106,333  23 %228,871  36 %(122,538) (54)%
NGL (Bbl/day)NGL (Bbl/day)
UticaUtica2,735 2,586 2,658 2,532 
SCOOPSCOOP353,252  77 %399,368  64 %(46,116) (12)%SCOOP9,073 7,047 8,027 8,411 
OtherOther72  — %208  — %(136) (65)%Other4 2 2 2 
TotalTotal459,657  628,447  (168,790) (27)%Total11,812 9,635 10,687 10,945 
Combined (Mcfe/day)Combined (Mcfe/day)Combined (Mcfe/day)
Utica Shale792,106  77 %1,050,724  77 %(258,618) (25)%
UticaUtica715,042 771,649 744,279 792,106 
SCOOPSCOOP234,396  23 %298,343  22 %(63,947) (21)%SCOOP277,897 213,043 244,401 234,396 
OtherOther563  — %9,922  1 %(9,359) (94)%Other577 182 373 563 
TotalTotal1,027,065  1,358,989  (331,924) (24)%Total993,516 984,874 989,053 1,027,065 
Our total net production averaged approxapproximately 989.1 Mimately Mcfe per day during the Current Combined Quarter, as compared to 1,027.1 MMcfe per day during the three months ended June 30, 2020, as compared to 1,359.0 MMcfe per day during the same period in 2019.Prior Predecessor Quarter. The 24%4% decrease in production is largely the result of a decrease in development activities throughout our portfolio in 2020 and the first half of our Utica Shale and SCOOP operating areas beginning in the third and fourth quarters of 2019. Additionally, in response2021 as we continue to sharp declines in commodity prices resulting from COVID-19 uncertainties, beginning in March 2020, we chose to shut in a portion of our operated low margin, liquids-weighted production during the second quarter of 2020, largely consisting of legacy vertical production in the SCOOP. We also experienced shut ins across both the SCOOP and Utica from our non-operated partners. Nearly all liquids-weighted volumesfocus on both our operated assets and those of our non-operated partners have returned to production.generating sustainable free cash flow.
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Six months ended June 30,
2020% of Total2019% of TotalChange% ChangeSuccessorPredecessorNon-GAAP CombinedPredecessor
($ In thousands)Period from May 18, 2021 through June 30, 2021Period from January 1, 2021 through May 17, 2021Six Months Ended June 30, 2021Six Months Ended June 30, 2020
Natural gas (Mcf/day)Natural gas (Mcf/day)Natural gas (Mcf/day)
Utica Shale780,426  83 %983,436  83 %(203,010) (21)%
UticaUtica691,876 780,791 759,176 780,426 
SCOOPSCOOP159,349  17 %196,955  17 %(37,606) (19)%SCOOP194,513 126,294 142,878 159,349 
OtherOther46  — %173  — %(127) (73)%Other127 63 78 46 
TotalTotal939,821  1,180,564  (240,743) (20)%Total886,516 907,148 902,132 939,821 
Oil and condensate (Bbls/day)
Utica Shale450  9 %675  10 %(225) (33)%
Oil and condensate (Bbl/day)Oil and condensate (Bbl/day)
UticaUtica1,125 1,336 1,285 450 
SCOOPSCOOP4,680  90 %4,661  67 %19  — %SCOOP4,824 2,508 3,071 4,680 
OtherOther81  1 %1,630  23 %(1,549) (95)%Other71 35 44 81 
TotalTotal5,211  6,966  (1,755) (25)%Total6,020 3,879 4,400 5,211 
NGL (Gal/day)
Utica Shale120,313  25 %243,995  39 %(123,682) (51)%
NGL (Bbl/day)NGL (Bbl/day)
UticaUtica2,735 2,638 2,661 2,865 
SCOOPSCOOP365,073  75 %380,234  61 %(15,161) (4)%SCOOP9,073 6,200 6,899 8,692 
OtherOther34  — %186  — %(152) (82)%Other4 3 3 1 
TotalTotal485,420  624,415  (138,995) (22)%Total11,812 8,841 9,563 11,558 
Combined (Mcfe/day)Combined (Mcfe/day)Combined (Mcfe/day)
Utica Shale800,313  77 %1,022,341  78 %(222,028) (22)%
UticaUtica715,042 804,633 782,854 800,313 
SCOOPSCOOP239,583  23 %279,243  21 %(39,660) (14)%SCOOP277,897 178,545 202,697 239,583 
OtherOther536  — %9,983  1 %(9,447) (95)%Other577 288 358 536 
TotalTotal1,040,432  1,311,567  (271,135) (21)%Total993,516 983,466 985,909 1,040,432 
Our total net production averaged approximately 1,040.4approximately 985.9 MMcfe per day during the six months ended June 30, 2020,Current Combined YTD Period, as compared to 1,311.6to 1,040.4 MMcfe per day during the same period in 2019.Prior Predecessor YTD Period. The 21%5% decrease in production is largely the result of a decrease in development activities throughout our portfolio in 2020 and the first half of our Utica Shale and SCOOP operating areas beginning in the third and fourth quarters of 2019. Additionally, in response2021 as we continue to sharp declines in commodity prices resulting from COVID-19 uncertainties, beginning in March 2020, we chose to shut in a portion of our operated low margin, liquids-weighted production during the second quarter of 2020, largely consisting of legacy vertical production in the SCOOP. We also experienced shut ins across both the SCOOP and Utica from our non-operated partners. Nearly all liquids-weighted volumesfocus on both our operated assets and those of our non-operated partners have returned to production.generating sustainable free cash flow.
Utica Shale. From January 1, 2020 through June 30, 2020, weWe spud 1210 gross (11.1 net)and net wells in the Utica Shale,during the Current Combined YTD Period, all of which one was being drilled and 11 were in various stages of operations at June 30, 2020.2021. In addition, we completed 22nine gross and net operated wells. We did not participate in any additional wells that were drilled by other operators on our Utica Shale acreage.
As of July 31, 2020,2021, we had no operated drilling rigs running in the Utica. We expect to add back one operated drilling rig running in the play and expect to continue with this level of activity throughUtica during the third quarter of 2020.
Aggregate net production from our Utica Shale acreage during the three months ended June 30, 2020 was approximately 72,082 MMcfe, or an average of 792.1 MMcfe per day, of which 98% was natural gas and 2% was oil and NGL.2021.
SCOOP. From January 1, 2020 through June 30, 2020, weWe spud sixtwo gross (5.2(1.97 net) wells in the SCOOP during the Current Combined YTD Period, of which one was being drilled and five were in various stages of operations at June 30, 2020. In addition. weone was waiting on completion. We completed 411 gross (3.8(9.3 net) operated wells. We also participated in an additional five gross wells that were drilled by other operators on our SCOOP acreage.
As of July 31, 2020,2021, we had one operated drilling rig running in the play andSCOOP, which we expect towill continue with this level of activity forthrough the remainder of 2020. 
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Aggregate net production from our SCOOP acreage during the three months ended June 30, 2020 was approximately 21,330 MMcfe, or an average of 234.4 MMcfe per day, of which 68% was from natural gas and 32% was from oil and NGL.2021.
RESULTS OF OPERATIONS
49
Comparison of the Three Month Periods Ended June 30, 2020 and 2019
We reported a net loss of $561.1 million for the three months ended June 30, 2020 as compared to net income of $235.0 million for the three months ended June 30, 2019. Included in the loss for the three months ended June 30, 2020 was a $532.9 million non-cash impairment of our oil and natural gas properties, which primarily resulted from a significant decrease in the trailing twelve month first of month prices of natural gas, oil and NGL, and was the main driver of the change in our net (loss) income during the period. Additionally, pricing for all of our commodities decreased significantly during the second quarter of 2020, resulting in a $182.4 million decrease in natural gas, oil and NGL sales and a $144.2 million decrease in gain on natural gas, oil and NGL derivatives. This increase in loss is partially offset by a $125.5 million decrease in loss from equity method investments, a $60.2 million decrease in DD&A, a $34.3 million gain on debt extinguishment, a $12.0 million decrease in midstream gathering and processing expenses, a $6.7 million decrease in lease operating expenses and a $4.5 million decrease in production taxes for the three months ended June 30, 2020 as compared to the three months ended June 30, 2019.
Natural Gas, Oil and NGL Sales
Three months ended June 30,
20202019change
($ In thousands)
Natural gas86,797  225,257  (61)%
Oil and condensate8,390  36,910  (77)%
NGL10,252  25,687  (60)%
Natural gas, oil and NGL sales$105,439  $287,854  (63)%
The decrease in natural gas sales without the impact of derivatives was due to a 49% decrease in realized natural gas prices and a 24%decrease in natural gas sales volumes.
The decrease in oil and condensate sales without the impact of derivatives was due to a 65% decrease in realized oil and condensate prices and a 36% decrease in oil and condensate sales volumes.
The decrease in NGL sales without the impact of derivatives was due to a 45% decreasein realized NGL prices and a 27% decrease in NGL sales volumes.
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Natural Gas, OilSuccessor Period and NGL Derivatives
Three months ended June 30,
20202019
($ 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  $171,140  
See Note 10Current Predecessor Quarter Compared to our consolidated financial statements for further discussion of our derivative activity.Prior Predecessor Quarter
Natural Gas, Oil and NGL Production and Pricing
The following table summarizes our oil and condensate, natural gas and NGL production and related pricing for the three months ended June 30, 2020,Successor Period, Current Predecessor Quarter and Current Combined Quarter, as compared to such data for the three months ended June 30, 2019:Prior Predecessor Quarter:
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 Three months ended June 30,
 20202019
($ 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  
 SuccessorPredecessorNon-GAAP CombinedPredecessor
Period from May 18, 2021 through June 30, 2021Period from April 1, 2021 through May 17, 2021Three Months Ended June 30, 2021Three Months Ended June 30, 2020
Natural gas sales
Natural gas production volumes (MMcf)39,007 42,448 81,455 84,988 
Natural gas production volumes (MMcf) per day887 903 895 934 
Total sales$111,718 $109,069 $220,787 $140,688 
Average price without the impact of derivatives ($/Mcf)$2.86 $2.57 $2.71 $1.66 
Impact from settled derivatives ($/Mcf)$(0.17)$(0.08)$(0.12)$0.99 
Average price, including settled derivatives ($/Mcf)$2.69 $2.49 $2.59 $2.65 
Oil and condensate sales
Oil and condensate production volumes (MBbl)265 187 452 417 
Oil and condensate production volumes (MBbl) per day6 4 5 5 
Total sales$17,587 $10,867 $28,454 $8,390 
Average price without the impact of derivatives ($/Bbl)$66.37 $58.11 $62.95 $20.14 
Impact from settled derivatives ($/Bbl)$— $— $— $97.12 
Average price, including settled derivatives ($/Bbl)$66.37 $58.11 $62.95 $117.26 
NGL sales
NGL production volumes (MBbl)520 453 973 996 
NGL production volumes (MBbl) per day12 10 11 11 
Total sales$16,077 $13,004 $29,081 $10,252 
Average price without the impact of derivatives ($/Bbl)$30.92 $28.71 $29.89 $10.29 
Impact from settled derivatives ($/Bbl)$— $— $— $— 
Average price, including settled derivatives ($/Bbl)$30.92 $28.71 $29.89 $10.29 
Natural gas, oil and condensate and NGL sales
Natural gas equivalents (MMcfe)43,715 46,289 90,004 93,463 
Natural gas equivalents (MMcfe) per day994 985 989 1,027 
Total sales$145,382 $132,940 $278,322 $159,330 
Average price without the impact of derivatives ($/Mcfe)$3.33 $2.87 $3.09 $1.70 
Impact from settled derivatives ($/Mcfe)$(0.15)$(0.08)$(0.11)$1.33 
Average price, including settled derivatives ($/Mcfe)$3.18 $2.79 $2.98 $3.03 
Production Costs:
Average lease operating expenses ($/Mcfe)$0.09 $0.15 $0.12 $0.14 
Average taxes other than income ($/Mcfe)$0.12 $0.08 $0.10 $0.07 
Average transportation, gathering, processing and compression ($/Mcfe)$0.95 $1.19 $1.07 $1.22 
Total lease operating expenses, midstream costs and production taxes ($/Mcfe)$1.16 $1.42 $1.29 $1.43 
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Lease Operating ExpensesNatural Gas, Oil and NGL Sales
Three months ended June 30,
20202019change
($ 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.
SuccessorPredecessorNon-GAAP CombinedPredecessor
Period from May 18, 2021 through June 30, 2021Period from April 1, 2021 through May 17, 2021Three Months Ended June 30, 2021Three Months Ended June 30, 2020
Natural gas$111,718 $109,069 $220,787 $140,688 
Oil and condensate17,587 10,867 28,454 8,390 
NGL16,077 13,004 29,081 10,252 
Natural gas, oil and NGL sales$145,382 $132,940 $278,322 $159,330 
The increase in natural gas sales without the impact of derivatives when comparing the Combined Current Quarter to the Prior Predecessor Quarter was due to a 64% increase in realized natural gas prices partially offset by a 4% decrease in total lease operating expenses ("LOE") forsales volumes. The realized price change was driven by the three months ended June 30, 2020 as comparedsignificant increase in the average Henry Hub gas index from $1.73 in the Prior Predecessor Quarter to $2.95 during the Combined Current Quarter.
The increase in oil and condensate sales without the impact of derivatives when comparing the Combined Current Quarter to the three months ended June 30, 2019Prior Predecessor Quarter was primarily the result of our 24% decrease in production and ongoing well optimization and cost initiatives. Per unit LOE was relatively flat for the three months ended June 30, 2020 as compared to the three months ended June 30, 2019.
Production Taxes
Three months ended June 30,
20202019change
($ 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 relateddue to a decrease212% increase in realized prices and production forcombined with a 9% increase in sales volumes. The realized price change was driven by the three months ended June 30, 2020 as comparedsignificant increase in the average WTI crude index from $28.28 per barrel in the Prior Predecessor Quarter to $66.19 per barrel during the three months ended June 30, 2019.Combined Current Quarter.
Midstream Gathering and Processing Expenses
Three months ended June 30,
20202019change
($ 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 forNGL sales without the three months ended June 30, 2020 as comparedimpact of derivatives when comparing the Combined Current Quarter to the three months ended June 30, 2019 is primarily relatedPrior Predecessor Quarter was due to Utica Shale production volumes falling below a minimum volume commitment and191% increase in realized prices partially offset by a 2% decrease in NGL sales volumes. The realized price change was driven by the resulting deficiency paymentssignificant increase in the average Mont Belvieu NGL index from $17.40 per barrel in the Prior Predecessor Quarter to $36.55 per barrel during the three months ended June 30, 2020.Combined Current Quarter.
Natural Gas, Oil and NGL Derivatives
SuccessorPredecessorNon-GAAP CombinedPredecessor
Period from May 18, 2021 through June 30, 2021Period from April 1, 2021 through May 17, 2021Three Months Ended June 30, 2021Three Months Ended June 30, 2020
Natural gas derivatives - fair value losses$(120,264)$(97,543)$(217,807)$(48,146)
Natural gas derivatives - settlement (losses) gains(6,689)(3,486)(10,175)83,835 
Total (losses) gains on natural gas derivatives(126,953)(101,029)(227,982)35,689 
Oil and condensate derivatives - fair value losses(5,357)(4,395)(9,752)(48,386)
Oil and condensate derivatives - settlement gains— — — 40,449 
Total losses on oil and condensate derivatives(5,357)(4,395)(9,752)(7,937)
NGL derivatives - fair value losses(7,348)(1,837)(9,185)(997)
NGL derivatives - settlement gains— — — 216 
Total losses on NGL derivatives(7,348)(1,837)(9,185)(781)
Total (losses) gains on natural gas, oil and NGL derivatives$(139,658)$(107,261)$(246,919)$26,971 
See Note 10 to our consolidated financial statements for further discussion of our derivative activity.
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Lease Operating Expenses
SuccessorPredecessorNon-GAAP CombinedPredecessor
Period from May 18, 2021 through June 30, 2021Period from April 1, 2021 through May 17, 2021Three Months Ended June 30, 2021Three Months Ended June 30, 2020
Lease operating expenses
Utica$2,853 $4,769 $7,622 $10,391 
SCOOP1,230 2,092 3,322 2,548 
Other(1)
33 10 43 139 
Total lease operating expenses$4,116 $6,871 $10,987 $13,078 
Lease operating expenses per Mcfe
Utica$0.09 $0.13 $0.11 $0.14 
SCOOP0.100.210.150.12
Other(1)
1.321.111.262.73
Total lease operating expenses per Mcfe$0.09 $0.15 $0.12 $0.14 
 _____________________
(1)    Includes Niobrara and Bakken.
The decrease in total LOE was primarily the result of a 4% decrease in production as well as ongoing cost reduction initiatives. The decrease in per unit LOE is primarily the result of ongoing cost reduction initiatives.
Taxes Other Than Income
SuccessorPredecessorNon-GAAP CombinedPredecessor
Period from May 18, 2021 through June 30, 2021Period from April 1, 2021 through May 17, 2021Three Months Ended June 30, 2021Three Months Ended June 30, 2020
Production taxes$3,739 $2,656 $6,395 $3,605 
Property taxes1,0676771,7442,580
Other250312562115
Total taxes other than income$5,056 $3,645 $8,701 $6,300 
Total taxes other than income per Mcfe$0.12 $0.08 $0.10 $0.07 
The increase in total and per unit production taxes when comparing the Combined Current Quarter to the Prior Predecessor Quarter was primarily related to an increase in revenues and realized prices.
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Transportation, Gathering, Processing and Compression
SuccessorPredecessorNon-GAAP CombinedPredecessor
Period from May 18, 2021 through June 30, 2021Period from April 1, 2021 through May 17, 2021Three Months Ended June 30, 2021Three Months Ended June 30, 2020
Transportation, gathering, processing and compression$41,376 $55,219 $96,595 $113,865 
Transportation, gathering, processing and compression per Mcfe$0.95 $1.19 $1.07 $1.22 
The decrease in transportation, gathering, processing and compression when comparing the Combined Current Quarter to the Prior Predecessor Quarter was primarily related to a 4% decrease in our production and savings associated with midstream contract rejections and renegotiations through the bankruptcy process. The decrease in per unit transportation, gathering, processing and compression when comparing the Combined Current Quarter to the Prior Predecessor Quarter is primarily related to midstream contract rejections and renegotiations through the bankruptcy process.
Depreciation, Depletion and Amortization
Three months ended June 30,SuccessorPredecessorPredecessor
20202019changePeriod from May 18, 2021 through June 30, 2021Period from April 1, 2021 through May 17, 2021Three Months Ended June 30, 2020
($ In thousands, except per unit)
Depreciation, depletion and amortization$64,790  $124,951  (48)%
Depreciation, depletion and amortization of oil and gas propertiesDepreciation, depletion and amortization of oil and gas properties$32,037 $21,064 $62,214 
Depreciation, depletion and amortization of other property and equipmentDepreciation, depletion and amortization of other property and equipment$325 $553 $2,576 
Total Depreciation, depletion and amortizationTotal Depreciation, depletion and amortization$32,362 $21,617 $64,790 
Depreciation, depletion and amortization per McfeDepreciation, depletion and amortization per Mcfe$0.69  $1.01  (32)%Depreciation, depletion and amortization per Mcfe$0.74 $0.47 $0.69 
Depreciation,The increase in depreciation, depletion and amortization ("DD&A") expense consisted of our oil and gas properties for the Successor Period compared to the Current Predecessor Quarter resulted from the revaluation of our properties subject to amortization in connection with our emergence from bankruptcy. Fresh start accounting requires that new fair values be established for our assets as of the emergence date. See $62.2 millionNote 3 for more information on our fresh-start valuation adjustments.
The decrease in depletionDD&A of oil and natural gas properties and $2.6 millionin 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&Apredecessor period 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 ofthroughout 2020, as well as a decrease in our production.
Impairment of Oil and Gas Properties. DuringProperties
As a result of the three months endedceiling test performed at June 30, 2020,2021, we incurred a$532.9 $117.8 million impairment charge of oil and natural gas properties impairment charge related primarily toduring the decline in the twelve month trailing first of month average price for natural gas, oil and NGL, compared to noSuccessor Period, while we recorded a $532.9 million impairment charge of oil and gas properties during the three months ended June 30, 2019.
Based on prices for2020. Upon the last nine months and the short-term pricing outlook for the third quarterapplication of 2020, we expect to recognize an additional full cost impairment in the third quarter of 2020. The amount of any future impairments is difficult to predict as it depends on changes in commodity prices, production rates, proved reserves, evaluation of costs excluded from amortization, future development costs and production costs.
Equity Investments
Three months ended June 30,
20202019change
($ 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 $125.4 million impairment charge recorded during the three months ended June 30, 2019. Asfresh start accounting, the value of our investmentoil and natural gas properties was determined using forward strip oil and natural gas prices as of the emergence date. These prices were higher than the 12-month weighted average prices used in Mammoth was reduced to zero during the first quarter of 2020, we did not record any similar impairment charges during the three months endedfull cost ceiling limitation at June 30, 2020. See Note 42021, which led to our consolidated financial statements for further discussion on our equity investments.
General and Administrative Expenses
Three months ended June 30,
20202019change
($ 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 theSuccessor Period impairment charge.
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continued depressed commodity price environment, we announced several G&A initiativesGeneral and Administrative Expenses
SuccessorPredecessorNon-GAAP CombinedPredecessor
Period from May 18, 2021 through June 30, 2021Period from April 1, 2021 through May 17, 2021Three Months Ended June 30, 2021Three Months Ended June 30, 2020
General and administrative expenses, gross$9,867 $10,835 $20,702 $20,951 
Reimbursed from third parties$(1,173)$(1,919)$(3,092)$(3,023)
Capitalized general and administrative expenses$(2,176)$(2,498)$(4,674)$(8,162)
General and administrative expenses, net$6,518 $6,418 $12,936 $9,766 
General and administrative expenses, net per Mcfe$0.15 $0.14 $0.14 $0.10 
The increase in general and administrative expenses in the Current Combined Quarter as compared to reducethe Prior Predecessor Quarter was primarily driven by legal and professional fees associated with our corporate cost structure. This decrease wasrestructuring. Subsequent to our emergence, legal and professional costs related to our ongoing contract rejections and other litigation are now presented in general and administrative expenses. During our restructuring process, these costs were generally presented in reorganizations expense, net. These increases were partially offset by an increase in non-recurring legal and consulting expenses.

