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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 March 31,September 30, 2021
OR
☐TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934
For the transition period from                    to                                    
Commission File Number 001-19514
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:
None(1)
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common Stock, $0.0001 par value per shareGPORThe New York Stock Exchange
(1) On November 27, 2020, our common stock was suspended from trading on the NASDAQ Stock Market LLC ("NASDAQ"). On November 30, 2020, our common stock began trading on the OTC Pink Marketplace maintained by the OTC Markets Group, Inc. under the symbol “GPORQ". On February 2, 2021, NASDAQ filed a Form 25 delisting our common stock from trading on NASDAQ, which delisting became effective 10 days after the filing of the Form 25. In accordance with Rule 12d2-2 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), the de-registration of our common stock under section 12(b) of the Exchange Act became effective on February 12, 2021.
Securities registered pursuant to Section 12(g) of the Act:
Common Stock
(Title of Class)
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 April 30,October 28, 2021, 160,892,44720,585,964 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 YTD Period. Combined Current Successor YTD Period and Current Predecessor YTD Period.
Current Predecessor YTD Period. Period from January 1, 2021 through May 17, 2021.
Current Successor Quarter. Period from July 1, 2021 through September 30, 2021.
Current Successor YTD Period. Period from May 18, 2021 through September 30, 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.
Exit Credit Facility. Collectively, the First-Out Term Loan 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. 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 WellsNew Common Stock. Refers to$0.0001 par value common stock issued by the sumSuccessor on the Emergence Date.
New Credit Facility. The Third Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A. as administrative agent and various lender parties, providing for a new money senior secured reserve-based revolving credit facility effective as of October 14, 2021.
New Preferred Stock. $0.0001 par value preferred stock issued by the fractional working interests owned in gross acres or gross wells.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.
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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 timetime-to-time party thereto with a maximum facility amount of $580 million.
Prior Predecessor Quarter. Period from July 1, 2020 through September 30, 2020.
Prior Predecessor YTD Period. Period from January 1, 2020 through September 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.
Undeveloped AcreageSuccessor Senior Notes. 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.8.000% Senior Notes due 2026.
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
(DEBTOR-IN-POSSESSION)
March 31, 2021December 31, 2020
(Unaudited)
(In thousands, except share data)
Assets
Current assets:
Cash and cash equivalents$179,701 $89,861 
Accounts receivable—oil and natural gas sales133,996 119,879 
Accounts receivable—joint interest and other12,904 12,200 
Prepaid expenses and other current assets134,509 160,664 
Short-term derivative instruments12,422 27,146 
Total current assets473,532 409,750 
Property and equipment:
Oil and natural gas properties, full-cost accounting, $1,413,774 and $1,457,043 excluded from amortization in 2021 and 2020, respectively10,895,625 10,816,909 
Other property and equipment88,835 88,538 
Accumulated depletion, depreciation, amortization and impairment(8,874,899)(8,819,178)
Property and equipment, net2,109,561 2,086,269 
Other assets:
Equity investments27,044 24,816 
Long-term derivative instruments652 322 
Operating lease assets314 342 
Other assets16,545 18,372 
Total other assets44,555 43,852 
Total assets$2,627,648 $2,539,871 
Liabilities and Stockholders’ Deficit
Current liabilities:
Accounts payable and accrued liabilities$310,172 $244,903 
Short-term derivative instruments20,687 11,641 
Current maturities of long-term debt279,807 253,743 
Total current liabilities610,666 510,287 
Non-current liabilities:
Long-term derivative instruments43,267 36,604 
Total non-current liabilities43,267 36,604 
Liabilities subject to compromise2,261,453 2,293,480 
Total liabilities$2,915,386 $2,840,371 
Commitments and contingencies (Note 8)
00
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 outstanding0 0 
Stockholders’ deficit:
Common stock - $0.01 par value, 200.0 million shares authorized, 160.9 million issued and outstanding at March 31, 2021 and 160.8 million at December 31, 20201,609 1,607 
Paid-in capital4,215,162 4,213,752 
Accumulated other comprehensive loss(40,430)(43,000)
Accumulated deficit(4,464,079)(4,472,859)
Total stockholders’ deficit$(287,738)$(300,500)
Total liabilities and stockholders’ deficit$2,627,648 $2,539,871 
In thousands, except share data)

See accompanying notes to consolidated financial statements.
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GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(DEBTOR-IN-POSSESSION)
(Unaudited)
 Three months ended March 31,
20212020
(In thousands)
REVENUES:
Natural gas sales$235,321 $161,008 
Oil and condensate sales18,239 23,151 
Natural gas liquid sales23,776 16,913 
Net (loss) gain on natural gas, oil and NGL derivatives(29,978)98,266 
Total Revenues247,358 299,338 
OPERATING EXPENSES:
Lease operating expenses12,653 14,695 
Taxes other than income8,704 6,637 
Transportation, gathering, processing and compression105,867 110,357 
Depreciation, depletion and amortization41,147 78,028 
Impairment of oil and natural gas properties0 553,345 
Impairment of other property and equipment14,568 0 
General and administrative expenses12,757 15,622 
Accretion expense805 741 
Total Operating Expenses196,501 779,425 
INCOME (LOSS) FROM OPERATIONS50,857 (480,087)
OTHER EXPENSE (INCOME):
Interest expense3,261 32,990 
Interest income(143)(152)
Gain on debt extinguishment0 (15,322)
Loss from equity method investments, net342 10,789 
Reorganization items, net38,721 0 
Other expense(104)1,856 
Total Other Expense42,077 30,161 
INCOME (LOSS) BEFORE INCOME TAXES8,780 (510,248)
Income Tax Expense0 7,290 
NET INCOME (LOSS)$8,780 $(517,538)
NET INCOME (LOSS) PER COMMON SHARE:
Basic$0.05 $(3.24)
Diluted$0.05 $(3.24)
Weighted average common shares outstanding—Basic160,813 159,760 
Weighted average common shares outstanding—Diluted160,813 159,760 
SuccessorPredecessor
September 30, 2021December 31, 2020
(Unaudited)
Assets
Current assets:
Cash and cash equivalents$4,485 $89,861 
Accounts receivable—oil and natural gas sales185,941 119,879 
Accounts receivable—joint interest and other9,669 12,200 
Prepaid expenses and other current assets18,487 160,664 
Short-term derivative instruments2,142 27,146 
Total current assets220,724 409,750 
Property and equipment:
Oil and natural gas properties, full-cost method
Proved oil and natural gas properties1,831,762 9,359,866 
Unproved properties216,357 1,457,043 
Other property and equipment5,277 88,538 
Total property and equipment2,053,396 10,905,447 
Less: accumulated depletion, depreciation and amortization(212,403)(8,819,178)
Total property and equipment, net1,840,993 2,086,269 
Other assets:
Equity investments— 24,816 
Long-term derivative instruments961 322 
Operating lease assets34 342 
Other assets25,496 18,372 
Total other assets26,491 43,852 
Total assets$2,088,208 $2,539,871 

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)BALANCE SHEETS–CONTINUED
(DEBTOR-IN-POSSESSION)In thousands, except share data)
(Unaudited)
 Three months ended March 31,
20212020
(In thousands)
Net income (loss)$8,780 $(517,538)
Foreign currency translation adjustment2,570 (15,030)
Other comprehensive income (loss)2,570 (15,030)
Comprehensive income (loss)$11,350 $(532,568)
SuccessorPredecessor
September 30, 2021December 31, 2020
(Unaudited)
Liabilities, Mezzanine Equity and Stockholders’ Equity (Deficit)
Current liabilities:
Accounts payable and accrued liabilities$436,172 $244,903 
Short-term derivative instruments560,722 11,641 
Current portion of operating lease liabilities34 — 
Current maturities of long-term debt60,000 253,743 
Total current liabilities1,056,928 510,287 
Non-current liabilities:
Long-term derivative instruments272,935 36,604 
Asset retirement obligation19,854 — 
Long-term debt, net of current maturities689,502 — 
Total non-current liabilities982,291 36,604 
Liabilities subject to compromise— 2,293,480 
Total liabilities$2,039,219 $2,840,371 
Commitments and contingencies (Note 9)
00
Mezzanine Equity:
New Preferred Stock - $0.0001 par value, 110 thousand shares authorized, 57.9 thousand issued and outstanding at September 30, 202157,920 — 
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 - $0.0001 par value, 42.0 million shares authorized, 20.6 million issued and outstanding at September 30, 20212 — 
Additional paid-in capital692,182 4,213,752 
New Common Stock held in reserve, 938 thousand shares(30,216)— 
Accumulated deficit(670,899)(4,472,859)
Total stockholders’ deficit$(8,931)$(300,500)
Total liabilities, mezzanine equity and stockholders’ deficit$2,088,208 $2,539,871 

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ (DEFICIT) EQUITYOPERATIONS
(DEBTOR-IN-POSSESSION)
(Unaudited)

Paid-in
Capital		Accumulated Other
Comprehensive (Loss) Income		Accumulated
Deficit		Total Stockholders’
Deficit
Common Stock
 SharesAmount
(In thousands)
Balance at January 1, 2021160,762 $1,607 $4,213,752 $(43,000)$(4,472,859)$(300,500)
Net Income— — — — 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, 2021160,878 $1,609 $4,215,162 $(40,430)$(4,464,079)$(287,738)
In thousands, except per share data)

(Unaudited)

Paid-in
Capital		Accumulated
Other
Comprehensive Loss		Accumulated
Deficit		Total
Stockholders’
Equity
Common Stock
 SharesAmount
(In thousands)
Balance at January 1, 2020159,711 $1,597 $4,207,554 $(46,833)$(2,847,726)$1,314,592 
Net Loss— — — — (517,538)(517,538)
Other Comprehensive Income— — — (15,030)— (15,030)
Stock Compensation— — 2,104 — — 2,104 
Shares Repurchased(80)(1)(78)— — (79)
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 
See accompanying notes to consolidated financial statements.























SuccessorPredecessor
Three Months Ended September 30, 2021Three Months Ended September 30, 2020
REVENUES:
Natural gas sales$301,516 $155,163 
Oil and condensate sales33,279 16,012 
Natural gas liquid sales45,153 18,824 
Net loss on natural gas, oil and NGL derivatives(622,476)(53,823)
Total Revenues(242,528)136,176 
OPERATING EXPENSES:
Lease operating expenses13,864 13,393 
Taxes other than income11,844 6,102 
Transportation, gathering, processing and compression84,435 110,567 
Depreciation, depletion and amortization62,573 51,551 
Impairment of oil and natural gas properties— 270,874 
General and administrative expenses16,691 20,331 
Restructuring and liability management expenses2,858 8,984 
Accretion expense488 774 
Total Operating Expenses192,753 482,576 
LOSS FROM OPERATIONS(435,281)(346,400)
OTHER EXPENSE:
Interest expense16,351 34,321 
Loss from equity method investments, net— 153 
Other, net9,031 89 
Total Other Expense25,382 34,563 
LOSS BEFORE INCOME TAXES(460,663)(380,963)
Income tax expense650 — 
NET LOSS$(461,313)$(380,963)
Dividends on New Preferred Stock$(2,095)$— 
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS$(463,408)$(380,963)
NET LOSS PER COMMON SHARE:
Basic$(22.50)$(2.37)
Diluted$(22.50)$(2.37)
Weighted average common shares outstanding—Basic20,598 160,683 
Weighted average common shares outstanding—Diluted20,598 160,683 

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GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWSOPERATIONS—CONTINUED
(DEBTOR-IN-POSSESSION)In thousands, except per share data)
(Unaudited)
 Three months ended March 31,
20212020
(In thousands)
Cash flows from operating activities:
Net income (loss)$8,780 $(517,538)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization41,147 78,028 
Impairment of oil and natural gas properties0 553,345 
Impairment of other property and equipment14,568 0 
Loss from equity investments342 10,789 
Gain on debt extinguishment0 (15,322)
Net loss (gain) on derivative instruments29,978 (98,266)
Net cash receipts on settled derivative instruments125 70,733 
Deferred income tax expense0 7,290 
Other, net1,574 3,223 
Changes in operating assets and liabilities, net26,661 38,556 
Net cash provided by operating activities123,175 130,838 
Cash flows from investing activities:
Additions to oil and natural gas properties(56,895)(113,744)
Proceeds from sale of oil and natural gas properties15 44,383 
Other, net(296)(448)
Net cash used in investing activities(57,176)(69,809)
Cash flows from financing activities:
Principal payments on pre-petition revolving credit facility(2,202)(180,000)
Borrowings on pre-petition revolving credit facility26,050 125,000 
Repurchase of senior notes0 (10,204)
Other, net(7)(252)
Net cash provided by (used in) financing activities23,841 (65,456)
Net increase (decrease) in cash, cash equivalents and restricted cash89,840 (4,427)
Cash, cash equivalents and restricted cash at beginning of period89,861 6,060 
Cash, cash equivalents and restricted cash at end of period$179,701 $1,633 
SuccessorPredecessor
Period from May 18, 2021 through September 30, 2021Period from January 1, 2021 through May 17, 2021Nine Months Ended September 30, 2020
REVENUES:
Natural gas sales$413,234 $344,390 $456,859 
Oil and condensate sales50,866 29,106 47,553 
Natural gas liquid sales61,230 36,780 45,989 
Net (loss) gain on natural gas, oil and NGL derivatives(762,134)(137,239)71,414 
Total Revenues(236,804)273,037 621,815 
OPERATING EXPENSES:
Lease operating expenses17,980 19,524 41,166 
Taxes other than income16,900 12,349 19,039 
Transportation, gathering, processing and compression125,811 161,086 334,789 
Depreciation, depletion and amortization94,935 62,764 194,369 
Impairment of oil and natural gas properties117,813 — 1,357,099 
Impairment of other property and equipment— 14,568 — 
General and administrative expenses23,209 19,175 45,719 
Restructuring and liability management expenses2,858 — 9,601 
Accretion expense714 1,229 2,270 
Total Operating Expenses400,220 290,695 2,004,052 
LOSS FROM OPERATIONS(637,024)(17,658)(1,382,237)
OTHER EXPENSE (INCOME):
Interest expense25,245 4,159 99,677 
Gain on debt extinguishment— — (49,579)
Loss from equity method investments, net— 342 10,987 
Reorganization items, net— (266,898)— 
Other, net7,979 1,711 8,957 
Total Other Expense (Income)33,224 (260,686)70,042 
(LOSS) INCOME BEFORE INCOME TAXES(670,248)243,028 (1,452,279)
Income tax expense (benefit)650 (7,968)7,290 
NET (LOSS) INCOME$(670,898)$250,996 $(1,459,569)
Dividends on New Preferred Stock$(3,126)$— $— 
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS$(674,024)$250,996 $(1,459,569)
NET (LOSS) INCOME PER COMMON SHARE:
Basic$(32.87)$1.56 $(9.12)
Diluted$(32.87)$1.56 $(9.12)
Weighted average common shares outstanding—Basic20,507 160,834 160,053 
Weighted average common shares outstanding—Diluted20,507 160,834 160,053 