our continued focus on reducing costs across our organization.
Interest Expense
SuccessorPredecessorPredecessor
Period from May 18, 2021 through June 30, 2021Period from April 1, 2021 through May 17, 2021Three Months Ended June 30, 2020
Interest expense on Predecessor Senior NotesInterest expense on Predecessor Senior Notes$— $— $28,179 
Interest expense on Pre-Petition Revolving Credit FacilityInterest expense on Pre-Petition Revolving Credit Facility$— $1,024 $2,860 
Interest expense on building loan and otherInterest expense on building loan and other$614 $(1,064)$310 
Capitalized interestCapitalized interest$— $— $(523)
Amortization of loan costsAmortization of loan costs$420 $— $1,540 
Interest on DIP Credit FacilityInterest on DIP Credit Facility$— $938 $— 
Interest on Exit FacilityInterest on Exit Facility$1,366 $— $— 
Interest on First-Out Term LoanInterest on First-Out Term Loan$1,238 $— $— 
Interest on Successor Senior NotesInterest on Successor Senior Notes$5,256 $— $— 
Total interest expenseTotal interest expense$8,894 $898 $32,366 
Interest expense per McfeInterest expense per Mcfe$0.20 $0.02 $0.35 
Three months ended June 30,
20202019
($ 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 comparedwhen comparing the Current Predecessor Quarter to the three months ended June 30, 2019Prior Predecessor Quarter was primarily due to repurchasesthe cessation of interest accrual on borrowings classified as subject to compromise as of the petition date.
Gain on Debt Extinguishment.
During the Prior Predecessor Quarter, we repurchased in the open market $47.5 million aggregate principal amount of our Predecessor Senior Notes for $12.6 million in cash and recognized a $34.3 million gain on debt extinguishment. We did not repurchase any of our senior notes in the second halfSuccessor Period or Current Predecessor Quarter.
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Equity Investments
SuccessorPredecessorNon-GAAP CombinedPredecessor
Period from May 18, 2021 through June 30, 2021Period from April 1, 2021 through May 17, 2021Three Months Ended June 30, 2021Three Months Ended June 30, 2020
Loss from equity method investments, net$— $— $— $45 
The decrease in loss from equity investments when comparing the Current Predecessor Quarter to the Prior Predecessor Quarter is related to both our election to report our share of Grizzly earnings on a one quarter lag at the Emergence Date as well as the use of our Mammoth shares to settle Class 4A claims.
Reorganization Items, Net
The following table summarizes the components in reorganization items, net included in our consolidated statements of operations for the Successor Period and the first halfCurrent Predecessor Quarter:
SuccessorPredecessor
Period from May 18, 2021 through June 30, 2021Period from April 1, 2021 through May 17, 2021
Legal and professional advisory fees$— $(40,782)
Net gain on liabilities subject to compromise— 571,032 
Fresh start adjustments, net— (160,756)
Elimination of predecessor accumulated other comprehensive income— (40,430)
Debt issuance costs— (3,150)
Other items, net— (20,297)
Reorganization items, net$— $305,617 
See Note 3 for further discussion of 2020.the components of reorganization items, net.
Income Taxes
The income tax benefit of $8.0 million that was recognized for the Current Predecessor Quarter in our consolidated statement of operations is a result of an Oklahoma refund claim associated with an examination relating to historical tax returns . We recorded nodid not record any income tax expense for three months ended June 30, 2020 compared to income tax benefitthe Successor Period as a result of $179.3 million for the three months ended June 30, 2019. As of June 30, 2020, we hadmaintaining a federal net operating loss carryforward of approximately $1.5 billion, in addition to numerous temporary differences, which gave rise to afull valuation allowance against our net deferred tax asset. Quarterly, management performs a forecastFor the Prior Predecessor Quarter, we had an effective tax rate of our taxable income0% and analyzes other relevant factorstax expense of zero due to determine whether it is more likely than not that athe Company’s valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established if, in management’s opinion, it is more likely than not that some portion will not be realized. At June 30, 2020, a valuation allowance of $879.3 million has been maintained against the full net deferred tax asset. The tax benefit recorded during the three months ended June 30, 2019 was a result of management's determination there was sufficient positive evidence that it was more likely than not that the federal and some state net operating loss carryforwards would be realized.
On April 30, 2020, our Board of Directors approved the adoption of a tax benefits preservation plan that is intended to protect value by preserving our ability to use our tax attributes, such as NOLs, to offset potential future income taxes for federal income tax purposes. See Note 14 of the notes to our consolidated financial statements for more information.