See accompanying notes to consolidated financial statements.
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GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)
(Unaudited)

SuccessorPredecessor
Three Months Ended September 30, 2021Three Months Ended September 30, 2020
Net loss$(461,313)$(380,963)
Foreign currency translation adjustment— 3,661 
Other comprehensive income— 3,661 
Comprehensive loss$(461,313)$(377,302)
SuccessorPredecessor
Period from May 18, 2021 through September 30, 2021Period from January 1, 2021 through May 17, 2021Nine Months Ended September 30, 2020
Net (loss) income$(670,898)$250,996 $(1,459,569)
Foreign currency translation adjustment— — (4,497)
Other comprehensive loss— — (4,497)
Comprehensive (loss) income$(670,898)$250,996 $(1,464,066)

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT)
(In thousands)
(Unaudited)
Common Stock Held in Reserve
Paid-in
Capital		Accumulated
Other
Comprehensive (Loss) Income		Reined Earnings Accumulated
Deficit		Total
Stockholders’
Equity (Deficit)
Common Stock
 SharesAmountSharesAmount
Balance at January 1, 2020 (Predecessor)159,711 $1,597 — $— $4,207,554 $(46,833)$(2,847,726)$1,314,592 
Net Loss— — — — — — (517,538)(517,538)
Other Comprehensive Loss— — — — — (15,030)— (15,030)
Stock Compensation— — — — 2,104 — — 2,104 
Shares Repurchased(80)(1)— — (78)— — (79)
Issuance of Restricted Stock211 2 — — (2)— — — 
Balance at March 31, 2020 (Predecessor)159,842 $1,598 — $— $4,209,578 $(61,863)$(3,365,264)$784,049 
Net Loss— $— — $— $— $— $(561,068)$(561,068)
Other Comprehensive Income— — — — — 6,872 — 6,872 
Stock Compensation— — — — 1,515 — — 1,515 
Shares Repurchased(27)— — — (28)— — (28)
Issuance of Restricted Stock301 3 — — (3)— — — 
Balance at June 30, 2020 (Predecessor)160,116 $1,601 — $— $4,211,062 $(54,991)$(3,926,332)$231,340 
Net Loss— $— — $— $— $— $(380,963)$(380,963)
Other Comprehensive Income— — — — — 3,661 — 3,661 
Stock Compensation— — — — 1,314 — — 1,314 
Shares Repurchased(136)(2)— — (127)— — (129)
Issuance of Restricted Stock782 8 — — (8)— — — 
Balance at September 30, 2020 (Predecessor)160,762 $1,607 — $— $4,212,241 $(51,330)$(4,307,295)$(144,777)


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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 — $— $4,213,752 $(43,000)$(4,472,859)$(300,500)
Net Income— — — — — — 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 — $— $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 $— $— $639,667 
Balance at May 18, 2021 (Successor)21,525 $2 (1,679)$(54,109)$693,774 $— $— $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)$692,890 $— $(209,586)$453,090 
Net Loss— $— — $— $— $— $(461,313)$(461,313)
Stock Compensation— — — — 1,387 — — 1,387 
Dividends on New Preferred Stock— — — — (2,095)— — (2,095)
Balance at September 30, 2021 (Successor)21,535 $2 (938)$(30,216)$692,182 $— $(670,899)$(8,931)
See accompanying notes to consolidated financial statements.
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GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)

SuccessorPredecessor
Period from May 18, 2021 through September 30, 2021Period from January 1, 2021 through May 17, 2021Nine Months Ended September 30, 2020
Cash flows from operating activities:
Net (loss) income$(670,898)$250,996 $(1,459,569)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization94,935 62,764 194,369 
Impairment of oil and natural gas properties117,813 — 1,357,099 
Impairment of other property and equipment— 14,568 — 
Loss from equity investments— 342 10,987 
Gain on debt extinguishment— — (49,579)
Net loss (gain) on derivative instruments762,134 137,239 (71,414)
Net cash (payments) receipts on settled derivative instruments(99,574)(3,361)225,364 
Non-cash reorganization items, net— (446,012)— 
Deferred income tax expense— — 7,290 
Other, net1,487 1,725 12,753 
Changes in operating assets and liabilities, net(41,260)153,894 (27,299)
Net cash provided by operating activities164,637 172,155 200,001 
Cash flows from investing activities:
Additions to oil and natural gas properties(119,306)(102,330)(337,979)
Proceeds from sale of oil and natural gas properties600 15 46,932 
Other, net2,562 4,484 351 
Net cash used in investing activities(116,144)(97,831)(290,696)
Cash flows from financing activities:
Principal payments on Pre-Petition Revolving Credit Facility— (318,961)(372,000)
Borrowings on Pre-Petition Revolving Credit Facility— 26,050 531,857 
Borrowings on Exit Credit Facility306,855 302,751 — 
Principal payments on Exit Credit Facility(409,000)— — 
Principal payments on DIP credit facility— (157,500)— 
Debt issuance costs and loan commitment fees(1,225)(7,100)(633)
Repurchase of senior notes— — (22,827)
Proceeds from issuance of New Preferred Stock— 50,000 — 
Other, net(55)(8)(719)
Net cash (used in) provided by in financing activities(103,425)(104,768)135,678 
Net (decrease) increase in cash, cash equivalents and restricted cash(54,932)(30,444)44,983 
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$4,485 $59,417 $51,043 
 See accompanying notes to consolidated financial statements.
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GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(DEBTOR-IN-POSSESSION)
(Unaudited)

1.BASIS OF PRESENTATION 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 as of and for the three months ended September 30, 2021 ("Current Successor Quarter"), May 18, 2021 through September 30, 2021 (“Current Successor YTD Period”), January 1, 2021 through May 17, 2021 (“Current Predecessor YTD Period”), the three months ended September 30, 2020 (“Prior Predecessor Quarter”) and the nine months ended September 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 the application of 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 reportCompany will continue as a going concern.
Certain reclassifications have been made to prior period financial statements and related disclosures to conform to current period presentation. These reclassifications have no impact on Form 10-K. Results for the three months ended March 31, 2021 are not necessarily indicative of the results expected for the full year.previous reported total assets, total liabilities, net loss, total stockholders' deficit or total operating cash flows.
Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code
On November 13, 2020, 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 LLCthe Petition Date, the Debtors filed voluntary petitions of relief under Chapter 11 of Title 11 of the United StatesBankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas. The Chapter 11 Cases are beingwere administered jointly under the caption In re Gulfport Energy Corporation, et al., Case No. 20-35562 (DRJ).
The debtors continueBankruptcy Court confirmed the Plan and entered 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 their businessesits business in the ordinary course as "debtors-in-possession" under the jurisdiction of the Bankruptcy Court,debtors-in-possession in accordance with the applicable provisions of the Bankruptcy CodeCode. The Bankruptcy Court granted the first day relief requested by the Company that was designed primarily to mitigate the impact of the Chapter 11 Cases on its operations, vendors, suppliers, customers and employees. As a result, the ordersCompany was 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 the ordinary course for goods and services provided prior to the Petition Date. During the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of business required the prior approval of the Bankruptcy Court.
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The commencement of a voluntary proceeding in bankruptcy constituted an event of default that accelerated the Company's obligations under the Company's Pre-Petition Revolving Credit Facility and the indentures governing the Company's senior notes, resulting in the principal and interest due thereunder becoming immediately due and payable.
Subject to certain specific exceptions under the Bankruptcy Code, the filing of the Chapter 11 Cases automatically stayed all judicial or administrative actions against the Company and efforts by creditors to collect on or otherwise exercise rights or remedies with respect to pre-petition claims. Absent an order from the Bankruptcy Court, substantially all of the Debtors’ pre-petition liabilities arewere subject to settlementcompromise and discharge under the Bankruptcy Code. The automatic stay was lifted on the Emergence Date.
The Company has applied FASB ASC Topic 852 - Reorganizations ("ASC 852") in preparing the consolidated financial statements whichfor the period ended May 17, 2021. ASC 852 specifies the accounting and financial reporting requirements for entities reorganizing through Chapter 11 bankruptcy proceedings. These requirements include distinguishing transactions associated with the reorganization separate from activities related to the ongoing operations of the business. Accordingly, pre-petition liabilities that may be impacted by the Chapter 11 proceedings have beenwere classified as liabilities subject to compromise on the consolidated balance sheetssheet as of March 31, 2021 and December 31, 2020. Additionally, certain expenses, realized gains and losses and provisions for losses that are realized or incurred during the Chapter 11 Cases are recorded as reorganization items, net in the consolidated statements of operations for the three months ended March 31, 2021.net. Refer to Note 23 for more information on the eventsregarding reorganization items.
Accounts Payable and Accrued Liabilities
Accounts payable and accrued liabilities consisted of the bankruptcy proceedings as well asfollowing at September 30, 2021 and December 31, 2020:
SuccessorPredecessor
September 30, 2021December 31, 2020
Accounts payable and other accrued liabilities$159,080 $120,275 
Revenue payable and suspense155,454 124,628 
Accrued contract rejection damages and shares held in reserve121,638 — 
Total accounts payable and accrued liabilities$436,172 $244,903 
Recently Adopted Accounting Standards
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 reporting impactsmeasurement of convertible instruments. It eliminates the treasury stock method for convertible instruments and requires application of the reorganization.
Ability“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 Continue as a Going Concerninterest expense of those embedded features.
The accompanying unauditedCompany elected to early adopt this standard effective on the Emergence Date. The Company adopted 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 preparedpresented under the new standard, while the predecessor periods and comparative periods are not adjusted and continue to be reported in accordance with generally accepted accounting principles applicable to a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business.
As discussed above, the filing of the Chapter 11 Cases constituted an event of default under the Company’s Pre-Petition Revolving Credit Facility and the indentures governing the Company's senior notes (the "Default"), resulting in the principalhistorical accounting policy.
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Supplemental Cash Flow and interest due thereunder becoming immediately due and payable. The Company does not have sufficient cash on hand or available liquidity to repay these amounts due. These conditions and events raise substantial doubt about the Company’s ability to continue as a going concern.Non-Cash Information
SuccessorPredecessor
Period from May 18, 2021 through September 30, 2021Period from January 1, 2021 through May 17, 2021Nine Months Ended September 30, 2020
Supplemental disclosure of cash flow information:
Cash paid for reorganization items, net$42,202 $87,199 $— 
Interest payments6,465 7,272 73,979 
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable - oil and natural gas sales(5,230)(60,832)28,767 
(Increase) decrease in accounts receivable - joint interest and other5,536 (3,005)32,827 
Increase (decrease) in accounts payable and accrued liabilities(48,903)79,193 (40,552)
(Increase) decrease in prepaid expenses7,231 135,471 (45,620)
(Increase) decrease in other assets106 3,067 (2,721)
Total changes in operating assets and liabilities$(41,260)$153,894 $(27,299)
Supplemental disclosure of non-cash transactions:
Capitalized stock-based compensation$484 $930 $2,189 
Asset retirement obligation capitalized55 546 2,343 
Asset retirement obligation removed due to divestiture— — (2,033)
Interest capitalized117 — 907 
Fair value of contingent consideration asset on date of divestiture— — 23,090 
Release of New Common Stock Held in Reserve23,893 — — 
Foreign currency translation gain (loss) on equity method investments— 2,570 (4,497)

2.CHAPTER 11 EMERGENCE
As part ofdescribed in Note 1, on November 13, 2020, the Debtors filed the Chapter 11 Cases the Company submittedand the Plan, which was subsequently amended, and entered the confirmation 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 Bankruptcy Court. The Company’s operations and its ability to develop and execute its business plan are subject to a high degreePlan.
Plan of risk and uncertainty associatedReorganization
In accordance with the Chapter 11 Cases. As discussed in Note 14, an order was enteredPlan confirmed by the Bankruptcy Court, confirmingthe following significant transactions occurred upon the Company's Plan on April 28, 2021 and it expects to emergeemergence from bankruptcy inon May 2021. However, there can be no assurance that17, 2021:
•Shares of the Predecessor's common stock outstanding immediately prior to the Emergence Date were cancelled, and on the Emergence Date, the Company will consummateissued 19,845,780 shares of New Common Stock and 55,000 shares of New Preferred Stock, which were the confirmed Plan,result of the transactions described below. The Company also entered into a registration rights agreement and as a result,amended its articles of incorporation and bylaws for the Company has concluded that management’s plans do not alleviate substantial doubt aboutauthorization of the Company’s ability to continue as a going concern.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;
While operating as•The Predecessor effectuated certain restructuring transactions, including entering into a debtor-in-possession, the Company may settle liabilities, subjectplan of Merger with Gulfport Merger Sub, Inc., a newly formed, wholly owned subsidiary of Gulfport ("Merger Sub"), pursuant to the approval of the Bankruptcy Court or as otherwise permittedwhich Merger Sub was merged with and into Predecessor, resulting in the ordinary coursePredecessor becoming a wholly owned subsidiary of business, for amounts other than those reflected in the accompanying consolidated financial statements. Further, the Plan or other bankruptcy proceedings could materially change the amountsGulfport;
•The Debtors entered into a Second Amended and classifications of assets and liabilities reported in the consolidated financial statements, including liabilities subject to compromise which will be resolved in connectionRestated Credit Agreement (the "Exit Credit Agreement") with the Chapter 11 Cases. The accompanying unaudited consolidated financial statements do not include any adjustments relatedBank of Nova Scotia as administrative agent, various lender parties and acknowledged and agreed to the recoverabilityby 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") and classification of assets or the amounts and classification of liabilities or any other adjustments that might be necessary should the Company be unable to continue as a going concern or as a consequence of the Chapter 11 Cases.

Impact on Previously Reported Results
During the third quarter of 2020, the Company identified that certain firm transportation costs incurred in prior periods were misclassified as deducts to "natural gas sales" while they should have been included in "transportation, gathering, processing and compression" on its consolidated statements of operations. The Company assessed the materiality of this presentation on prior periods’ consolidated financial statements in accordancetogether with the SEC Staff Accounting Bulletin No. 99, “Materiality”Exit Facility (the "Exit Credit Facility"), codified in ASC Topic 250, “Accounting Changescollectively with an initial borrowing base and Error Corrections”. Based on this assessment, the Company concluded that the correction is not material to any previously issued financial statements. The correction had no impact on its consolidated balance sheets, consolidated statements of comprehensive income, consolidated statements of stockholders' equity or consolidated statements of cash flows. Additionally, the error had no impact on net loss or net loss per share. The Company will conform presentation of previously reported consolidated statements of operations in future filings. The following tables present the effect of the correction on all affected line items of our previously issued consolidated financial statements of operations for the three months ended March 31, 2020.
Three months ended March 31, 2020
As ReportedAdjustmentsAs Revised
(In thousands)
Natural gas sales$108,547 $52,461 $161,008 
Total Revenues$246,877 $52,461 $299,338 
Transportation, gathering, processing and compression$57,896 $52,461 $110,357 
Total Operating Expenses$726,964 $52,461 $779,425 
elected commitment
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Supplemental Cash Flowamount of up to $580 million (less the amount of any term loan deemed funded by any RBL Lender that is 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 Non-Cash Information
Three months ended March 31,
20212020
Supplemental disclosure of cash flow information:(In thousands)
Cash paid for reorganization items, net$21,367 $0 
Interest payments$4,763 $14,034 
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable - oil and natural gas sales$(14,117)$47,111 
(Increase) decrease in accounts receivable - joint interest and other(478)6,001 
Increase (decrease) in accounts payable and accrued liabilities15,555 (7,637)
(Increase) decrease in prepaid expenses26,356 (6,920)
(Increase) decrease in other assets(655)1 
Total changes in operating assets and liabilities$26,661 $38,556 
Supplemental disclosure of non-cash transactions:
Capitalized stock-based compensation$630 $934 
Asset retirement obligation capitalized$483 $381 
Asset retirement obligation removed due to divestiture$0 $(2,033)
Interest capitalized$0 $187 
Fair value of contingent consideration asset on date of divestiture$— $23,090 
Foreign currency translation gain (loss) on equity method investments$2,570 $(15,030)
2.CHAPTER 11 PROCEEDINGS
Restructuring Support Agreement
On November 13, 2020,among the Debtors commencedIssuer, UMB Bank, National Association, as trustee, and the Chapter 11 Cases as described in Note 1 above. To ensure ordinary course operations,guarantors party thereto (such indenture, the Debtors have obtained approval from“1145 Indenture,” and such senior notes issued thereunder, the “1145 Notes”), under section 1145 of the Bankruptcy Court for certain first-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 second-day motions, including motions to obtain customary relief intended to continue ordinary course operations afteramong the Petition Date. In addition,Issuer, UMB Bank, National Association, as trustee, and the Debtors have received authority to use cash collateralguarantors 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 lendersSecurities 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.
On November 13, 2020, the Debtors entered into a restructuring support agreement with (i) over 95%Facility terminated. Each holder of the lenders (the “Consenting RBL Lenders”) party to the Pre-Petition Revolving Credit Facility, dated asan Allowed DIP Claim received, in full and final satisfaction, settlement, release, and discharge of, December 27, 2013, by and among the Company, as borrower,in exchange for, each Allowed DIP Claim its Pro Rata share of the lenders party thereto, the Bank of Nova Scotia, as administrative agent and issuing bank, the joint lead arrangers and joint bookrunners, the co-syndication agents, and the co-documentation agents and (ii) certain holders (the “Consenting Noteholders,” and, together with the Consenting RBL Lenders, the “Consenting Stakeholders”) holding over two-thirds of the Company’s (a) 6.625% senior notes due 2023, issued under that certain Indenture, dated as of April 21, 2015, (b) 6.000% senior notes due 2024, issued under that certain Indenture, dated as of October 14, 2016, (c) 6.375% senior notes due 2025, issued under that certain Indenture, dated as of December 21, 2016, and (d) 6.375% senior notes due 2026, issued under that certain Indenture, dated as of October 11, 2017 (collectively, the “Unsecured Notes”), each by and among the Company, the subsidiary guarantors party thereto, and UMB Bank, N.A. as successor trustee.
The RSA outlines the key elements and actions the Company plans to take as part of Chapter 11 process, including equitizing a significant portion of its prepetition indebtedness and rejecting or renegotiating certain contracts which will result in a materially improved balance sheet and cost structure. The RSA contains certain covenants on the part of each of Gulfport and the Consenting Stakeholders, including commitments by the Consenting Stakeholders to vote in favor of the Plan and commitments of Gulfport and the Consenting Stakeholders to negotiate in good faith to finalize the documents and agreements governing the Restructuring. The RSA also places certain conditions on the obligations of the parties and provides that the RSA may be terminated upon the occurrence of certain events, including, without limitation, the failure to achieve certain milestones and certain breaches by the parties under the RSA. One such condition is the requirement of the Company to obtain certain levels of savings on certain midstream obligations (as set forthparticipation in the RSA) through rejection of such contracts and/or renegotiation of their terms.

Plan of Reorganization
On April 28, 2021, the Bankruptcy Court entered an order confirming the Amended Joint Chapter 11 Plan of Reorganization of Gulfport Energy Corporation and Its Debtor Subsidiaries (the "Plan"). The Company expects the effective
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date of the Plan will occur once all conditions precedent to the Plan have been satisfied (the "Effective Date"). Below is a summary of the material terms of the Plan as approved and confirmed by the Bankruptcy Court. This summary highlights only certain substantive provisions of the Plan and is not intended to be a complete description of the Plan. Capitalized terms used under this heading but not otherwise defined herein shall have the meaning given to such terms in the Plan, which has been included as an exhibit to this Form 10-Q:

Exit Credit Facility;
•the RBL LendersEach 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 DIP Lenders, each with The Bank of Nova Scotia as administrative agent, have agreed that the RBL Credit Facility and DIP Facility, respectively, will convert into the $580 million Exit Facility upon the Effective Date, subject to the terms and conditions set forth in the Exit Facility Documentation;New Unsecured Senior Notes.
•certain members1,678,755 shares of New Common Stock were issued to the Ad Hoc Noteholder Group have agreed to backstop the Rights Offering of at least $50 million in exchange for New Preferred Stock;Disputed Claims reserve;
•HoldersEach holder of Allowed Generala Class 4A Claim greater than the Convenience Claim Threshold received its pro rata share of 119,679 shares of New Common Stock (which were issued to the Unsecured Claims against Gulfport Parent will receive their Pro Rata share of: (a)Distribution Trust), $10 million in Cash,cash, subject to adjustment by the Unsecured Claims Distribution Trustee; (b)Trustee, and 100% of the Mammoth Shares; and (c) 4%
•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 the Reorganized Debtors, subject to dilution and certain adjustments;
•Holders of Allowed Notes Claims against Gulfport Parent will waive their entitlement to a Cash recovery or any of the Mammoth Shares, and will cap their recovery at 96% of the New CommonPreferred Stock, of the Reorganized Debtors, which will be drawn first from the Gulfport Subsidiaries Equity Pool and then from the Gulfport Parent Equity Pool to the extent required due to dilution as a result of distributions made to General Unsecured Claims against Gulfport Subsidiaries (excluding distributions to Unsecured Surety Claims);
•Holders of Allowed Notes Claims against Gulfport Subsidiaries and Allowed General Unsecured Claims against Gulfport Subsidiaries will receive their Pro Rata share of: (a) the Gulfport Subsidiaries Equity Pool; (b) the New Unsecured Notes; and (c) the Rights Offering Subscription Rights;Rights and the Successor Senior Notes.
•Each holder of a Convenience Class of Convenience Claims consisting of (a) Allowed General Unsecured Claims of $300,000 or less or (b) Allowed General Unsecured Claims over $300,000 that the applicable Holder has irrevocably elected to have reduced to $300,000 and treated as Convenience Claims,Claim will share in a $3,000,000 Cash$3 million cash distribution pool, which the Unsecured Claims Distribution Trustee may increase by an additional $2,000,000$2 million by reducing the Gulfport Parent Cash Pool;
•an Unsecured Claims Distribution Trustee will administer a trust to make distributions to Allowed General Unsecured ClaimsEach intercompany claim was cancelled on the Emergence Date and Allowed Convenience Claims and to exercise certain consent rights with respect to the settlement and Allowanceholders of disputed General Unsecured Claims and Convenience Claims;intercompany interests received no recovery or distribution;
•each Intercompany Claim shall be cancelledThe 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 exchange forproceeds. Additionally, 5,000 shares were issued to the distributions contemplated byBack Stop Commitment counterparties in lieu of cash consideration as per the Plan to Holders of Claims against and Interests in the respective Debtor entities and shall be considered settled pursuant to Bankruptcy Rule 9019;Backstop Commitment Agreement.
•each Holder of an Intercompany Interest shall receive no recovery or distributionThe Company adopted the Gulfport Energy Corporation 2021 Stock Incentive Plan (the "Incentive Plan") effective on the Emergence Date and shall be Reinstated solely to the extent necessary to maintain the Debtors’ prepetition corporate structure for the ultimate benefit of the Holdersreserved 2,828,123 shares of New Common Stock for issuance to Gulfport's employees and New Preferred Stock; andnon-employee directors pursuant to equity incentive awards to be granted under the Incentive Plan.
•the Existing Interests in Gulfport Parent will be cancelled, released, and extinguished, and will be of no further force or effect, without any distribution.

DIP Credit Facility

PursuantAdditionally, pursuant to the RSA, the Consenting RBL Lenders have 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 proceeds of the DIP Credit Facility may be 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. The DIP Credit Facility was approvedPlan confirmed by the Bankruptcy Court, on a final basis on December 18, 2020. See Note 5 for additional information.

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Tablethe Company's post-emergence Board of Contents

Directors is comprised of five directors, including the Company's 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 Company mayDebtors 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 or unexpired lease iswas treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relievesrelieved the CompanyDebtors from performing its future obligations under such executory contract or unexpired lease but entitlesentitled the contract counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. Counterparties to rejected contracts or leases may assert unsecured claims in the Bankruptcy Court against the Company's estate for such damages. Generally,Alternatively, the assumption of an
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executory contract or unexpired lease requiresrequired the CompanyDebtors 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 Company,Debtors in this document, including where applicable a quantification of the Company'sCompany’s obligations under any such executory contract or unexpired lease of the Company,Debtors, is qualified by any overriding rejection rights itthe 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
Potential Claims

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 has filedqualified 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 Bankruptcy Court schedules 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 setting forth, among other things,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 liabilities differ materially from their recorded values as reflected on the historical balance sheet of the CompanyPredecessor.
Reorganization Value
Reorganization value is derived from an estimate of enterprise value, or fair value of the Company's interest-bearing debt and eachstockholders' equity. Under ASC 852, reorganization value generally approximates fair value of its subsidiaries, subjectthe entity before considering liabilities and is intended to approximate the assumptions filedamount a willing buyer would pay for the assets immediately after the effects of a restructuring. As set forth in connection therewith. These schedulesthe disclosure statement, amended for updated pricing, and statements may be subject to further amendment or modification after filing. Certain holders of pre-petition claims that are not governmental units were required to file proofs of claim by the deadline for general claims, which was setapproved by the Bankruptcy Court, as January 26, 2021. Governmental unitsthe enterprise value of the Successor was estimated to be between $1.3 billion and $1.9 billion. With the 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. 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 required to file proof of claims by May 12, 2021,described below in greater detail within the deadline that was set by the Bankruptcy Court.

valuation process.
As of April 30, 2021,The enterprise value and corresponding implied equity value are dependent upon achieving the Debtors have received approximately 2,700 proofs of claim for an aggregate amount of approximately $13 billion. The Company will continue to evaluate these claims throughout the Chapter 11 process and recognize or adjust amounts in future financial statements as necessaryresults set forth in our valuation using the bestan asset-based methodology of estimated proved reserves, undeveloped properties, and other financial information, available at such time. Differences between amounts scheduled by the Companyconsiderations and claims by creditors will ultimately be reconciled and resolved in connection with the claims resolution process. In lightprojections, applying a combination of the expected number of creditors, the claims resolution process may take considerable time to completeincome, cost and likely will continue after the Company emerges from bankruptcy.