position
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Comparison of the Six Month Periods Ended June 30, 2020Successor Period and 2019
We reported net loss of $1.1 billion for the six months ended June 30, 2020 as comparedCurrent Predecessor YTD Period 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  $628,477  (60)%
The decrease in natural gas sales without the impact of derivatives was due to a 51% decrease in realized natural gas prices and a 20% decreasein natural gas sales volumes.
The decrease in oil and condensate sales without the impact of derivatives was due to an 40% decrease in realized oil and condensate prices and a 25% decrease in oil and condensate sales volumes.
The decrease in NGL sales without the impact of derivatives was due to a 40% decrease in realized NGL prices and a 22% decrease in NGL sales volumes.
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Natural Gas, Oil and NGL Derivatives
Six months ended June 30,
20202019
($ 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.Prior Predecessor YTD Period
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,Successor Period, Current Predecessor YTD Period and the Current Combined YTD Period, as compared to such data for the six months ended June 30, 2019:Prior Predecessor YTD Period:
 SuccessorPredecessorNon-GAAP CombinedPredecessor
Period from May 18, 2021 through June 30, 2021Period from January 1, 2021 through May 17, 2021Six Months Ended June 30, 2021Six Months Ended June 30, 2020
Natural gas sales
Natural gas production volumes (MMcf)39,007 124,279 163,286 171,047 
Natural gas production volumes (MMcf) per day887 907 902 940 
Total sales$111,718 $344,390 $456,108 $301,696 
Average price without the impact of derivatives ($/Mcf)$2.86 $2.77 $2.79 $1.76 
Impact from settled derivatives ($/Mcf)$(0.17)$(0.03)$(0.06)$0.85 
Average price, including settled derivatives ($/Mcf)$2.69 $2.74 $2.73 $2.61 
Oil and condensate sales
Oil and condensate production volumes (MBbl)265 531 796 948 
Oil and condensate production volumes (MBbl) per day6 4 4 5 
Total sales$17,587 $29,106 $46,693 $31,541 
Average price without the impact of derivatives ($/Bbl)$66.37 $54.81 $58.66 $33.26 
Impact from settled derivatives ($/Bbl)$— $— $— $52.67 
Average price, including settled derivatives ($/Bbl)$66.37 $54.81 $58.66 $85.93 
NGL sales
NGL production volumes (MBbl)520 1,211 1,731 2,103 
NGL production volumes (MBbl) per day12 9 10 12 
Total sales$16,077 $36,780 $52,857 $27,165 
Average price without the impact of derivatives ($/Bbl)$30.92 $30.37 $30.54 $12.92 
Impact from settled derivatives ($/Bbl)$— $— $— $— 
Average price, including settled derivatives ($/Bbl)$30.92 $30.37 $30.54 $12.92 
Natural gas, oil and condensate and NGL sales
Natural gas equivalents (MMcfe)43,715 134,735 178,450 189,359 
Natural gas equivalents (MMcfe) per day994 983 986 1,040 
Total sales$145,382 $410,276 $555,658 $360,402 
Average price without the impact of derivatives ($/Mcfe)$3.33 $3.05 $3.11 $1.90 
Impact from settled derivatives ($/Mcfe)$(0.15)$(0.02)$(0.06)$1.03 
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 Six months ended June 30,
 20202019
($ 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  $0.85  
Average price, including settled derivatives ($/Mcfe)$3.18 $3.03 $3.05 $2.93 
Production Costs:
Average lease operating expenses ($/Mcfe)$0.09 $0.14 $0.13 $0.15 
Average taxes other than income ($/Mcfe)$0.12 $0.09 $0.10 $0.07 
Average transportation, gathering, processing and compression ($/Mcfe)$0.95 $1.20 $1.13 $1.18 
Total lease operating expenses, midstream costs and production taxes ($/Mcfe)$1.16 $1.43 $1.36 $1.40 