Financial Statement Classification of Liabilities Subject to Compromise
The accompanying consolidated balance sheetsmarket approaches as of March 31, 2021the fresh start reporting date of May 17, 2021. As estimates, assumptions, valuations and December 31, 2020 include amounts classified as liabilitiesfinancial projections, including the fair value adjustments, the financial projections, the enterprise value and equity value projections, are inherently subject to compromise, which represent liabilitiessignificant uncertainties, the Company anticipatesresolution of contingencies is beyond our control. Accordingly, there is no assurance that the estimates, assumptions, valuations or financial projections will be allowed as claims in the Chapter 11 Cases. These amounts represent the Company's current estimate of known or potential obligations to be resolved in connection with the Chapter 11 Cases,realized, and may differ from actual future settlement amounts paid. Differences between liabilities estimated and claims filed, or to be filed, will be investigated and resolved in connection with the claims resolution process. The Company will continue to evaluate these liabilities throughout the Chapter 11 process and adjust amounts as necessary. Such adjustments may be material.

Liabilities subject to compromise includes amounts related to the rejection of various executory contracts. Additional amounts may be included in liabilities subject to compromise in future periods if additional executory contracts and/or unexpired leases are rejected. The nature of many of the potential claims arising under the Company's executory contracts and unexpired leases has not been determined at this time, and therefore, such claims are not reasonably estimable at this time and may be material. Damages related to rejected contracts are accounted for after they have been approved for rejection by the Bankruptcy Court.

The following table summarizes the components of liabilities subject to compromise included on the Company's consolidated balance sheets as of March 31, 2021 and December 31, 2020:

results could vary materially.
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March 31, 2021December 31, 2020
(in thousands)
Debt subject to compromise$2,003,004 $2,005,219 
Accounts payable and accrued liabilities134,344 164,939 
Asset retirement obligations64,854 63,566 
Accrued interest on debt subject to compromise55,159 55,634 
Other liabilities4,092 4,122 
Liabilities subject to compromise$2,261,453 $2,293,480 
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.
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.

Interest Expense
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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.
Consolidated Balance Sheet
The Company has discontinued recording interestfollowing 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 $(145,019)(a)$— $1,526 
Restricted cash—57,891(b)—57,891
Accounts receivable—oil and natural gas sales180,711——180,711
Accounts receivable—joint interest and other15,431——15,431
Prepaid expenses and other current assets86,189(60,894)(c)—25,295
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 properties9,558,121—(7,860,713)(s)1,697,408
Unproved properties1,375,681—(1,145,507)(s)230,174
Other property and equipment38,026—(31,133)(t)6,893
Total property and equipment10,971,828—(9,037,353)1,934,475
Accumulated depletion, depreciation and amortization(8,870,723)—8,870,723(u)—
Total property and equipment, net2,101,105—(166,630)1,934,475
Other assets:
Equity investments27,044—(27,044)(v)—
Long-term derivative instruments7,468—715(w)8,183
Operating lease assets47——47
Other assets18,8667,100(d)—25,966
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 $122,599 (e)$— $506,799 
Short-term derivative instruments96,116 — 2,784 (x)98,900 
Current portion of operating lease liabilities— 38 (f)— 38 
Current maturities of long-term debt280,251 (220,251)(g)— 60,000 
Total current liabilities760,567 (97,614)2,784 665,737 
Non-current liabilities:
Long-term derivative instruments69,331 — 11,411 (y)80,742 
Asset retirement obligation— 65,341 (h)(46,257)(z)19,084 
Non-current operating lease liabilities— 9 (i)— 9 
Long-term debt, net of current maturities— 792,751 (j)— 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)$1,558,323 
Commitments and contingencies (Note 9)
0000
Mezzanine Equity:
New Preferred Stock$— $55,000 (l)$— $55,000 
Stockholders’ equity (deficit):
Predecessor common stock1,609 (1,609)(m)— — 
New Common Stock— 2 (n)— 2 
Additional paid-in capital4,215,838 (3,522,064)(o)— 693,774 
New Common Stock held in reserve— (54,109)(p)— (54,109)
Accumulated other comprehensive loss(40,430)40,430 (q)— — 
Retained earnings (accumulated deficit)(4,644,634)4,805,390 (q)(160,756)(aa)— 
Total stockholders’ equity (deficit)$(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$63,068 
New Preferred Stock rights offering proceeds50,000 
Funds required to rollover the DIP Credit Facility and Pre-Petition Revolving Credit Facility into the Exit Facility(175,000)
Payment of accrued Pre-Petition Revolving Credit Facility and DIP Credit Facility interest(1,022)
Payment of issuance costs related to the Exit Credit Facility(10,250)
Funding of the Professional Fee Escrow(43,891)
Payment of professional fees at Emergence Date(7,964)
Transfer to restricted cash for the Unsecured Claims Distribution Trust(1,000)
Transfer to restricted cash for the Convenience Claims Cash Pool(3,000)
Transfer to restricted cash for the Parent Cash Pool(10,000)
Payment of severance costs at Emergence Date(5,960)
Net change in cash and cash equivalents$(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 instruments classified asissuance 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 Facility$122,751 
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 of the Petition Date. 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 contractual interest expenseresulting gain on liabilities subject to compromise not accruedwas 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 consolidated statementsRights Offering.
(m)Changes in Predecessor common stock reflect the extinguishment of operations was approximately $28.5 million forPredecessor equity as per the three months ended March 31, 2021.Plan.
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(n)Changes in New Common Stock included the following:
Issuance of common stock to settle General Unsecured Claims against Gulfport Parent (par value)$— 
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)— 
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 First-Out Term Loan(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.
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(v)The change in equity investments is due to the fair value adjustment to the Company's Grizzly investment.
(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 obligations 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 and will continue to incur significant expenses, gains and losses associated with the reorganization, primarily the write-offgain on settlement of unamortized debt issuance costs, debt and equity financing fees, adjustmentsliabilities 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 restructuring process.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 are beingwere incurred in reorganization items, net within the Company's accompanying auditedunaudited condensed consolidated statements of operations, are expected tohave significantly affectaffected the Company's statements of operations. The Company has incurred adjustments for allowable claims related to its legal proceedings and executory contracts approved for rejections by the Bankruptcy Court, with additional adjustments possible in future periods.

The following table summarizes the components in reorganization items, net included in the Company's unaudited consolidated statements of operations for the three months ended March 31, 2021:

operations:
Three months ended March 31, 2021SuccessorPredecessor
(in thousands)Period from May 18, 2021 through September 30, 2021Period from January 1, 2021 through May 17, 2021
Legal and professional advisory fees$40,783 — $(81,565)
AdjustmentNet gain on liabilities subject to allowed claimscompromise2,088— 575,182 
Fresh start adjustments, net— 
Gain on settlement of pre-petition accounts payable(4,150)(160,756)
ReorganizationElimination of predecessor accumulated other comprehensive income— (40,430)
Debt issuance costs— (3,150)
Other items, net— (22,383)
Total reorganization items, net$38,721— $266,898 
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3.
4.PROPERTY AND EQUIPMENT
The major categories of property and equipment and related accumulated DD&A and impairment as of March 31,September 30, 2021 and December 31, 2020 are as follows:
March 31, 2021December 31, 2020SuccessorPredecessor
(In thousands)September 30, 2021December 31, 2020
Oil and natural gas properties$10,895,625 $10,816,909 
Proved oil and natural gas propertiesProved oil and natural gas properties$1,831,762 $9,359,866 
Unproved propertiesUnproved properties216,357 1,457,043 
Other depreciable property and equipmentOther depreciable property and equipment85,827 85,530 Other depreciable property and equipment4,891 85,530 
LandLand3,008 3,008 Land386 3,008 
Total property and equipmentTotal property and equipment10,984,460 10,905,447 Total property and equipment2,053,396 10,905,447 
Accumulated DD&A and impairmentAccumulated DD&A and impairment(8,874,899)(8,819,178)Accumulated DD&A and impairment(212,403)(8,819,178)
Property and equipment, netProperty and equipment, net$2,109,561 $2,086,269 Property and equipment, net$1,840,993 $2,086,269 

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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 March 31,September 30, 2021, the net book value of the Company's oil and gas properties was below the calculated ceiling for the period leading up to March 31,September 30, 2021. As a result, the Company recorded 0 impairment of its oil and natural gas properties for the three months ended March 31, 2021. The Company recordeddid not record an impairment of its oil and natural gas properties during the third quarter of $553.32021. The Company recorded impairment charges of $117.8 million for the three months ended March 31, 2020.Current Combined YTD Period. The Company recorded impairments of its oil and natural gas properties of $270.9 million and $1.4 billion for the Prior Predecessor Quarter and the Prior Predecessor YTD Period, respectively, as a result of the significant decrease in commodity prices.
Certain 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. All general and administrative costs not capitalized are charged to expense as they are incurred. Capitalized general and administrative costs were approximately $5.5 million and $5.4$5.1 million for the three months ended March 31, 2021Current Successor Quarter, $7.3 million for the Current Successor YTD Period, and 2020,$8.0 million for the Current Predecessor YTD Period. Capitalized general and administrative costs were approximately $6.2 million and $19.8 million for the Prior Predecessor Quarter and the Prior Predecessor YTD Period, respectively.
The following table summarizes the Company’s unevaluated properties excluded from amortization by area at March 31, 2021:
March 31, 2021
(In thousands)
Utica$761,397 
SCOOP651,451 
Other926 
$1,413,774 
At December 31, 2020, approximately $1.5 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.
The following table summarizes the Company’s unevaluated properties excluded from amortization by area at September 30, 2021:
Successor
September 30, 2021
(In thousands)
Utica$179,449 
SCOOP36,905 
Other3 
Total unproved properties$216,357 
Impairment of Other Property and Equipment
During the three months ended March 31, 2021,Current Predecessor YTD Period, the Company recorded an impairment of $14.6 million related to its corporate headquarters as a result of changes in the expected future use.
Asset Retirement Obligation
A reconciliation of the Company’s asset retirement obligation for the three months ended March 31, 2021 and 2020 is as follows:
March 31, 2021March 31, 2020
(In thousands)
Asset retirement obligation, beginning of period$63,566 $60,355 
Liabilities incurred483 381 
Liabilities removed due to divestitures0 (2,033)
Accretion expense805 741 
Total asset retirement obligation as of end of period$64,854 $59,444 
Less: amounts reclassified to liabilities subject to compromise$(64,854)$0 
Total asset retirement obligation reflected as non-current liabilities$0 $59,444 
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4.EQUITY INVESTMENTS
Investments accounted for by the equity method consist of the following as of March 31, 2021 and December 31, 2020:
Carrying valueLoss from equity method investments
Approximate ownership %March 31, 2021December 31, 2020Three months ended March 31,
20212020
(In thousands)
Investment in Grizzly Oil Sands ULC24.5 %$27,044 $24,816 $(342)$(143)
Investment in Mammoth Energy Services, Inc.21.5 %0 0 0 (10,646)
$27,044 $24,816 $(342)$(10,789)

The tables below summarize financial information for the Company’s equity investments as of March 31, 2021 and December 31, 2020.
Summarized balance sheet information:
March 31, 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 March 31,
 20212020
(In thousands)
Gross revenue$66,805 $97,383 
Net loss$(13,606)$(85,031)
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 March 31, 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 March 31, 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 $2.6 million as a result of a foreign currency translation gain and decreased by $14.7 million as a result of a foreign currency translation loss for the three months ended March 31, 2021 and 2020, respectively.
Mammoth Energy Services, Inc.
At March 31, 2021, 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 March 31, 2021 was $52.3 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 0 at March 31, 2020. During the first quarter of 2021, the Company's
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share of net loss of Mammoth continued to be in excessAsset Retirement Obligation
The following table provides a reconciliation of the carrying valueCompany’s asset retirement obligation for the periods 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 
Liabilities incurred19 
Accretion expense488 
Asset retirement obligation at September 30, 2021$19,854 
(1) See Note 3 for additional discussion of its investment and, therefore, the Company's investment value remained at 0 at March 31, 2021.
The Company received 0 distributions from Mammoth Energy during the three months ended March 31, 2021 and 2020, respectively. The loss from equity method investments presented in the table above reflects any intercompany profit eliminations.fresh start adjustments.
5.LONG-TERM DEBT
Long-term debt consisted of the following items as of March 31,September 30, 2021 and December 31, 2020:
March 31, 2021December 31, 2020SuccessorPredecessor
(In thousands)September 30, 2021December 31, 2020
DIP credit facility$157,500 $157,500 
Pre-petition revolving credit facility316,759 292,910 
Exit FacilityExit Facility$35,606 $— 
First-Out Term LoanFirst-Out Term Loan165,000 — 
8.000% senior unsecured notes due 20268.000% senior unsecured notes due 2026550,000 — 
DIP Credit FacilityDIP Credit Facility— 157,500 
Pre-Petition Revolving Credit FacilityPre-Petition Revolving Credit Facility— 292,910 
6.625% senior unsecured notes due 20236.625% senior unsecured notes due 2023324,583 324,583 6.625% senior unsecured notes due 2023— 324,583 
6.000% senior unsecured notes due 20246.000% senior unsecured notes due 2024579,568 579,568 6.000% senior unsecured notes due 2024— 579,568 
6.375% senior unsecured notes due 20256.375% senior unsecured notes due 2025507,870 507,870 6.375% senior unsecured notes due 2025— 507,870 
6.375% senior unsecured notes due 20266.375% senior unsecured notes due 2026374,617 374,617 6.375% senior unsecured notes due 2026— 374,617 
Building loan21,914 21,914 
Building LoanBuilding Loan— 21,914 
Debt issuance costsDebt issuance costs(1,104)— 
Total DebtTotal Debt2,282,811 2,258,962 Total Debt$749,502 $2,258,962 
Less: current maturities of long-term debtLess: current maturities of long-term debt(279,807)(253,743)Less: current maturities of long-term debt(60,000)(253,743)
Less: amounts reclassified to liabilities subject to compromiseLess: amounts reclassified to liabilities subject to compromise(2,003,004)(2,005,219)Less: amounts reclassified to liabilities subject to compromise— (2,005,219)
Total Debt reflected as long termTotal Debt reflected as long term$0 $0 Total Debt reflected as long term$689,502 $— 
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Successor Debt
Our post-emergence debt consisted of the Exit Credit Facility and the Successor Senior Notes. Subsequent to the end of the third quarter of 2021, the Company amended and refinanced the Exit Credit Facility with the New Credit Facility.
New Credit Facility
On October 14, 2021, the Company entered into the New Credit Facility for an aggregate maximum principal amount of up to $1.5 billion, an initial borrowing base of $850.0 million and an initial aggregate elected commitment amount of $700.0 million. See Note 17 for additional discussion of the New Credit Facility.
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 provided 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 had an initial borrowing base and elected commitment amount of up to $580.0 million.
Loans drawn under the Exit Facility were not subject to amortization, while loans drawn under the First-Out Term Loan amortized with $15.0 million quarterly installments, commencing on the closing date and occurring every three months after the closing date. The Exit Credit Facility was schedule to mature on May 17, 2024.
The Exit Facility provided for a $150.0 million sublimit of the aggregate commitments that is available for the issuance of letters of credit. The Exit Facility also included a $40 million availability blocker that was to remain in place until Successful Midstream Resolution (as defined in the Exit Credit Agreement), as discussed in Note 9.

As of September 30, 2021, the Exit Facility and the First-Out Term Loan bore interest at weighted average rates of 4.50% and 5.50%, respectively.

As of September 30, 2021, the Company had $35.6 million outstanding borrowings under the Exit Facility, $165 million outstanding borrowings under the First-Out Term Loan and $115.5 million in letters of credit outstanding. At September 30, 2021, the Company was in compliance with all covenants under its Exit Credit Facility.
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 notes are guaranteed on a senior unsecured basis by each of the Company's subsidiaries that guarantee the Exit Credit Facility and the New Credit Facility as discussed in Note 17.
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.
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.
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.
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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 staysstayed 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 sheetssheet as of March 31, 2021 and December 31, 2020.
Debtor-in-Possession Credit Agreement
Pursuant to the RSA, the Consenting RBL Lenders have 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 may bewere 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. TheOn the Emergence Date, the DIP Credit Facility was approved by the Bankruptcy Court on a final basis on December 18, 2020. As of March 31, 2021, $157.5 million was outstanding under the DIP Credit Facilityterminated and the total availability for future borrowings under this facility, after giving effect to an aggregate of $28.5 million letters of credit, was $76.5 million.
Borrowings underlenders indefeasibly converted into the DIP Credit Facility will mature, and the lending commitments thereunder will terminate, upon the earliest to occur of: (a) August 30, 2021; (b) three (3) business days after the Petition Date, if the Interim Order and Hedging Order have not been entered prior to the expiration of such period; (c) thirty five (35) days (or a later date consented to by the Administrative Agent and the Majority Lenders in their sole discretion) after the entry of the Interim Order, if the Bankruptcy Court has not entered the Final Order on or prior to such date; (d) the effective dateExit Facility. Each holder of an Approved Plan of Reorganization, (e)
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the consummation of a sale of all or substantially all of the equity and/or assets of the Debtors and budgeted and necessary expenses of the estates; (f) the date of the paymentallowed DIP Claim received, in full and final satisfaction, settlement, release, and discharge of, and in cash,exchange for, each Allowed DIP Claim its Pro Rata share of all Obligations (and the termination of all Commitments in accordance with the terms hereof); and (g) the date of termination of all Commitments and/or the acceleration of all of the Obligations under the Agreement and the other Loan Documents following the occurrence and during the continuance of an Event of Default.
Borrowings under the DIP Credit Facility bear interest at a eurodollar rate or base rate, at our election, plus an applicable margin of 4.50% per annum for eurodollar loans and 3.50% per annum for base rate loans. At March 31, 2021, amounts borrowed under the DIP credit facility bore interest at a weighted average rate of 5.50%. In addition to paying interest on outstanding principal and letters of credit posted under the DIP Credit Facility, we are required to pay a commitment fee of 0.50% per annum to the lenders of the DIP Credit Facility in respect of the unutilized DIP commitments thereunder and a letter of credit fee equal to 0.20% per annum.
The DIP Credit Facility includes negative covenants that, subject to significant exceptions, limit the Company's ability and the ability of its restricted subsidiaries to, among other things, (i) create liens on assets, property revenues, (ii) make investments, (iii) incur additional indebtedness, (iv) engage in mergers, consolidations, liquidations and dissolutions, (v) sell assets, (vi) pay dividends and distributions or repurchase capital stock, (vii) cease for any reason to be the operator of its properties, (viii) enter into letters of credit without prior written consent, (ix) enter into certain commodity hedging contracts except commodity hedging contracts with terms approved by the Bankruptcy Courtparticipation in the hedging order or certain interest rate contracts, (x) change lines of business, (xi) engage in certain transactions with affiliates and (xii) incur more than a certain amount in capital expenditures in any calendar month. The DIPExit Credit Facility includes certain customary representations and warranties, affirmative covenants and events of default, including but not limited to defaults on account of nonpayment, breaches of representations and warranties and covenants, certain bankruptcy-related events, certain events under ERISA, material judgments and a change in control. If an event of default occurs, the lenders under the DIP Credit Facility will be entitled to take various actions, including the acceleration of all amounts due under the DIP Credit Facility and all actions permitted to be taken under the loan documents or application of law. In addition, the DIP Credit Facility is subject to various other financial performance covenants, including compliance with certain financial metrics and adherence to a budget approved by the Company's DIP Credit Facility lenders.

Facility.
Pre-Petition Revolving Credit Facility
ThePrior to the Emergence Date, the Company hashad entered into a senior secured revolving credit facility agreement, as amended, with The Bank of Nova Scotia, as the lead arranger and administrative agent and certain lenders from time to time party thereto. On October 8, 2020, the Company'sThe Pre-Petition Revolving Credit Facility had a borrowing base under itsof $580 million. On the Emergence Date, the Pre-Petition Revolving Credit Facility was reduced from $700 million to $580 million, thereby significantly reducingterminated and the Company's available liquidity. On October 15, 2020,lenders indefeasibly converted into the Company elected to not pay interest on certain Senior Notes outstanding triggering a default under the credit agreement. There was $316.8 millionExit Credit Facility. Each holder of outstanding borrowingsan allowed claim under the Pre-Petition Revolving Credit Facility asreceived, in full and final satisfaction, settlement, release, and discharge of, March 31, 2021 that were not rolled up intoand in exchange for, each Allowed DIP Claim its Pro Rata share of participation in the DIPExit Credit Facility. This amount of indebtedness will remain
Predecessor Senior Notes
On the Emergence Date, all outstanding throughout the Chapter 11 Cases and will continue to accrue interest at the default interest rate on amounts drawn after the Petition Date. The Company made certain adequate protection payments of $2.2 million on its Pre-Petition Revolving Credit Facility during the three months ended March 31, 2021 which reduced the amount of outstanding borrowingsobligations under the Pre-Petition Revolving Credit Facility classified as liabilities subject to compromise asPredecessor Senior Notes were cancelled in accordance with the Plan and each holder of March 31, 2021 inan allowed unsecured notes claim received their pro-rata share of 19.7 million shares of New Common Stock and $550 million of the accompanying consolidated balance sheets.Successor Senior Notes.
During the first quarter of 2021, $26.1 million was drawn on letters of credit secured by the Company's Pre-Petition Revolving Credit Facility by certain of its firm transportation contract counterparties. As these were post-petition activities, these letters of credit drawn are included in current portion of long-term debt in the accompanying consolidated balance sheets. At March 31, 2021Predecessor Building Loan
In June 2015, the Company included $99.1 million in prepaid and other current assets in the accompanying consolidated balance sheets as an offsetentered into a loan for the drawn letters of credit. A portion of the drawn letters of credit were netted against accounts payable to the Company's firm transportation contract counterparties.
Additionally, as of March 31, 2021, the Company had an aggregate of $121.2 million of letters of credit outstanding and 0 availability for future borrowings under its Pre-Petition Revolving Credit Facility. This facility is secured by substantially allconstruction of the Company's assets. Allcorporate headquarters in Oklahoma City, which was substantially completed in December 2016. On the Emergence Date, ownership of the Company's wholly-owned subsidiaries, excluding Grizzly Holdingscorporate headquarters reverted to the Building Loan lender and Mule Sky, guarantee our obligations under our revolving credit facility.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.
At March 31, 2021, amounts borrowed underCapitalization of Interest
The Company capitalized approximately $0.1 million of interest expense for the revolving credit facility boreCurrent Successor YTD Period related to its unevaluated oil and natural gas properties. The Company did not capitalize interest at a weighted average rate of 3.12%.expense for the Current Predecessor YTD Period. The Company capitalized approximately $0.2 million and $0.9 million in interest expense during the Prior Predecessor Quarter and the Prior Predecessor YTD Period, respectively.
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Capitalization of Interest
The Company did 0t capitalize interest expense for the three months ended March 31, 2021 and capitalized approximately $0.2 million in interest expense related to its unevaluated oil and natural gas properties during the three months ended March 31, 2020.
Fair Value of Debt
At March 31,September 30, 2021, the carrying value of the outstanding debt represented by the Successor Senior Notes was approximately $1.8 billion.$548.9 million. Based on the quoted market prices (Level 1), the fair value of the Successor Senior Notes was determined to be approximately $1.6 billion$601.4 million at March 31,September 30, 2021.
6.EQUITY
As discussed in Note 2, the Company filed an amended and restated certificate of incorporation with the Delaware Secretary of State on the Emergence Date to provide for, among other things, (i) the authority to issue 42 million shares of New Common Stock with 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.
New Common Stock
On the Emergence Date, all existing shares of the 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 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 under the Company's credit agreement. This requirement with respect to PIK Dividends is no longer applicable upon the effective date of the New Credit Facility.
Each holder of shares of New Preferred Stock has the right (the “Conversion Right”), at its option and at any time, to convert all or a portion of the shares of New Preferred Stock that it holds into a number 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 Preferred Terms) on the date of conversion, by (y) $14.00 per share (as may be adjusted under the Preferred Terms) (the “Conversion Price”). The shares of New Preferred Stock outstanding at September 30, 2021 would convert to 4.1 million shares of New Common Stock if all holders of New Preferred Stock exercised their Conversion Right.
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 holders 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 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.
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The New Preferred Stock has no stated maturity and will 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 September 30, 2021, the company paid dividends on its New Preferred Stock, which included 2,065 shares of New Preferred Stock paid in kind and approximately $30 thousand of cash-in-lieu of fractional shares. The following table summarizes PIK dividends and conversions of the Company’s New Preferred Stock subsequent to the Emergence Date:
New Preferred Stock at May 18, 2021 (Successor)55,000 
Issuance of New Preferred Stock1,006 
Conversion of New Preferred Stock(146)
New Preferred Stock at June 30, 202155,860 
Issuance of New Preferred Stock2,065 
Conversion of New Preferred Stock(5)
New Preferred Stock at September 30, 202157,920 
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. The Company has granted restricted stock units to employees and directors pursuant to the Incentive Plan, as discussed below. During the Current Successor Quarter and the Current Successor YTD Period, the Company's stock-based compensation expense was $1.4 million, of which the Company capitalized $0.5 million relating to its exploration and development efforts. Stock compensation expense, net of the amounts capitalized, is included in general and administrative expenses in the accompanying consolidated statements of operations.
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The following table summarizes restricted stock unit activity for the Current Successor 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 May 18, 2021— $— — $— 
Granted198,755 65.92 141,697 47.67 
Vested— — — — 
Forfeited/canceled— — — — 
Unvested shares as of September 30, 2021198,755 $65.92 141,697 $47.67 
Successor Restricted Stock Units
Restricted stock units awarded under the Incentive Plan generally vest over a period of 1 to 4 years in the case of employees and 4 years in the case of directors upon the recipient meeting applicable service requirements. Stock-based compensation expense is 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 the grant. Unrecognized compensation expense as of September 30, 2021 was $12.2 million. The expense is expected to be recognized over a weighted average period of 3.05 years.
Successor Performance Vesting Restricted Stock Units
The Company has awarded performance vesting restricted stock units to certain of its executive officers under the Incentive Plan. The number of shares of common stock issued pursuant to the award will be based on a combination of (i) the Company's total shareholder return ("TSR") and (ii) the Company's relative total shareholder return ("RTSR") for the performance period. Participants will earn from 0% to 200% of the target award based on the Company's TSR and RTSR ranking compared to the TSR of the companies in the Company's designated peer group at the end of the performance period. Awards will be earned and vested over a performance period from May 17, 2021 to May 17, 2024, subject to earlier termination of the performance period in the event of a change in control. The grant date fair value was determined using the Monte Carlo simulation method and is being recorded ratably over the performance period. Expected volatilities utilized in the Monte Carlo model were estimated using a historical period consistent with the remaining performance period of approximately 3 years. The risk-free interest rate was based on the U.S. Treasury rate for a term commensurate with the expected life of the grant. The Company assumed a risk-free interest rate of 0.35% and expected volatility of 87.0% to estimate the fair value. Unrecognized compensation expense as of September 30, 2021, related to performance vesting restricted shares was $6.3 million. The expense is expected to be recognized over a weighted average period of 2.8 years.
Predecessor Stock-Based Compensation
The Company granted restricted stock units to employees and directors pursuant to the 2019 Amended and Restated Incentive Stock Plan ("2019 Plan"), as discussed below.. During the three months ended March 31, 2021,Current Predecessor YTD Period, the Company’s stock-based compensation cost was $3.0$4.4 million, of which the Company capitalized $0.6$0.9 million, relating to its exploration and development efforts. During the three months ended March 31, 2020,Prior Predecessor Quarter and the Prior Predecessor YTD Period, the Company’s stock-based compensation cost was $2.1$8.9 million and $13.2 million, respectively, of which the Company capitalized $0.9$0.3 million and $2.2 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.
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The following table summarizes restricted stock unit activity for the three months ended March 31, 2021: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		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, 2021Unvested shares as of January 1, 20211,702,513 $4.74 840,595 $4.07 Unvested shares as of January 1, 20211,702,513 $4.74 840,595 $4.07 
GrantedGranted0 0 0 0 Granted— — — — 
VestedVested(202,583)8.32 0 0 Vested(227,132)8.45 — — 
Forfeited/canceledForfeited/canceled(19,707)3.61 0 0 Forfeited/canceled(1,475,381)4.16 (840,595)4.07 
Unvested shares as of March 31, 20211,480,223 $4.26 840,595 $4.07 
Unvested shares as of May 17, 2021Unvested shares as of May 17, 2021— $— — $— 
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 March 31, 2021 related to restricted stock units was $4.0 million. The expense is expected to be recognized over a weighted average period of 1.12 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. RTSR is an incentive measure whereby participants will earn from 0% to 200% of the target award based on the Company’s RTSRTSR ranking compared to the RTSRTSR 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 March 31, 2021 relatedthe Emergence Date.
8.EARNINGS (LOSS) PER SHARE
Basic income or loss per share attributable to performance vesting restricted shares was $1.1 million. The expensecommon stockholders is expectedcomputed as (i) net income or loss less (ii) dividends paid to be recognized over aholders of New Preferred Stock less (iii) net income or loss attributable to participating securities divided by (iv) weighted average periodbasic shares outstanding. Diluted net income or loss per share attributable to common 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 determine the dilutive impact for the Company's convertible New Preferred Stock and the treasury stock method is used to determine the dilutive impact of 1.04 years.unvested restricted stock.
There were no potential shares of common stock that were considered dilutive for the Current Successor YTD Period, Current Successor Quarter, Current Predecessor Quarter or the Current Predecessor YTD Period. There were 4.1 million shares of potential common shares issuable due to the Company's convertible New Preferred Stock that were considered anti-dilutive for the Current Successor YTD Period due to the Company's net loss. There were 0.1 million shares of restricted stock that were considered anti-dilutive during the Current Successor Quarter and Current Successor YTD Period due to the Company's net loss.
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2020 Cash Retention Incentives
On August 4, 2020, the Company's Board of Directors authorized a redesign of the incentive compensation program for the Company's workforce, including for its current named executive officers. In connection with a comprehensive review of the Company’s compensation programs and in consultation with its independent compensation consultant and legal advisors, the Board of Directors determined that significant changes were appropriate to retain and motivate the Company’s employees as a result of the ongoing uncertainty and unprecedented disruption in the oil and gas industry.
All unpaid amounts previously awarded pursuant to the 2020 Incentive Plan and all restricted stock units granted in 2020 issued to the Company's named executive officers were cancelled and replaced with cash retention incentives. These cash retention incentives are equally weighted between achievement of certain specified performance metrics and a service period. Of the cash retention incentives, 50% may be clawed back on an after-tax basis if an executive officer terminates employment for any reason other than a qualifying termination 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 established performance metrics are not met over performance periods from August 1, 2020 through July 31, 2021. In total, $13.5 million in cash retention incentives were paid to the Company's executives in August 2020.
The transactions were considered a modification to the previously issued equity- and liability-classified awards, and the previously issued equity-classified awards were reclassified as liability awards. The after-tax value of the cash incentives paid to the Company's executives of was capitalized to prepaid expenses and other current assets in the accompanying consolidated balance sheets and will be amortized over the remaining service period. Unrecognized compensation expense as of March 31, 2021 related to these payments was $2.1 million.