Natural Gas, Oil and NGL Sales
SuccessorPredecessorNon-GAAP CombinedPredecessor
Period from May 18, 2021 through June 30, 2021Period from January 1, 2021 through May 17, 2021Six Months Ended June 30, 2021Six Months Ended June 30, 2020
Natural gas$111,718 $344,390 $456,108 $301,696 
Oil and condensate17,587 29,106 46,693 31,541 
NGL16,077 36,780 52,857 27,165 
Natural gas, oil and NGL sales$145,382 $410,276 $555,658 $360,402 
The increase in natural gas sales without the impact of derivatives was due to a 58% increase in realized natural gas prices partially offset by a 5% decrease in sales volumes. The realized price change was driven by the significant increase in the average Henry Hub gas index from $1.80 in the Prior Predecessor YTD Period to $3.22 during the Current Combined YTD Period.
The increase in oil and condensate sales without the impact of derivatives was due to a 76% increase in realized prices and partially offset by a 16% decrease in sales volumes. The realized price change was driven by the significant increase in the average WTI crude index from $36.58 per barrel in the Prior Predecessor YTD Period to $62.21 per barrel during the Current Combined YTD Period.
The increase in NGL sales without the impact of derivatives was due to a 136% increase in realized prices partially offset by an 18% decrease in NGL sales volumes. The realized price change was driven by the significant increase in the average Mont Belvieu NGL index from $16.49 per barrel in the Prior Predecessor YTD Period to $37.13 per barrel during the Current Combined YTD Period.
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Natural Gas, Oil and NGL Derivatives
SuccessorPredecessorNon-GAAP CombinedPredecessor
Period from May 18, 2021 through June 30, 2021Period from January 1, 2021 through May 17, 2021Six Months Ended June 30, 2021Six Months Ended June 30, 2020
Natural gas derivatives - fair value losses$(120,264)$(123,080)$(243,344)$(63,271)
Natural gas derivatives - settlement (losses) gains(6,689)(3,362)(10,051)144,813 
Total (losses) gains on natural gas derivatives(126,953)(126,442)(253,395)81,542 
Oil and condensate derivatives - fair value losses(5,357)(6,126)(11,483)(5,012)
Oil and condensate derivatives - settlement gains— — — 49,949 
Total (losses) gains on oil and condensate derivatives(5,357)(6,126)(11,483)44,937 
NGL derivatives - fair value losses(7,348)(4,671)(12,019)(332)
NGL derivatives - settlement gains— — — 471 
Total (losses) gains on NGL derivatives(7,348)(4,671)(12,019)139 
Contingent consideration arrangement - fair value losses— — — (1,381)
Total (losses) gains on natural gas, oil and NGL derivatives$(139,658)$(137,239)$(276,897)$125,237 
See Note 10 to our consolidated financial statements for further discussion of our derivative activity.
Lease Operating Expenses
Six months ended June 30,
20202019changeSuccessorPredecessorNon-GAAP CombinedPredecessor
($ In thousands, except per unit)Period from May 18, 2021 through June 30, 2021Period from January 1, 2021 through May 17, 2021Six Months Ended June 30, 2021Six Months Ended June 30, 2020
Lease operating expensesLease operating expensesLease operating expenses
UticaUtica$24,180  $25,473  (5)%Utica$2,853 $13,991 $16,844 $20,288 
SCOOPSCOOP7,320  7,757  (6)%SCOOP1,230 5,449 6,679 7,313 
Other(1)172  8,965  (98)%
Other(1)
Other(1)
33 84 117 172 
Total lease operating expensesTotal lease operating expenses$31,672  $42,195  (25)%Total lease operating expenses$4,116 $19,524 $23,640 $27,773 
Lease operating expenses per McfeLease operating expenses per McfeLease operating expenses per Mcfe
UticaUtica$0.17  $0.14  21 %Utica$0.09$0.13$0.12$0.14
SCOOPSCOOP0.17  0.15  9 %SCOOP0.100.220.180.17
Other(1)1.77  4.96  (64)%
OtherOther1.322.151.831.76
Total lease operating expenses per McfeTotal lease operating expenses per Mcfe$0.17  $0.18  (6)%Total lease operating expenses per Mcfe$0.09$0.14$0.13$0.15
 _____________________
(1)    Includes WCBB, Hackberry, Niobrara and Bakken.
The decrease in total LOE forduring the six months ended June 30, 2020 asCurrent Combined YTD Period compared to the six months ended June 30, 2019Prior Predecessor YTD Period was primarily the result of our 21%a 6% decrease in production. Per unit LOE was relatively flat for the six months ended June 30, 2020production as compared to the six months ended June 30, 2019.
Production Taxes
Six months ended June 30,
20202019change
($ In thousands, except per unit)
Production taxes$8,404  $16,019  (48)%
Production taxes per Mcfe$0.04  $0.07  (34)%
well as ongoing cost reduction initiatives. The decrease in production taxes wasper unit LOE is primarily related to a decrease in realized prices and production for the six months ended June 30, 2020.
Six months ended June 30,
20202019change
($ 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.result of ongoing cost reduction initiatives.
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Taxes Other Than Income
SuccessorPredecessorNon-GAAP CombinedPredecessor
Period from May 18, 2021 through June 30, 2021Period from January 1, 2021 through May 17, 2021Six Months Ended June 30, 2021Six Months Ended June 30, 2020
Production taxes$3,739 $8,459 $12,198 $8,404 
Property taxes1,0672,5903,6573,863
Other2501,3001,550670
Total taxes other than income5,05612,34917,40512,937
Total taxes other than income per Mcfe$0.12 $0.09 $0.10 $0.07 
The increase in total and per unit production taxes during the Current Combined YTD Period compared to the Prior Predecessor YTD Period was primarily related to an increase in revenues due to an increase in realized prices.
Transportation, Gathering, Processing and Compression
SuccessorPredecessorNon-GAAP CombinedPredecessor
Period from May 18, 2021 through June 30, 2021Period from January 1, 2021 through May 17, 2021Six Months Ended June 30, 2021Six Months Ended June 30, 2020
Transportation, gathering, processing and compression$41,376 $161,086 $202,462 $224,222 
Transportation, gathering, processing and compression per Mcfe$0.95 $1.20 $1.13 $1.18 
The decrease in transportation, gathering, processing and compression during the Current Combined YTD Period compared to the Prior Predecessor YTD Period was primarily related to a 6% decrease in our production. The decrease in per unit transportation, gathering, processing and compression during the Current Combined YTD Period compared to the Prior Predecessor YTD Period is primarily related to midstream contract rejections and renegotiations through the bankruptcy process.
Depreciation, Depletion and Amortization
Six months ended June 30,SuccessorPredecessorPredecessor
20202019changePeriod from May 18, 2021 through June 30, 2021Period from January 1, 2021 through May 17, 2021Six Months Ended June 30, 2020
($ In thousands, except per unit)
Depreciation, depletion and amortization$142,818  $243,384  (41)%
Depreciation, depletion and amortization of oil and gas propertiesDepreciation, depletion and amortization of oil and gas properties$32,037 $60,831 $137,573 
Depreciation, depletion and amortization of other property and equipmentDepreciation, depletion and amortization of other property and equipment$325 $1,933 $5,245 
Total Depreciation, depletion and amortizationTotal Depreciation, depletion and amortization$32,362 $62,764 $142,818 
Depreciation, depletion and amortization per McfeDepreciation, depletion and amortization per Mcfe$0.75  $1.03  (26)%Depreciation, depletion and amortization per Mcfe$0.74 $0.47 $0.75 
Depreciation,The increase in depreciation, depletion and amortization ("DD&A") expense consisted of $137.6 million in depletion ofour oil and natural gas properties and $5.2 million in depreciation of other property and equipment,for the Successor Period compared to $237.7 millionthe Current Predecessor YTD Period resulted from the revaluation of our properties subject to amortization in depletionconnection with our emergence from bankruptcy. Fresh start accounting requires that new fair values be established for our assets as of oil and natural gas properties and $5.7 million in depreciationthe emergence date. See Note 3 for more information on our fresh-start valuation adjustments.