7.EARNINGS (LOSS) PER SHARE
Reconciliations of the components of basic and diluted net (loss) income (loss) per common share are presented in the tables below:
Three months ended March 31,
20212020
(In thousands, except share data)
Net income (loss)$8,780 $(517,538)
Basic Shares160,812,935 159,760,222 
Basic EPS$0.05 $(3.24)
Effect of dilutive securities:
Stock options and awards0 0 
Dilutive Shares160,812,935 159,760,222 
Dilutive EPS$0.05 $(3.24)
SuccessorPredecessor
Three Months Ended September 30, 2021Three Months Ended September 30, 2020
Net loss$(461,313)$(380,963)
Dividends on New Preferred Stock(2,095)— 
Participating securities - New Preferred Stock(1)
— — 
Net loss attributable to common stockholders$(463,408)$(380,963)
Basic Shares20,598 160,683 
Basic and Dilutive EPS$(22.50)$(2.37)

SuccessorPredecessor
Period from May 18, 2021 through September 30, 2021Period from January 1, 2021 through May 17, 2021Nine Months Ended September 30, 2020
Net (loss) income attributable to Gulfport$(670,898)$250,996 $(1,459,569)
Dividends on New Preferred Stock(3,126)— — 
Participating securities - New Preferred Stock(1)
— — — 
Net (loss) income attributable to common stockholders$(674,024)$250,996 $(1,459,569)
Basic Shares20,507 160,834 160,053 
Basic and Dilutive EPS$(32.87)$1.56 $(9.12)
There were 0 potential shares of common stock that were considered dilutive for the three months ended March 31, 2021. There were 1,552,423 potential shares of common stock that were considered anti-dilutive for the three months ended March 31, 2020.
(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.
8.9.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 recorded as obligations in the accompanying consolidated balance sheets; however, theycosts associated with utilized future firm transportation and gathering agreements are reflected in the Company's estimates of proved reserves.
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Additionally, one of the requirements provided for in the RSA is that the Company must permanently reduce its future demand reservation fees owed over the life of all of its firm transportation agreements, taken as a whole, by at least 50% of the amount of all such fees owed on October 31, 2020, as calculated on a PV-10 basis. Additionally, the Company must reduce the future firm transportation demand reservation volumes over the life of all of its firm transportation agreements, taken as a whole, by at least 35%. Since the filing of the Chapter 11 Cases in November 2020, the Company has successfully renegotiated or terminated certain of its midstream contracts and commitments, significantly reducing its transportation expenses. As of March 31, 2021, the Company was still negotiating certain of its midstream contracts pending emergence from Chapter 11. However, there can be no assurances the Company will successfully renegotiate or terminate any additional midstream contracts. The below table reflects the Company's obligations as of March 31, 2021 excluding contemplation of any contracts yet to be terminated or renegotiated throughout the Chapter 11 Cases.
A summary of these commitments at March 31,September 30, 2021 are set forth in the table below, excluding contracts recently rejected or in the process of being rejected as discussed in the Litigation and Regulatory Proceedings section below:
(In thousands)(In thousands)
Remaining 2021Remaining 2021$242,253 Remaining 2021$61,609 
20222022324,048 2022224,537 
20232023322,241 2023222,730 
20242024302,116 2024215,865 
20252025215,119 2025137,116 
ThereafterThereafter1,575,874 Thereafter977,616 
TotalTotal$2,981,651 Total$1,839,473 
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 operated production has generally been sufficient to satisfy its delivery commitments during the periods presented, and it expects its operated production will continue to be the primary means of fulfilling its future commitments. However, where the Company's operated 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 March 31,September 30, 2021 are set forth in the table below:
(MMBtu per day)(MMBtu per day)
Remaining 2021Remaining 202161,000 Remaining 202116,000 
2022202249,000 20224,000 
202317,000 
Total127,000
Litigation and Regulatory ProceedingsContingencies
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.

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 ("TC") and Rover Pipeline LLC ("Rover") or jointly as 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. During the third quarter of 2021, Gulfport finalized a settlement agreement with TC that was approved by the Bankruptcy Court on September 21, 2021. Pursuant to the settlement agreement, Gulfport and TC agreed that the firm transportation contracts between Gulfport and TC would be rejected without any further
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payment or obligation by Gulfport or TC, and TC assigned its damages claims from such rejection to Gulfport. In exchange, Gulfport agreed to make a payment of $43.8 million in cash to TC. The $43.8 million was paid to TC on October 7, 2021 and as of September 30, 2021 is presented in "Accounts payable and accrued liabilities" in the accompanying consolidated balance sheet. Gulfport expects to receive distributions for substantially all of the $43.8 million payment based on the assigned claims pursuant to Gulfport’s Chapter 11 plan of reorganization that became effective in May 2021. Any future distributions will be recognized once received by Gulfport. The Company believes that the remaining Pending Motion to Reject will be ultimately granted, and that the Company does not have any ongoing obligation pursuant to the contract; however, in the event that the Company is not permitted to reject the Rover firm transportation contract, it could be liable for demand charges, attorneys' fees and interest in excess of approximately $40 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 District of the State of Louisiana in the 15th Judicial District Court for the Parish of Vermilion on July 29, 2016 (together, the
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"Complaints" "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. On September 9, 2021, the State of Louisiana and Cameron Parish dismissed all claims against Gulfport without prejudice.
In September 2019, a stockholder of Mammoth Energy filed a derivative action on behalf of Mammoth Energy against members of Mammoth Energy’s boardBoard of directors,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 boardBoard of directorsDirectors 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 boardBoard of directorsDirectors to make specified corporate governance reforms.
In On October 2019, Kelsie Wagner, in her capacity as trustee4, 2021, plaintiffs filed a stipulation and agreement of various trusts and on behalf ofsettlement to dismiss all claims against Gulfport that is pending approval by 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. This matter was administratively terminated on December 2, 2020.trial court.
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. On October 16, 2021, Gulfport filed a motion to dismiss that is currently pending before the trial court.
TheIn 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, and Stingray filed claims in the Chapter 11 proceedings exceeding $80 million related to breach of contract damages, attorneys' fees and interest. In September 2021, Gulfport reached an agreement in principle with Stingray that fully resolves the litigation between the parties. Pursuant to the settlement, Stingray and Gulfport have agreed to drop all of the claims brought against each other in Delaware Court and Bankruptcy Court. On September 22, 2021, the parties announced to the bankruptcy court that all Stingray claims would be withdrawn. The parties are finalizing settlement documents.

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 alleges that the Company breached its obligation to purchase a certain amount of proppant sand each month or make designated shortfall payments under the Sand Supply Agreement, effective October 1, 2014, as amended (the “Sand Supply Agreement”), between Muskie and the Company, and seeks payment of unpaid shortfall payments, and Muskie
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filed a claim in the Chapter 11 proceedings for $3.4 million. On September 22, 2021, the parties announced to the bankruptcy court that an agreed claim for $3.1 million would resolve the matter. The parties are finalizing settlement documents.
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 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, and claims were filed in the Chapter 11 proceedings totaling $5.8 million.
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 alleges that the Company breached its obligation to purchase a certain amount of proppant sand each month or make designated shortfall payments under the Sand Supply Agreement, effective On October 1, 2014, as amended (the “Sand Supply Agreement”), between Muskie and2021, the Company, and seeks paymentbankruptcy court approved the parties' settlement resolving all claims for a bankruptcy claim of unpaid shortfall payments, and Muskie filed a claim in the Chapter 11 proceedings for $3.4approximately $0.7 million.
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 Final dismissal is currently pending before 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. Ohio Eastern Division.
The Company, believes thatalong with other 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 Pending Motions to Reject will be ultimately granted, and thatUnited States District Court for the Company does not have any ongoing obligations pursuantSouthern District of Ohio on December 6, 2018. Plaintiffs assert their respective leases are limited to the contracts; however, inMarcellus 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 event thatfull value of any production from below the Company is not permittedMarcellus and Utica shale formations, unspecified damages from the diminution of value to reject these firm transportation contracts,their mineral estate, unspecified punitive damages, and the monetary damages awarded could be greater than $57 million.
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reasonable attorney fees, legal expenses, and 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. Gulfport 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.
Other Matters
Based on management’s current assessment, they are of the opinion that no pending or threatened lawsuit or dispute relating to its business operations is likely to have a material adverse effect on their future consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.
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9.10.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 mitigate risks related to unfavorable changes in natural gas, oil and NGL prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps, collars and various types of option contracts. These contractsThe derivative instruments allow the Company to mitigate the impact of declines in future natural gas, oil and NGLcommodity prices by effectively locking in a floor price for a certain level of the Company’s production. However, these hedge contractsinstruments also limit the benefit tofuture gains from favorable price movements. The volume of commodity derivative instruments utilized by the Company in periods when the future market prices of natural gas, oil and NGL that are higher than the hedged prices.may vary from year to year based on forecasted production.
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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. propane.
Below is a summary of the Company’s open fixed price swap positions as of March 31,September 30, 2021. 
LocationDaily Volume
(MMBtu/day)		Weighted
Average Price
Remaining 2021NYMEX Henry Hub351,316 $2.73 
LocationDaily VolumeWeighted
Average Price
Natural Gas(MMBtu/d)($/MMBtu)
Remaining 2021NYMEX Henry Hub198,000 $2.85 
2022NYMEX Henry Hub140,740 $2.88 
2023NYMEX Henry Hub34,932 $3.24 
Oil(Bbl/d)($/Bbl)
Remaining 2021NYMEX WTI3,000 $57.67 
2022NYMEX WTI2,104 $66.23 
NGL(Bbl/d)($/Bbl)
Remaining 2021Mont Belvieu C33,100 $27.80 
2022Mont Belvieu C33,378 $35.09 
LocationDaily Volume
(Bbl/day)		Weighted
Average Price
Remaining 2021NYMEX WTI1,505 $53.07 
LocationDaily Volume
(Bbl/day)		Weighted
Average Price
Remaining 2021Mont Belvieu C32,074 $27.80 
2022Mont Belvieu C3496 $27.30 

In 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 on certain natural gas swaps that settled in 2020. Each call option has an established ceiling price of $2.90/MMBtu. If monthly NYMEX natural gas prices settle above the $2.90$2.90/MMBtu ceiling price, the Company is required to pay the option counterparty an amount equal to the difference between the referenced NYMEX natural gas settlement price and $2.90$2.90/MMBtu multiplied by the hedged contract volumes.
Below is a summary of the Company's sold natural gas call option positions as of March 31,September 30, 2021.
LocationDaily Volume
(MMBtu/day)		Weighted Average PriceLocationDaily VolumeWeighted Average Price
Natural GasNatural Gas(MMBtu/d)($/MMBtu)
20222022NYMEX Henry Hub152,675 $2.90 2022NYMEX Henry Hub152,675 $2.90 
20232023NYMEX Henry Hub627,675 $2.90 2023NYMEX Henry Hub627,675 $2.90 
The Company entered into costless collars based off the NYMEX WTI and Henry Hub oil and natural gas index.indices. Each two-way price collar has a set floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, the Company will cash-settle the difference with the hedge counterparty.
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Below is a summary of the Company's costless collar positions as of March 31,September 30, 2021.
LocationDaily Volume (MMBtu/day)Weighted Average Floor PriceWeighted Average Ceiling PriceLocationDaily VolumeWeighted Average Floor PriceWeighted Average Ceiling Price
Natural GasNatural Gas(MMBtu/d)($/MMBtu)($/MMBtu)
Remaining 2021Remaining 2021NYMEX Henry Hub390,509 $2.54 $2.93 Remaining 2021NYMEX Henry Hub610,000 $2.59 $3.02 
20222022NYMEX Henry Hub186,438 $2.63 $3.04 2022NYMEX Henry Hub406,747 $2.58 $2.91 
OilOil(Bbl/d)($/Bbl)($/Bbl)
20222022NYMEX WTI1,500 $55.00 $60.00 
In addition, the Company entered into natural gas basis swap hedge contracts. If the applicable monthly price indices are outside of the ranges set forth in the various natural gas basis swap contracts, the Company will cash-settle the difference with the hedge counterparty.
Below is a summary of the Company's natural gas basis swap positions as of March 31,September 30, 2021.
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Gulfport PaysGulfport ReceivesDaily Volume
(MMBtu/day)		Weighted Average Fixed SpreadGulfport PaysGulfport ReceivesDaily VolumeWeighted Average Fixed Spread
Natural GasNatural Gas(MMBtu/d)($/MMBtu)
Remaining 2021Remaining 2021Rex Zone 3NYMEX Plus Fixed Spread85,309 $(0.22)Remaining 2021Rex Zone 3NYMEX Plus Fixed Spread83,152 $(0.12)
Remaining 2021Tetco M2NYMEX Plus Fixed Spread32,384 $(0.63)
20222022Rex Zone 3NYMEX Plus Fixed Spread14,795 $(0.10)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 March 31,September 30, 2021 and December 31, 2020:
March 31, 2021December 31, 2020SuccessorPredecessor
(In thousands)September 30, 2021December 31, 2020
Short-term derivative assetShort-term derivative asset$12,422 $27,146 Short-term derivative asset$2,142 $27,146 
Long-term derivative assetLong-term derivative asset652 322 Long-term derivative asset961 322 
Short-term derivative liabilityShort-term derivative liability(20,687)(11,641)Short-term derivative liability(560,722)(11,641)
Long-term derivative liabilityLong-term derivative liability(43,267)(36,604)Long-term derivative liability(272,935)(36,604)
Total commodity derivative positionTotal commodity derivative position$(50,880)$(20,777)Total commodity derivative position$(830,554)$(20,777)
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Gains and Losses
The following table presentstables present the gain and loss recognized in net (loss) gain on natural gas, oil and NGL derivatives in the accompanying consolidated statements of operations for the three months ended March 31, 2021 and 2020.operations:
Net (loss) gain on derivative instruments
Three months ended March 31,
20212020
(In thousands)
Natural gas derivatives$(25,413)$45,853 
Oil derivatives(1,731)52,874 
NGL derivatives(2,834)920 
Contingent consideration arrangement0 (1,381)
Total$(29,978)$98,266 
Net loss on derivative instruments
SuccessorPredecessor
Three Months Ended September 30, 2021Three Months Ended September 30, 2020
Natural gas derivatives - fair value losses$(517,799)$(84,390)
Natural gas derivatives - settlement (losses) gains(82,566)31,742 
Total losses on natural gas derivatives(600,365)(52,648)
Oil and condensate derivatives - fair value (losses) gains(1,590)723 
Oil and condensate derivatives - settlement losses(4,336)(1,505)
Total losses on oil and condensate derivatives(5,926)(782)
NGL derivatives - fair value losses(10,201)(288)
NGL derivatives - settlement losses(5,984)(105)
Total losses on NGL derivatives(16,185)(393)
Total losses on natural gas, oil and NGL derivatives$(622,476)$(53,823)
Net (loss) gain on derivative instruments
SuccessorPredecessor
Period from May 18, 2021 through September 30, 2021Period from January 1, 2021 through May 17, 2021Nine Months Ended September 30, 2020
Natural gas derivatives - fair value losses$(638,063)$(123,080)$(147,661)
Natural gas derivatives - settlement (losses) gains(89,255)(3,362)176,555 
Total (losses) gains on natural gas derivatives(727,318)(126,442)28,894 
Oil and condensate derivatives - fair value losses(6,947)(6,126)(4,289)
Oil and condensate derivatives - settlement (losses) gains(4,336)— 48,444 
Total (losses) gains on oil and condensate derivatives(11,283)(6,126)44,155 
NGL derivatives - fair value losses(17,549)(4,671)(620)
NGL derivatives - settlement (losses) gains(5,984)— 366 
Total losses on NGL derivatives(23,533)(4,671)(254)
Contingent consideration arrangement - fair value losses— — (1,381)
Total (losses) gains on natural gas, oil and NGL derivatives$(762,134)$(137,239)$71,414 
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 March 31, 2021
Gross Assets (Liabilities)Gross Amounts
Presented in theSubject to MasterNet
Consolidated Balance SheetsNetting AgreementsAmount
(In thousands)
Derivative assets$13,074 $(13,074)$0 
Derivative liabilities$(63,954)$13,074 $(50,880)
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As of December 31, 2020Successor
Gross Assets (Liabilities)Gross AmountsAs of September 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$27,468 $(25,730)$1,738 Derivative assets$3,103 $(3,103)$— 
Derivative liabilitiesDerivative liabilities$(48,245)$25,730 $(22,515)Derivative liabilities$(833,657)$3,103 $(830,554)
Predecessor
As of December 31, 2020
Gross Assets (Liabilities)Gross Amounts
Presented in theSubject to MasterNet
Consolidated Balance SheetsNetting AgreementsAmount
Derivative assets$27,468 $(25,730)$1,738 
Derivative liabilities$(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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10.11.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.
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Financial assets and liabilities
The following tables summarize the Company’s financial and non-financial assets and liabilities by valuation level as of March 31,September 30, 2021 and December 31, 2020:
March 31, 2021Successor
Level 1Level 2Level 3 September 30, 2021
(In thousands)Level 1Level 2Level 3
Assets:Assets:Assets:
Derivative InstrumentsDerivative Instruments$0 $13,074 $0 Derivative Instruments$— $3,103 $— 
Contingent consideration arrangementContingent consideration arrangement$0 $0 $6,000 Contingent consideration arrangement— — 5,300 
Total assetsTotal assets$0 $13,074 $6,000 Total assets$— $3,103 $5,300 
Liabilities:Liabilities:Liabilities:
Derivative InstrumentsDerivative Instruments$0 $63,954 $0 Derivative Instruments$— $833,657 $— 
December 31, 2020Predecessor
Level 1Level 2Level 3 December 31, 2020
(In thousands)Level 1Level 2Level 3
Assets:Assets:Assets:
Derivative InstrumentsDerivative Instruments$0 $27,468 $0 Derivative Instruments$— $27,468 $— 
Contingent consideration arrangementContingent consideration arrangement$0 $0 $6,200 Contingent consideration arrangement— — 6,200 
Total assetsTotal assets$0 $27,468 $6,200 Total assets$— $27,468 $6,200 
Liabilities:Liabilities:Liabilities:
Derivative InstrumentsDerivative Instruments$0 $48,245 $0 Derivative Instruments$— $48,245 $— 