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Table of other property and equipment for the six months ended June 30, 2019. Contents

The decrease in DD&A of oil and gas properties in the predecessor period 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 2019throughout 2020, as well as a decrease in our production.
Impairment of Oil and Gas Properties. DuringProperties
As a result of the six months endedceiling test performed at June 30, 2020,2021, 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 noa $117.8 million impairment charge of oil and gas properties during the six months endedSuccessor Period. We recorded $1.1 billion in impairment charges of oil and gas properties during the Prior Predecessor YTD Period. Upon the application of fresh start accounting, the value of our oil and natural gas properties was determined using forward strip oil and natural gas prices as of the emergence date. These prices were higher than the 12-month weighted average prices used in the full cost ceiling limitation at June 30, 2019.2021, which led to the Successor Period impairment charge.
Equity InvestmentsImpairment of Other Property and Equipment
Six months ended June 30,
20202019change
($ In thousands, except per unit)
Loss from equity method investments, net$10,834  $121,309  (91)%
We recognized a $14.6 million impairment charge on the Company's corporate headquarters during the Current Predecessor YTD Period as a result in a change in expected future use.
General and Administrative Expenses
SuccessorPredecessorNon-GAAP CombinedPredecessor
Period from May 18, 2021 through June 30, 2021Period from January 1, 2021 through May 17, 2021Six Months Ended June 30, 2021Six Months Ended June 30, 2020
General and administrative expenses, gross$9,867 $32,152 $42,019 $45,055 
Reimbursed from third parties$(1,173)$(4,957)$(6,130)$(6,075)
Capitalized general and administrative expenses$(2,176)$(8,020)$(10,196)$(13,592)
General and administrative expenses, net$6,518 $19,175 $25,693 $25,388 
General and administrative expenses, net per Mcfe$0.15 $0.14 $0.14 $0.13 
The decrease in general and administrative expenses during the Current Combined YTD Period compared to the Prior Predecessor YTD Period was primarily driven by our continued focus on reducing costs across our organization and lower non-recurring legal and consulting expenses.
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Interest Expense
 SuccessorPredecessorPredecessor
Period from May 18, 2021 through June 30, 2021Period from January 1, 2021 through May 17, 2021Six Months Ended June 30, 2020
Interest expense on Predecessor Senior Notes$— $— $57,299 
Interest expense on Pre-Petition Revolving Credit Facility$— $2,044 $5,025 
Interest expense on building loan and other$614 $(989)$650 
Capitalized interest$— $— $(710)
Amortization of loan costs$420 $— $3,092 
Interest on DIP Credit Facility$— $3,104 $— 
Interest on Exit Facility$1,366 $— $— 
Interest on First-Out Term Loan$1,238 $— $— 
Interest on Successor Senior Notes$5,256 $— $— 
Total interest expense$8,894 $4,159 $65,356 
Interest expense per Mcfe$0.20 $0.03 $0.35 
The decrease in interest expense during the Current Predecessor YTD Period compared to the Prior Predecessor YTD Period was due to the cessation of interest accrual on borrowings classified as subject to compromise as of the petition date.
Gain on Debt Extinguishment
During the Prior Predecessor YTD Period, we repurchased in the open market $73.3 million aggregate principal amount of our Predecessor Senior Notes for $22.8 million in cash and recognized a $49.6 million gain on debt extinguishment. We did not repurchase any of our senior notes in the Successor Period or Current Predecessor YTD Period.
Equity Investments
SuccessorPredecessorNon-GAAP CombinedPredecessor
Period from May 18, 2021 through June 30, 2021Period from January 1, 2021 through May 17, 2021Six Months Ended June 30, 2021Six Months Ended June 30, 2020
Loss from equity method investments, net$— $342 $342 $10,834 
During the Prior Predecessor YTD Period, our share of net loss from equity method investments is primarily related to a $125.4 million impairment charge recorded duringMammoth was in excess of the six months ended June 30, 2019. Thecarrying value of our investment, inwhich reduced our investment to zero. Our carrying value remained at zero through the Current Predecessor YTD Period until the use of Mammoth was reducedShares to zero duringsettle Class 4A claims at the first quarter of 2020, and we did not record any similar impairment charges during the six months ended June 30, 2020.Emergence Date. See Note 413 to our consolidated financial statements for further discussion on our equity investments.
General and Administrative Expenses
Six months ended June 30,
20202019change
($ 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  $123,287  
Reorganization Items, Net.
The decreasefollowing table summarizes the components in interest expensereorganization items, net included in our consolidated statements of operations for the six monthsSuccessor Period and Current Predecessor YTD Period ended June 30, 2020 as compared2021:
SuccessorPredecessor
Period from May 18, 2021 through June 30, 2021Period from January 1, 2021 through May 17, 2021
Legal and professional advisory fees$— $(81,565)
Net gain on liabilities subject to compromise— 575,182 
Fresh start adjustments, net— (160,756)
Elimination of predecessor accumulated other comprehensive income— (40,430)
Debt issuance costs— (3,150)
Other items, net— (22,383)
Reorganization items, net$— $266,898 
We have incurred and will continue to the six months ended June 30, 2019 wasincur additional gains and losses associated with our reorganization, primarily duerelated to continued repurchases oflegal and professional fees related to our senior notes.ongoing Chapter 11 cases.
Income Taxes
Income Taxes. We recorded income tax expense of 7.3 million for the six months ended June 30, 2020 compared toan income tax benefit of 179.3$8.0 million during the Current Predecessor YTD Period as a result of an Oklahoma refund claim associated with an examination relating to historical tax returns . We did not record any income tax expense for the six months ended June 30, 2019. AsSuccessor Period as a result of June 30, 2020, we hadmaintaining a federal net operating loss carryforward of approximately $1.5 billion from prior years, in addition to numerous temporary differences, which gave rise to afull valuation allowance against our net deferred tax asset. Quarterly, management performs a forecastFor the Prior Predecessor YTD Period, we had an effective tax rate of our taxable income0.7% 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$7.3 million as a result of management's determination there was sufficient positive evidence that it was more likely than not that the federalsale of assets and somea corresponding adjustment to the valuation allowance on remaining state net operating loss carryforwards would be realized.

carryforwards.
Liquidity and Capital Resources
Overview. We strive to maintain sufficient liquidity to ensure financial flexibility, withstand commodity price volatility and fund our development projects, operations and capital expenditures and return capital to shareholders. We utilize derivative contracts to reduce the financial impact of commodity price volatility and provide a level of certainty to the Company's cash flows. Historically, we have generally funded our operations, planned capital expenditures, debt repurchases and share repurchases with cash flow from our operating activities, cash on hand and borrowings under our revolving credit facility. We also periodically access debt and equity markets and sell properties to enhance our liquidity.

For the Successor Period, our primary sources of capital resources and liquidity have consisted of internally generated cash flows from operations, and our primary uses of cash have been for development of our oil and natural gas properties. Historically, our primary sources of capital funding and liquidity have been our operating cash flow, borrowings under our revolving credit facilityagreements and issuances of equity and debt securities. Our ability to issue additional indebtedness, dispose of assets or access these sources of funds can be significantly impacted by changes inthe capital markets decreaseswas substantially limited or nonexistent during the Chapter 11 Cases and required court approval in commodity prices and decreasesmost instances. Accordingly, our liquidity 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 obtainPredecessor periods depended mainly on cash generated from operating activities and available funds under the DIP Credit Facility in the 2021 Predecessor Period and Pre-Petition Revolving Credit Facility in the 2020 Predecessor Period.
We believe our annual free cash flow generation, borrowing capacity under the Exit Credit Facility, and cash 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 ourhand will provide sufficient liquidity and may impair our ability to fund our plannedoperations, capital expenditures, interest expense, debt repayments and meet our obligationsany quarterly cash dividend payments, if declared by the Board during the next 12 months. To the extent that we sell assets in the future, we plan to use the proceeds to fund on-going operations, reduce debt and for general corporate purposes.
As of June 30, 2021, we had $9.4 million of cash and cash equivalents, $105.0 million of borrowings under our existing indebtedness. Further, a reduction inExit Facility, $180.0 million of borrowings under our capital expenditures would decreaseFirst-Out Term Loan, $114.8 million of letters of credit outstanding, and $550 million of outstanding 2026 Notes. Our total principal amount of funded debt as of June 30, 2021 was $835.0 million. As of August 2, 2021, we had available liquidity of $161.9 million. To the extent actual operating results, realized commodity prices or uses of cash differ from our production, revenues, operating cash flow and EBITDA, whichassumptions, our liquidity could limit our ability to comply with the restrictive covenants in our revolving credit facility and other existing indebtedness.be adversely affected. See 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 stateNote 5 of the first lien market andnotes to 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.
Post-Emergence Debt. On the Emergence Date, pursuant to the terms of the Plan, we entered into a reserve-based credit agreement providing for the Exit Credit Facility, which features an initial borrowing base of $580.0 million. The Exit Credit Facility consists of the Exit Facility and the First-Out Term Loan. The borrowing base will be redetermined semiannually on or around May 1 and November 1 of each year. The next scheduled redetermination will be on or around November 1, 2021.
The Exit Facility provides for a $150.0 million sublimit of the aggregate commitments that is available for the issuance of letters of credit. The Exit Facility also includes a $40 million availability blocker that remains in place until Successful Midstream Resolution (as defined in the Exit Credit Agreement), as discussed in Note 9. The Exit Facility bears interest at a rate equal to, at our election, either (a) LIBOR plus an applicable margin that varies from 3.00% to 4.00% per annum or (b) a base rate plus an applicable margin that varies from 2.00% to 3.00% per annum. The First-Out Term Loan Facility bears interest at a rate equal to, at Gulfport’s election, either (a) LIBOR (subject to a 1.00% floor) plus 4.50% or (b) a base rate (subject to a 2.00% floor) plus 3.50%. As of June 30, 2021, the Exit Facility and the First-Out Term Loan Facility bore interest at weighted average rates of 4.50% and 5.50%, respectively.
Additionally, on the Emergence Date, pursuant to the terms of the Plan, we issued $550 million aggregate principal amount of our Successor Senior Notes.
The Successor Senior Notes are guaranteed on a senior unsecured basis by each of the Company's subsidiaries that guarantee the Exit Credit Facility.
See Note 5 for additional discussion of our post-emergence debt.
Preferred Dividends. As discussed in Note 6 of the notes to our consolidated financial statements, holders of New Preferred Stock are entitled to receive cumulative quarterly dividends at a rate of 10% per annum of the Liquidation Preference (as defined below) with respect to cash dividends and 15% per annum of the Liquidation Preference with respect to dividends paid in kind as additional shares of New Preferred Stock (“PIK Dividends”). Gulfport must pay PIK Dividends for so long as the quotient obtained by dividing (i) Total Net Funded Debt (as defined in the Exit Credit Facility) by (ii) the last twelve (12) months of EBITDAX (as defined in the Exit Credit Facility) calculated as at the applicable record date is equal to or greater than 1.50. If such ratio is less than 1.50 such dividend may be paid in either cash or as PIK Dividends, subject to certain conditions.
On June 30, 2021, the company paid dividends on its New Preferred Stock, which included 1,006 shares of New Preferred Stock paid in kind and approximately $25 thousand of cash-in-lieu of fractional shares.
Supplemental Guarantor Financial Information. The Successor Senior Notes are guaranteed on a senior unsecured basis by all existing consolidated subsidiaries that guarantee our Exit Facility or certain other debt (the “Guarantors”). The Senior Notes are not guaranteed by Grizzly Holdings or Mule Sky, LLC (the “Non-Guarantors”). The Guarantors are 100% owned by 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. 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 Successor Senior Notes and the guarantees are effectively subordinated to all of our and the subsidiary guarantors' secured indebtedness (including all borrowings and other obligations under our amended and restated credit agreement) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated to all indebtedness and other liabilities of any of our subsidiaries that do not guarantee the Successor Senior Notes.

SEC Regulation S-X Rule 13-01 requires the presentation of "Summarized Financial Information" to replace the "Condensed Consolidating Financial Information" required under Rule 3-10. Rule 13-01 allows the omission of Summarized Financial Information if assets, liabilities and results of operations of the Guarantors are not materially different than the corresponding amounts presented in our consolidated financial statements. The Parent and Guarantor subsidiaries comprise our material operations. Therefore, we concluded that the presentation of the Summarized Financial Information is not required as our Summarized Financial Information of the Guarantors is not materially different from our consolidated financial statements.
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
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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, 2020,2021, we had the following open natural gas, oil and NGL derivative instruments:
Natural Gas DerivativesNatural Gas DerivativesNatural Gas Derivatives
YearYearType of Derivative InstrumentIndexDaily Volume (MMBtu/day)Weighted
Average Price ($)		YearType of Derivative InstrumentIndexDaily Volume (MMBtu/day)Weighted
Average Price ($)
2020SwapsNYMEX Henry Hub357,000  2.86  
2020Basis SwapsVarious70,000  (0.12) 
20212021Costless CollarsNYMEX Henry Hub250,000  2.46/2.812021SwapsNYMEX Henry Hub221,500 $2.79 
20222022SwapsNYMEX Henry Hub80,411 $2.80 
20212021Basis SwapsRex Zone 366,576 $(0.16)
20222022Basis SwapsRex Zone 324,658 $(0.10)
20212021Costless CollarsNYMEX Henry Hub575,000 $2.58/$2.97
20222022Costless CollarsNYMEX Henry Hub406,747 $2.58/$2.91
20222022Sold Call OptionsNYMEX Henry Hub628,000  2.90  2022Sold Call OptionsNYMEX Henry Hub152,675 $2.90 
20232023Sold Call OptionsNYMEX Henry Hub628,000  2.90  2023Sold Call OptionsNYMEX Henry Hub627,675 $2.90 
Oil DerivativesOil DerivativesOil Derivatives
YearYearType of Derivative InstrumentIndexDaily Volume (Bbls/day)Weighted
Average Price ($)		YearType of Derivative InstrumentIndexDaily Volume (Bbl/day)Weighted
Average Price ($)
2020SwapsNYMEX WTI3,000  35.49  
20212021SwapsNYMEX WTI3,250 $57.35 
20222022SwapsNYMEX WTI1,000 $67.00 
20222022Costless CollarsNYMEX WTI1,500 $55.00/$60.00
NGL DerivativesNGL DerivativesNGL Derivatives
YearYearType of Derivative InstrumentIndexDaily Volume (Bbls/day)Weighted
Average Price ($)		YearType of Derivative InstrumentIndexDaily Volume (Bbl/day)Weighted
Average Price ($)
2020SwapsMont Belvieu C31,500  20.27  
20212021SwapsMont Belvieu C33,100 $27.80 
20222022SwapsMont Belvieu C3496 $27.30 
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 commitmentsexpenditures have historically been primarily forrelated to the execution of our drilling programs and discounted repurchases of our senior notes.completion activities in addition to certain lease acquisition activities. 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.prices.
Our capital expenditures for 20202021 are currently estimated to be in the range of $265.0$270 million to $285.0$290 million for drilling and completion expenditures. In addition, we currently expect to spend $20.0 million to $25.0approximately $20 million in 20202021 for non-drilling and completion expenditures, which includes acreage expenses, primarily lease extensions in the Utica Shale. The midpoint
Proceeds from Issuance of Preferred Stock. On the 2020 rangeEmergence Date, pursuant to the Plan, we conducted a Rights Offering and issued and issued 50,000 shares of capital expenditures is more than 50% lower thanNew Preferred Stock at $1,000 per share to holders of claims against the $602.5Predecessor Subsidiaries, raising $50 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.proceeds.
Cash Flow from Operating Activities. Net cash flow provided by operating activities was $38.4 million for the Successor Period and $172.2 million for the Current Predecessor YTD Period as compared to $247.2 million for the six months ended June 30, 2020 as compared to $399.8 million for the same period in 2019. ThisPrior Predecessor YTD Period. These decrease waswere primarily the result of a significant decreasereorganization items related to our Chapter 11 Cases, offset partially by an increase in cash receipts from our oil and natural gas purchasers due to increased realized gas prices as well as decreases in our production volumes.commodities pricing.
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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.
UseUses of Funds. The following table presents the uses of our cash and cash equivalents for the six months ended June 30, 2020successor period, Current Predecessor YTD Period, and 2019:the Prior Predecessor YTD Period:
Six months ended June 30,
20202019SuccessorPredecessor
(In thousands)Period from May 18, 2021 through June 30, 2021Period from January 1, 2021 through May 17, 2021Six Months Ended June 30, 2020
Oil and Natural Gas Property Cash Expenditures:Oil and Natural Gas Property Cash Expenditures:Oil and Natural Gas Property Cash Expenditures:
Drilling and completion costsDrilling and completion costs255,904  435,583  Drilling and completion costs$37,009 $94,128 $255,904 
Leasehold acquisitionsLeasehold acquisitions10,098  25,778  Leasehold acquisitions422 2,752 10,098 
OtherOther8,849  46,954  Other2,993 5,450 8,849 
Total oil and natural gas property expendituresTotal oil and natural gas property expenditures$274,851  $508,315  Total oil and natural gas property expenditures$40,424 $102,330 $274,851 
Other Uses of Cash and Cash EquivalentsOther Uses of Cash and Cash EquivalentsOther Uses of Cash and Cash Equivalents
Principal payments on pre-petition revolving credit facility, netPrincipal payments on pre-petition revolving credit facility, net$— $292,911 $— 
Principal payments on DIP credit facilityPrincipal payments on DIP credit facility— 157,500 — 
Principal payments on exit credit facility, netPrincipal payments on exit credit facility, net17,751 — — 
Cash paid to repurchase senior notesCash paid to repurchase senior notes22,827  —  Cash paid to repurchase senior notes— — 22,827 
Cash paid to repurchase common stock under approved stock repurchase program—  30,000  
OtherOther801  5,444  Other1,227 7,497 801 
Total other uses of cash and cash equivalentsTotal other uses of cash and cash equivalents$23,628  $35,444  Total other uses of cash and cash equivalents$18,978 $457,908 $23,628 
Total uses of cash and cash equivalentsTotal uses of cash and cash equivalents$298,479  $543,759  Total uses of cash and cash equivalents$59,402 $560,238 $298,479 
Drilling and Completion Costs. During six months ended June 30, 2020,the Current Combined YTD Period, we spud 1210 gross (11.1 net)and net and commenced sales from 13nine gross and net operated wells in the Utica Shale for a total cost of approximately $141.5 million.$91.9 million. During the six months ended June 30, 2020,Current Combined YTD Period, we spud sixtwo gross (5.2(1.97 net) and commenced sales from four11 gross (3.8(9.3 net) operated wells in the SCOOP for a total cost of approximately $42.2 million.$52.8 million.
During the six months ended June 30, 2020,2021, we did not participate in any wells that were spud or turned to sales by other operators on our Utica Shale acreage. In addition, 5.00five gross (0.03(0.001 net) wells were spud and 5.0016 gross (3.5(0.05 net) wells were turned to sales by other operators on our SCOOP acreage during the six months ended June 30, 2020.Current Combined YTD Period.
Drilling and completion costs presented in this section reflect incurred costs while drilling and completion costs presented above in Uses of Funds section reflect cash payments for drilling and completions. Incurred capital expenditures and cash capital expenditures may vary from period to period due to the cash payment cycle.
Contractual and Commercial Obligations
We have various contractual obligations in the normal course of our operations and financing activities. See Note 93 andfor discussion of changes in contractual obligations as a result of emergence from bankruptcy. See Note 139 of the notes to our consolidated financial statements for further discussion of our firm transportation and gathering agreements subsequent to the termination of our Master Services Agreement with Stingray Pressure Pumping LLC, a subsidiary of Mammoth Energy Services, Inc. and a related party.Emergence Date. 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, 2019.2020.    
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, 2020,2021, our material off-balance sheet arrangements and transactions include $324.1$114.8 million in letters of credit outstanding against our revolving credit facilityExit Facility and $119.5$90.7 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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materially affect our liquidity or availability of our capital resources. See Note 9 to our consolidated financial statements for further discussion of the various financial guarantees we have issued.
Critical Accounting Policies and Estimates
As of June 30, 2020,2021, there have been no significant changes in our critical accounting policies from those disclosed in our 20192020 Annual Report on Form 10-K.
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Cautionary Note Regarding Forward-Looking Statements
This Form 10-Q may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (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 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 Form 10-Q that address activities, events or developments that we expect or anticipate will or may occur in the future, including the expected impact of the COVID-19 pandemic on our business, our industry and the global economy, estimated future net revenues from oil and gas reserves and the present value thereof, future capital expenditures (including the amount and nature thereof), 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 our expectations and beliefs 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 that 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 the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed in Item 1A. “Risk Factors” and Item 7. “Management's Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2020 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 Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report.
We may use the Investors section of our website (www.gulfportenergy.com) to communicate with investors. It is possible that the financial and other information posted there could be deemed to be material information. The information on our website is not part of this Quarterly Report on Form 10-Q.
ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Natural Gas, Oil and Natural Gas Liquids Derivative Instruments. Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL. To mitigate a portion of our exposure to adverse price changes, we have entered into various derivative instruments. Our natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to predict with greater certainty the 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 storage inventory levels, industry decline rates for base production and weather trends. Executive management is involved in all risk management activities and the Board of Directors reviews
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our derivative program at its quarterly board meetings. We believe we have sufficient internal controls to prevent unauthorized trading.
We use derivative instruments to achieve our risk management objectives, including swaps, options and costless collars. All of these are described in more detail below. We typically use swaps for a large portion of the oil and natural gas price risk we hedge. We have also sold calls, taking advantage of premiums associated with market price volatility.
We determine the notional volume potentially subject to derivative contracts by reviewing our overall estimated future production levels, which are derived from extensive examination of existing producing reserve estimates and estimates of likelyestimated production from new drilling. Production forecasts are updated at least monthly and adjusted if necessary to actual results and activity levels. We do not enter into derivative contracts for volumes in excess of our share of forecasted production, and if production estimates were lowered for future periods and derivative instruments are already executed for some volume above the new production forecasts, the positions would beare typically reversed. The actual fixed priceprices on our derivative instruments is derived from the reference NYMEX price,prices from 3rd party indices such as reflected in current NYMEX trading. The pricing dates of our derivative contracts follow NYMEX futures.NYMEX. All of our commodity derivative instruments are net settled based on the difference between the fixed price as stated in the contract and the floating-price, resulting in a net amount due to or from the counterparty.
We review our derivative positions continuously and if future market conditions change and prices are at levels we believe could jeopardize the effectiveness of a position, we will mitigate this risk by either negotiating a cash settlement with our counterparty, restructuring the position or entering a new trade that effectively reverses the current position. The factors we consider in closing or restructuring a position before the settlement date are identical to those we review when deciding to enter the original derivative position. Gains or losses related to closed positions will be recognized in the month specified in the original contract.
We have determined the fair value of our derivative instruments utilizing established index prices, volatility curves, discount factors and discount factors.option pricing models. 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, 2020,2021, our natural gas, oil and NGL derivative instruments consisted of the following types of instruments:
•Swaps: We receive a fixed price and pay a floating market price to the counterparty for the hedged commodity. In exchange for higher fixed prices on certain of our swap trades, we may sell call options.
•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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•Call Options: We sell, and occasionally buy, call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, we pay the counterparty the excess on sold call options, and we receive the excess on bought call options. If the market price settles below the fixed price of the call option, no payment is due from either party.
•Costless Collars: These instruments have a set floor and 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 June 30, 2020:2021:
LocationDaily Volume (MMBtu/day)Weighted
Average Price
Remaining 2020NYMEX Henry Hub357,000  $2.86  
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LocationDaily Volume
(Bbls/day)		Weighted
Average Price
Remaining 2020NYMEX WTI3,000  $35.49  

LocationDaily Volume
(Bbls/day)		Weighted
Average Price
Remaining 2020Mont Belvieu C31,500  $20.27  
LocationDaily VolumeWeighted
Average Price
Natural Gas (MMBtu/day)
Remaining 2021NYMEX Henry Hub221,500 $2.79 
2022NYMEX Henry Hub80,411 $2.80 
Oil (Bbl/day)
Remaining 2021NYMEX WTI3,250 $57.35 
2022NYMEX WTI1,000 $67.00 
NGL (Bbl/day)
Remaining 2021Mont Belvieu C33,100 $27.80 
2022Mont Belvieu C3496 $27.30 
We
In the second half of 2019, we sold 2022 and 2023 natural gas call options in exchange for a premium, and used the associated premiums to enhance the fixed price for a portion of the fixed priceon certain natural gas swaps primarily for 2020 listed above. We hadthat settled in 2020. Each call option has an established ceiling price of $2.90/MMBtu. If monthly NYMEX natural gas prices settle above the following open$2.90 ceiling price, we are required to pay the option counterparty an amount equal to the difference between the referenced NYMEX natural gas settlement price and $2.90 multiplied by the hedged contract volumes. Below is a summary of our sold call option positions atas of June 30, 2020:2021.
LocationDaily Volume (MMBtu/day)Weighted
Average Price		LocationDaily VolumeWeighted
Average Price
Natural Gas (MMBtu/day)Natural Gas (MMBtu/day)
20222022NYMEX Henry Hub628,000  $2.90  2022NYMEX Henry Hub152,675 $2.90 
20232023NYMEX Henry Hub628,000  $2.90  2023NYMEX Henry Hub627,675 $2.90 
We had the following openBelow is a summary of our 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  
Asas of June 30, 2020, the Company had the following natural gas2021:
LocationDaily VolumeWeighted Average Floor PriceWeighted Average Ceiling Price
Natural Gas (MMBtu/day)
Remaining 2021NYMEX Henry Hub575,000 $2.58 $2.97 
2022NYMEX Henry Hub406,747 $2.58 $2.91 
Oil (Bbl/day)
2022NYMEX WTI1,500 $55.00 $60.00 
Below is a summary of our 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 endedas of June 30, 2020, we early terminated oil fixed price swaps which represented approximately 6,000 BBls2021:
Gulfport PaysGulfport ReceivesDaily VolumeWeighted Average Fixed Spread
Natural Gas (MMBtu/day)
Remaining 2021Rex Zone 3NYMEX Plus Fixed Spread66,576 $(0.16)
2022Rex Zone 3NYMEX Plus Fixed Spread24,658 $(0.10)
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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, NYMEX WTI for oil, 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.the applicable index.
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Under our 2020 contracts, we have hedged approximately 59% to 63% of our estimated 2020 production. SuchOur hedge arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or commodity prices increase. At June 30, 2020,2021, we had a net assetliability derivative position of $3.3$301.0 million as compared to a net asset derivative position of $139.5$3.3 million as of June 30, 2019, related to our hedging portfolio.2020. Utilizing actual derivative contractual volumes, a 10% increase in underlying commodity prices would have reduced the fair value of these instruments by approximately $48.8$160.3 million, while a 10% decrease in underlying commodity prices would have increased the fair value of these instruments by approximately $43.1$145.1 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 United States, or, if the eurodollar rates are elected, the eurodollar rates. At June 30, 2020,2021, we had $123.0$105.0 million in borrowings outstanding under our revolving credit facilityExit Facility which bore interest at a weighted average rate of 2.44%4.50%. At June 30, 2021, we had $180.0 million in borrowings outstanding under our First-Out Term Loan which bore interest at a weighted average rate of 5.50%. As of June 30, 2020,2021, we did not have any interest rate swaps to hedge our interest rate risks.

ITEM 4.CONTROLS AND PROCEDURES
Evaluation of Disclosure Control and Procedures. Under the directionsupervision of our Chief Executive Officer and President and our Chief Financial Officer, and with participation of management, 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 June 30, 2020,2021, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and President and our Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and President and our Chief Financial Officer have concluded that, as of June 30, 2020,2021, our disclosure controls and procedures wereare effective.
In designing and evaluating the Company's disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not effective becauseabsolute, assurance that the objectives of the material weaknesscontrol system will be met. In addition, the design of any control system is based in our internal control over financial reporting describedpart upon certain assumptions about the likelihood of future events and the application of judgment in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9Aevaluating the cost-benefit relationship 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 newpossible controls and processes overprocedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that the evaluation and transfer of unevaluated costs to the amortizable base. Our management believes that these actionsCompany's controls will remediate the material weaknesssucceed in internal control over financial reporting.

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

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

In December 2019, we filed a lawsuit against Stingray Pressure Pumping LLC, a subsidiary of Mammoth Energy (“Stingray”), for breach of contract and to terminate the Master Services Agreement for pressure pumping services, effective as of October 1, 2014, as amended (the “Master Services Agreement”), between Stingray and us. In March 2020, Stingray filed a counterclaim against us in the Superior Court of the State of Delaware. The counterclaim alleges that we have breached the Master Services Agreement. The counterclaim seeks actual damages, which the complaint calculates to be approximately 28 million as of June 2020 (such amount to increase each month), the payment of reasonable attorney fees and legal expenses and pre- and post-judgment interest as allowed, and such other and further relief which it may be justly entitled.
In April 2020, Bryon Lefort, individually and on behalf of similarly situated individuals, filed an action against us in the United States District Court for the Southern District of Ohio Eastern Division. The complaint alleges that we violated the Fair Labor Standards Act (“FLSA”), the Ohio Wage Act and the Ohio Prompt Pay Act by classifying the plaintiffs as independent contractors and paying them a daily rate with no overtime compensation for hours worked in excess of 40 hours per week. The complaint seeks to recover unpaid regular and overtime wages, liquidated damages in an amount equal to six percent of all unpaid overtime compensation, the payment of reasonable attorney fees and legal expenses and pre-judgment and post-judgment interest, and such other damages that may be owed to the workers.
These cases are still in their early stages. As a result, we have not had the opportunity to evaluate the allegations made in the plaintiffs' complaints and intend to vigorously defend the suits.
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 liabilityinformation 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 involvedItem 1. Legal Proceedings is set forth in various lawsuits and disputes incidental to our business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions.
Environmental Contingencies
The nature of the oil and gas business carries with it certain environmental risks for 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 $180,000 to the ODEQ. The Order received final approval at the ODEQ and expects to be finalized in the third quarter of 2020.
Other Matters
Based on management’s current assessment, they are of the opinion that no pending or threatened lawsuit or dispute relating to its business operations is likely to have a material adverse effect on their futureaccompanying condensed consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.

statements.
ITEM 1A.RISK FACTORS
Our 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 below and under "Risk Factors" in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2019. The risk factors below updates2020.
Risks Related to our risk factors previously discussed inEmergence from Bankruptcy

We recently emerged from bankruptcy, which may adversely affect our Annual Report on Form 10-Kbusiness and relationships.

It is possible that our having filed for bankruptcy and our recent emergence from bankruptcy may adversely affect our business and relationships with customers, vendors, contractors or employees. Due to uncertainties, many risks exist, including the fiscal year ended December 31, 2019.following:
Any significant reduction in our borrowing base under our revolving credit facility as a result of periodic borrowing base redeterminations•key vendors or otherwiseother contract counterparties may terminate their relationships with us or an inability to refinance our revolving credit facility prior to its maturity may negatively impact require additional financial assurances or enhanced performance from us;
•our ability to fundrenew existing contracts and compete for new business may be adversely affected;
•our ability to attract, motivate and/or retain key executives may be adversely affected; and
•competitors may take business away from us, and our ability to attract and retain customers may be negatively impacted.

The occurrence of one or more of these events could have a material and adverse effect on our operations, financial condition and wereputation. We cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations in the future.

Our actual financial results after emergence from bankruptcy may not have sufficient fundsbe comparable 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 gashistorical financial information as a result of the COVID-19 pandemicimplementation of the Plan 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 complytransactions contemplated thereby.

In connection with the restrictive covenants in our revolving credit facilitydisclosure statement we filed with the Bankruptcy Court, 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 ablethe hearing to refinance the credit facility with a new credit facility or other financing. Considering the current stateconsider confirmation of the first lien market and our elevated leverage profile, there is substantial risk that a refinancing will not be availablePlan, we prepared projected financial information to us on reasonable terms. A current liability underdemonstrate to the revolving credit facility at year end 2020 may result in a qualified audit opinion which could result in a default underBankruptcy Court the termsfeasibility of the current revolving credit facility. As a result of these uncertainties, management has concluded that there is substantial doubt aboutPlan and our ability to continue as a going concern. Failure to meetoperations upon our obligations underemergence from bankruptcy. Those projections were prepared solely for the purpose of bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. At the time they were prepared, the projections reflected numerous assumptions concerning 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,anticipated future performance with respect to prevailing and anticipated market and economic conditions that were and remain beyond our control and that may not materialize. Projections are inherently subject to substantial and numerous uncertainties and to a wide variety of significant business, economic and competitive risks and the revolving credit facility,assumptions underlying the potential foreclosureprojections and/or valuation estimates may prove to be wrong in material respects. Actual results may vary significantly from those contemplated by the projections. As a result, investors should not rely on these projections.

The market price of our securities is subject to volatility.

Upon our emergence from bankruptcy, our old common stock was cancelled and we issued New Common Stock.The market price of our New Common Stock could be subject to wide fluctuations in response to, and the collateral securing such debt, and could cause a cross-default underlevel of trading that develops with our New Common Stock may be affected by, numerous factors, many of which are beyond our control.These factors include, among other outstanding indebtedness. Further, if the outstanding borrowings underthings, our revolving credit facility were to exceed the borrowing basenew capital structure as a result of any such redetermination, we would be requiredthe transactions contemplated by the Plan, our limited trading history subsequent to repayour emergence from bankruptcy, our limited trading volume, 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 renewalslack 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;comparable
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•historical financial information due to our operations may be disruptedadoption of fresh start accounting, actual or impaired, thus loweringanticipated variations in our production level, if a significant portionoperating results and cash flow, the nature and content of our employeesearnings releases, announcements or contractors are unable to work due to illnessevents that impact our products, customers, competitors or ifmarkets, business conditions in 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 ingeneral state of the securities markets and the market for energy-related stocks, as well as general business environmenteconomic and market conditions and other factors that may affect our ability to executefuture results, including those described in this Part II, Item 1A of this Quarterly Report 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 withForm 10-Q.

Upon emergence from bankruptcy, the obligations under anycomposition of our debt instruments,board of directors changed significantly.

The composition of our board of directors changed significantly upon emergence from bankruptcy. Our new board is comprised of five directors, 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,Company's Interim Chief Executive Officer, Timothy Cutt, and we may revise or delay our strategic plans.
We expect that the principal areas of operational risk for us are availability of service providersfour non-employee directors, David Wolf, Guillermo Martinez, Jason Martinez 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.David Reganato. While we believeexpect to engage in an orderly transition process as we integrate newly appointed board members, our new board of directors may change views on strategic initiatives and a range of issues that we are following best practices under COVID-19 guidance,will determine the potential for transmission still exists. In certain instances, it may be necessary or determined advisable for us to delay development operations.
In addition,future of the COVID-19 pandemic has increased volatility and caused negative pressure in the capital and credit markets.Company. As a result, wethe future strategy and plans of the Company may experience difficulty accessingdiffer materially from those of 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 operationspast.

Future sales or the borrowing capacity under our revolving credit facility are insufficient to fund our capital expenditures and we are unable to obtain the capital necessaryavailability for our planned capital budget or our operations, we could be required to curtail our operations and the developmentsale of substantial amounts of our properties, which in turn could lead to a decline in our reserves and production, andcommon stock, or the perception that these sales may occur, could adversely affect the trading price of our business, resultscommon stock and could impair our ability to raise capital through future sales of operations and financial position.equity securities.
To
A large percentage of our common stock is held by a relatively small number of investors. In connection with our emergence from bankruptcy protection, we entered into the extentRegistration Rights Agreement pursuant to which we have agreed to file a registration statement with the COVID-19 pandemic adversely affectsSEC to facilitate potential future sales of our business and financial results, it may also havecommon stock by such investors. Sales of a substantial number of shares of our common stock in the effect of heightening manypublic markets, or even the perception that these sales might occur (such as upon the filing of the other risks set forth in Item 1A.aforementioned registration statement), “Risk Factors” incould impair our Annual Report on Form 10-K, such as those relatingability to raise capital through a future sale of, or pay for acquisitions using, 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.equity securities.

We expectcannot predict the effect that wefuture sales of our common stock will have on the price at which the common stock trades. Sales of substantial amounts of our common stock, or the perception that such sales could occur, may adversely affect the trading price of our common stock.

Our amended and restated certificate of incorporation provides, subject to certain exceptions, that the Court of Chancery of the State of Delaware will be unablethe sole and exclusive forum for certain stockholder litigation matters, which could limit our stockholders’ ability to meetobtain a favorable judicial forum for disputes with us or our firm commitment delivery obligations underdirectors, officers, employees or stockholders.

Our amended and restated certificate of incorporation provides, subject to limited exceptions, that the Court of Chancery of the State of Delaware will, to the fullest extent permitted by law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our firm transportation contracts relatingbehalf; (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors or officers to us, our Utica Shalestockholders, our creditors or SCOOP acreage dueother constituents; (iii) any action asserting a claim against us, any director or our officers arising pursuant to decreased developmental activities,any provision of the DGCL, our certificate of incorporation or our by-laws; or (iv) any action asserting a claim against us, any director or our officers that is governed by the internal affairs doctrine. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or any of our directors or officers or stockholders which will resultmay discourage lawsuits with respect to such claims. Alternatively, if a court were to find the choice of forum provision contained in fees andour certificate of incorporation to be inapplicable or unenforceable in an action, we may incur additional costs associated with resolving such action in other jurisdictions, which could have a material adverse effect on our operations.
Asbusiness, financial condition and results of June 30, 2020, we had entered into firm transportation contracts to deliver approximately 1,455,000 MMBtu per day for the remainder of 2020 and 2021, respectively. Under these firm transportation contracts, we are obligated to deliver minimum daily volumes or pay fees for any deficiencies in deliveries. As a result of the reduced production from our Utica Shale or SCOOP acreage due to decreased developmental activities, taking into consideration the current low commodity price environment, we expect that we will be unable to meet our obligations under the existing firm transportation contracts, resulting in fees, which may be significant and may have a material adverse effect on our operations.

ITEM 2.UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
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Unregistered Sales of Equity Securities
    None.
Issuer Repurchases of Equity Securities
    Our common stock repurchase activity for the three months ended June 30, 2020Successor Period and Current Predecessor Quarter 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  —  
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Predecessor PeriodTotal number of shares purchased (1)Average price paid per shareTotal number of shares purchased as part of publicly announced plans or programs
April10,470 $0.05 — 
(1)During the three months ended June 30, 2020,April 2021, we repurchased and canceled 27,29410,470 shares of our common stock at a weighted average price of $1.04$0.05 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.Our Bankruptcy Filing described above constitutes an event of default that accelerated our obligations under our Pre-Petition Revolving Credit Facility and our Predecessor Senior Notes. Under the Bankruptcy Code, the creditors under these debt agreements were stayed from taking any action against us as a result of an event of default. See Note 3 and Note 5 to the unaudited consolidated financial statements included in Part I, Item 1 of this Form 10-Q for additional details about the impact of the Plan on these amounts.
ITEM 4.MINE SAFETY DISCLOSURES
Not applicable.
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ITEM 5.OTHER INFORMATION

Incentive compensation program

In connection with a comprehensive reviewBased on assumption of the Company’s compensation programsadditional responsibilities, Mr. Craine’s title was changed to Chief Legal and in consultation with its independent compensation consultantAdministrative Officer and legal advisors, the Board of Directors has determined that significant changes are appropriatehis base salary was increased 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:
Named Executive OfficerRestricted Stock Units
David M. Wood43,557
Michael Sluiter17,060
Additionally, on February 27, 2020, the following named executive officer disposed of shares to satisfy tax withholding obligations:
Named Executive OfficerRestricted Stock Units
Donnie Moore19,498

$450,000 annually.
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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
INDEX OF EXHIBITS
Incorporated by Reference
Exhibit NumberDescriptionFormSEC File NumberExhibitFiling DateFiled or Furnished Herewith
2.18-K001-195142.24/29/2021
3.18-K000-195143.15/17/2021
3.28-K000-195143.25/17/2021
4.18-K000-195144.15/17/2021
4.28-K000-195144.25/17/2021
10.18-K001-1951410.15/17/2021
10.28-K001-1951410.25/17/2021
10.38-K001-1951410.35/17/2021
10.4*8-K000-1951410.45/17/2021
10.5*8-K000-1951410.55/17/2021
10.6*8-K000-1951410.65/17/2021
10.7*10.7X
10.8*10.8X
10.9*10.9X
31.1X
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10.2+8-K000-1951410.23/17/2020
10.3X
10.48-K001-1951410.17/30/2020
31.1X
31.2X
32.1X
32.2X
101.INSXBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.X
101.SCHXBRL Taxonomy Extension Schema Document.X
101.CALXBRL Taxonomy Extension Calculation Linkbase Document.X
101.DEFXBRL Taxonomy Extension Definition Linkbase Document.X
101.LABXBRL Taxonomy Extension Labels Linkbase Document.X
101.PREXBRL Taxonomy Extension Presentation Linkbase Document.X
104Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.X
+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 compensationor compensatory plan or arrangement.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: August 6, 20209, 2021
 
GULFPORT ENERGY CORPORATION
By:/s/    Quentin HicksWilliam Buese
Quentin HicksWilliam Buese
Executive Vice President & Chief Financial Officer

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