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.
The Company's SCOOP water infrastructure sale, which closed in the first quarter of 2020, included a contingent consideration arrangement. As of March 31,September 30, 2021, the fair value of the contingent consideration was $6.0$5.3 million, of which
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$1.3 $0.8 million is included in prepaid expenses and other assets and $4.7$4.5 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 an immaterial gaina $1.2 million loss for the Current Successor Quarter, a $0.1 million loss for the Current Successor YTD Period, and a nominal gain of $0.2 million on changes in fair value offor the contingent consideration during the three months ended March 31, 2021 and 2020,Current Predecessor YTD Period, respectively, which is included in other expense (income) in the accompanying consolidated statements of operations. The Company recognized losses of $0.2 million and $3.1 million on changes in fair value of the contingent consideration during the Prior Predecessor Quarter and Prior Predecessor YTD Period, respectively. Settlements under the contingent consideration arrangement totaled $0.6 million during the Current Successor YTD Period, $0.2 million during the Current Predecessor YTD Period, and $0.3 million during the 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 34 for further discussion of the Company’s asset retirement obligations. Asset retirement obligations incurred during the three months ended March 31, 2021 were approximately $0.5 million.
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As discussed in Note 34, the Company recorded an impairment during the three months ended March 31, 2021Current 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 building 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
11.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 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 midstream,transportation, gathering, processing and processingcompression 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
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product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure
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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 $134.0$185.9 million and $119.9 million as of March 31,September 30, 2021 and December 31, 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 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 three months ended March 31, 2021,Current Predecessor YTD Period and the Current Successor YTD Period, revenue recognized in the reporting periodperiods related to performance obligations satisfied in prior reporting periods was not material.
12.13.EQUITY INVESTMENTS
Investments accounted for by the equity method during the periods presented consisted of the following:
Carrying valueLoss from equity method investments
PredecessorPredecessor
December 31, 2020Three Months Ended September 30, 2020Period from January 1, 2021 through May 17, 2021Nine Months Ended September 30, 2020
Investment in Grizzly Oil Sands ULC$24,816 $(153)$(342)$(341)
Investment in Mammoth Energy— — — (10,646)
$24,816 $(153)$(342)$(10,987)
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 September 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 has not paid any cash calls since its decision to cease funding further capital calls in 2019. Grizzly’s functional currency is the Canadian dollar. For the Prior Predecessor Quarter and the Prior Predecessor YTD Period, the Company's investment in Grizzly increased by $3.7 million and decreased by $4.1 million, respectively, as a result of foreign currency translation gains and losses.
Effective as of the Emergence Date, the Company evaluated its investment in Grizzly and determined that the Company no longer has the ability to exercise significant influence over operating and financial policies of Grizzly. As such, the equity method of accounting for its investment was no longer applicable. As a result, the Company will use its previous carrying value of zero (as discussed below) as its initial basis and will subsequently measure at fair value while recording any changes in fair value in earnings.
As discussed in Note 3, the Company reduced the carrying value of its investment in Grizzly to zero 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 its equity ownership interest.
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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 zero in the first quarter of 2020 due to the Company's share of cumulative net loss and impairments and the carrying value remained at zero through the Emergence Date.
14.RESTRUCTURING AND LIABILITY MANAGEMENT
In the third quarter of 2021, the Company announced and completed a workforce reduction representing approximately 3% of its headcount. Charges related to the reduction in workforce primarily consisted of one-time employee-related termination benefits. Additionally, the Company incurred charges related to financial and legal advisors engaged to assist with the evaluation of a range of liability management alternatives during the Prior Predecessor Quarter and Prior Predecessor YTD Period.
The following table summarizes the restructuring and liability management charges incurred:
SuccessorPredecessor
Three months ended September 30, 2021Three months ended September 30, 2020
Reduction in workforce$2,858 $1,460 
Liability management— 7,524 
Total restructuring and liability management$2,858 $8,984 
SuccessorPredecessor
Period from May 18, 2021 through September 30, 2021Period from January 1, 2021 through May 17, 2021Nine months ended September 30, 2020
Reduction in workforce$2,858 $— $1,460 
Liability management— — 8,141 
Total restructuring and liability management$2,858 $— $9,601 
15.LEASES
Nature of Leases
The Company has operating leases on certain equipment and field offices with remaining lease 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 contracts for drilling rigs with varying terms with third parties to ensure operational continuity, cost control and rig availability in its operations.for drilling rigs. The CompanyCompany has concluded its drilling rig contracts are operating leases as the assets are identifiable and the Company has the right to control the identified assets. The Company's drilling rig commitments are typically structured with an initial term of less than one year to two years, althoughHowever, at March 31,September 30, 2021, the Company did not have any active long-term drilling rig contracts in 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 2024.2022. 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
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incremental borrowing rate reflects the estimated rate of interest that it would pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment.
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Maturities of operating lease liabilities as of March 31,September 30, 2021 were as follows:
(In thousands)(In thousands)
Remaining 2021Remaining 2021$97 Remaining 2021$10 
20222022115 202225 
202390 
202430 
Total lease paymentsTotal lease payments$332 Total lease payments$35 
Less: Imputed interestLess: Imputed interest(18)Less: Imputed interest(1)
TotalTotal$314 Total$34 
LeaseThe table below summarizes lease cost for the three months ended March 31, 2021 and 2020 consisted of the following:periods presented:
Three months ended March 31,
20212020SuccessorPredecessor
(In thousands)Three Months Ended September 30, 2021Three Months Ended September 30, 2020
Operating lease costOperating lease cost$32 $4,082 Operating lease cost$10 $1,692 
Variable lease costVariable lease cost0 224 Variable lease cost— 245 
Short-term lease costShort-term lease cost2,189 2,810 Short-term lease cost2,873 2,259 
Total lease cost(1)
Total lease cost(1)
$2,221 $7,116 
Total lease cost(1)
$2,883 $4,196 
SuccessorPredecessor
Period from May 18, 2021 through September 30, 2021Period from January 1, 2021 through May 17, 2021Nine Months Ended September 30, 2020
Operating lease cost$18 $41 $7,970 
Variable lease cost— — 705 
Short-term lease cost5,033 4,496 7,698 
Total lease cost(1)
$5,051 $4,537 $16,373 
(1)The majority of the Company's total lease cost was capitalized to the full cost pool, and the remainder was included in either lease operating expenses or general and administrative expenses in the accompanying consolidated statements of operations.
Supplemental cash flow information for the three months ended March 31, 2021 and 2020 related to leases was as follows:
Three months ended March 31,SuccessorPredecessor
20212020Period from May 18, 2021 through September 30, 2021Period from January 1, 2021 through May 17, 2021Nine Months Ended September 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$31 $36  Operating cash flows from operating leases$46 $48 $109 
Investing cash flow from operating leases Investing cash flow from operating leases$0 $3,997  Investing cash flow from operating leases— — 9,786 
Investing cash flow from operating leases—related party Investing cash flow from operating leases—related party$0 $6,800  Investing cash flow from operating leases—related party— — 6,800 
The weighted-average remaining lease term as of March 31,September 30, 2021 was 2.80.89 years. The weighted-average discount rate used to determine the operating lease liability as of March 31,September 30, 2021 was 4.22%3.98%.
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13.16.INCOME TAXES
The Company records its quarterly tax provision based on an estimateAs discussed in Note 2, elements of the annual effective tax rate expectedPlan provided that the Company’s indebtedness related to apply to continuing operations for the various jurisdictions in which it operates. The tax effects of certain items, such as tax rate changes, significant unusual or infrequent items,Predecessor Senior Notes and certain changesgeneral 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 assessmentamount 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 months ended March 31, 2021, the Company's estimated annual effective tax rate before discrete items was approximately 0%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 September 30, 2021, the Company had an estimated federal net operating loss carryforward of approximately $1.2 billion after giving effect to the estimated reduction in tax attributes as discussed above.

Emergence from Chapter 11 bankruptcy proceedings resulted in a change in ownership for purposes of IRC Section 382. The Company currently expects to apply rules under IRC Section 382(l)(5) that would allow the Company to mitigate the limitations imposed under the regulations with respect to the Company’s remaining tax attributes. The Company’s deferred tax assets and liabilities, prior to the valuation allowance, have been computed on 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.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.

At each reporting period, the Company weighs all available positive and negative evidence to determine whether its deferred tax assets are more likely than not to 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
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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. The cumulative loss in recent years is a significant piece of negative evidence that is hard to overcome and thereforeBased upon the Company placed more reliance on historical results than forecasts. As a result of thisCompany’s analysis, the Company determined a full valuation allowance of $911.4 million was necessary against its net deferred tax assetassets as of March 31,both May 17, 2021 and September 30, 2021.

The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until it is determined that 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 recognizes taxable income. As long as the Company concludes that the valuation allowance against its net deferred tax assets is necessary, the Company likely will not have any additional deferred income tax expense or benefit.
14.
For the Current Predecessor YTD Period, the Company has an effective tax rate of (3.4)% 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 Current Successor YTD Period, the Company has an effective tax rate of (0.01)% and tax expense of $0.7 million. The tax expense is entirely attributable to the Oklahoma refund claim that was filed during the third quarter of 2021, resulting in an adjustment to the benefit recorded during the Current Predecessor YTD Period. We did not record any additional income tax expense for the Current Successor YTD Period as a result of maintaining a full valuation allowance against our net deferred tax asset. For the Prior Predecessor Quarter, the Company had an effective tax rate of 0% and tax expense of zero due to the Company’s valuation allowance position. For the Prior Predecessor YTD Period, the Company had an effective tax rate of (0.5)% 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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17.SUBSEQUENT EVENTS
Chapter 11 Proceedings UpdateNew Credit Facility
The Bankruptcy CourtOn October 14, 2021, the Company entered into the Third Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A., as administrative agent, and various lender parties ("New Credit Facility"). The New Credit Facility provides for an order confirming the Plan on April 28, 2021. In supportaggregate maximum principal amount of up to $1.5 billion, an initial borrowing base of $850.0 million and an initial aggregate elected commitment amount of $700.0 million. The credit agreement also provides for a $175.0 million sublimit of the Plan,aggregate commitments that is available for the enterprise valueissuance of letters of credit. The New Credit Facility amended and refinanced the Exit Credit Facility.
The borrowing base will be redetermined semiannually on or around May 1 and November 1 of each year, with the first scheduled redetermination to be on or around May 1, 2022. The New Credit Facility matures in October 2025.
The New Credit Facility bears interest at a rate equal to, at the Company’s election, either (a) LIBOR plus an applicable margin that varies from 2.75% to 3.75% per annum or (b) a base rate plus an applicable margin that varies from 1.75% to 2.75% per annum, based on borrowing base utilization. The New Credit Facility will mature on October 14, 2025. The Company is required to pay a commitment fee of 0.50% per annum on the average daily unused portion of the Successor was estimatedcurrent aggregate commitments under the New Credit Facility. The Company is also required to pay customary letter of credit and approved by the Bankruptcy Court to be in the range of $1.3 billion to $1.9 billion.fronting fees.
Upon emergence from bankruptcy, which is expected to occur in May 2021, Gulfport expects to qualify for fresh-start reporting. In order to qualify for fresh start-reporting (i) the holders of existing voting shares of the Company prior to its emergence must receive less than 50% of the voting shares of the Company outstanding following its emergence from bankruptcy and (ii) the reorganization value of our assets immediately prior to confirmation of the plan of reorganization must be less than the post-petition liabilities and allowed claims. Under the principles of fresh-start reporting, a new reporting entity will be considered to have been created, and, as a result, the Company will allocate the reorganization value ofThe credit agreement requires the Company to its individualmaintain as of the last day of each fiscal quarter (i) a net funded leverage ratio of less than or equal to 3.25 to 1.00, and (ii) a current ratio of greater than or equal to 1.00 to 1.00.
The obligations under the New Credit Facility, certain swap obligations and certain cash management obligations, are guaranteed by the Company and the wholly-owned domestic material subsidiaries of the Borrower (collectively, the “Guarantors” and, together with the Borrower, the “Loan Parties”) and secured by substantially all of the Loan Parties’ assets (subject to customary exceptions).
The credit agreement also contains customary affirmative and negative covenants, including, property, plantamong other things, as to compliance with laws (including environmental laws and equipment, based on their estimated fair values. Gulfport cannot currently estimate the financial effectanti-corruption laws), delivery of emergence from bankruptcy on itsquarterly and annual financial statements although it expectsand borrowing base certificates, conduct of business, maintenance of property, maintenance of insurance, entry into certain derivatives contracts, restrictions on the incurrence of liens, indebtedness, asset dispositions, restricted payments, and other customary covenants. These covenants are subject to record material adjustments relateda number of limitations and exceptions.
Share Repurchase Program
On November 1, 2021, the Company's Board of Directors approved a stock repurchase program to acquire up to $100.0 million of its PlanNew Common Stock ("Repurchase Program"). Purchases under the Repurchase Program may be made from time to time in open market or privately negotiated transactions, and will be subject to available liquidity, market conditions, credit agreement restrictions, applicable legal requirements, contractual obligations and other factors. The Repurchase Program does not require the applicationCompany to acquire any specific number of fresh-start reporting guidance uponshares of New Common Stock. The Company intends to purchase shares under the Effective Date.Repurchase Program opportunistically with available funds while maintaining sufficient liquidity to fund its capital development program. The Repurchase Program is authorized to extend through December 31, 2022 and may be suspended from time to time, modified, extended or discontinued by the board of directors at any time. Any shares of New Common Stock repurchased are expected to be cancelled.
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Natural Gas Oil and Natural Gas LiquidsOil Derivative Instruments
Subsequent to March 31,September 30, 2021 and as of April 30,October 28, 2021, the Company entered into the following natural gas and oil derivative contracts as it completed minimum hedging requirements as provided for in the RSA:contracts:
PeriodType of Derivative InstrumentIndex
Daily Volume(1)
Weighted
Average Price
November 2021 - March 2022Basis SwapsRex Zone 340,000 $(0.10)
April 2022 - December 2022Costless CollarsNYMEX Henry Hub139,773 $2.40/$2.60
January 2022 - December 2022Costless CollarsNYMEX WTI1,500 $55.00/$60.00
Type of Derivative InstrumentIndexDaily VolumeWeighted
Average Price
Natural Gas(MMBtu/d)($/MMBtu)
November 2021 - December 2021Basis SwapONG Minus Inside FERC20,000 $0.50
January 2022 - March 2022Basis SwapONG Minus Inside FERC20,000 $0.50
January 2023 - December 2023Fixed price swapNYMEX Henry Hub30,000 $3.58
(1)    Volume units for gas instruments are presented as MMBtu/day and oil is presented in Bbls/day.

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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 Notes included in Part I, Item 1 of this Quarterly Report on Form 10-Q.
The following information updates the discussion of Gulfport’s financial condition provided in its Annual Report on Form 10-K for the year ended December 31, 2020 (“2020 Form 10-K”), and analyzes the changes in the results of operations between the periods of May 18, 2021 through September 30, 2021 (“Current Successor YTD Period”), January 1, 2021, through May 17, 2021 (“Current Predecessor YTD Period”), the three months ended September 30, 2021 ("Current Successor Quarter"), the three months ended September 30, 2020 (“Prior Predecessor Quarter”) and the nine months ended September 30, 2020 ("Prior Predecessor YTD Period"). For definitions of commonly used natural gas and oil terms found in this Quarterly Report on Form 10-Q, please refer to the “Definitions” provided in this report and in our 2020 Form 10-K.
Gulfport is an independent natural gas-weighted exploration and production company with assets primarily located in the Appalachia and Anadarko 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 Current Successor Quarter, Current Successor YTD Period, and the 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 nine months ended September 30, 2021 by combining the results of the Current Successor YTD Period and the Current Predecessor YTD Period ("Current Combined 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 Current Successor YTD Period combined with the 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.

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We believe we have emerged from the Chapter 11 Cases as a fundamentally stronger company, built to generate sustainable free cash flow with a strengthened balance sheet. As a result of the Chapter 11 Cases, we reduced our total indebtedness by $1.4 billion by issuing equity in a reorganized entity to the holders of our unsecured notes and allowed general unsecured claimants.

Chief Executive Officer
On September 2, 2021, we reached agreement with Timothy Cutt, effective immediately, to fully assume the role of Chief Executive Officer, dropping the "Interim" designation from his title.

New Credit Facility

On October 14, 2021, we entered into the New Credit Facility for an aggregate maximum principal amount of up to $1.5 billion, an initial borrowing base of $850.0 million and an initial aggregate elected commitment amount of $700.0 million. The New Credit Facility amends and refinances the Exit Credit Facility. See Note 17 for additional discussion of the New Credit Facility.
Share Repurchase Program
On November 1, 2021, our board of directors has approved a stock Repurchase Program to acquire up to $100.0 million of our outstanding New Common Stock. Purchases under the Repurchase Program may be made from time to time in open market or privately negotiated transactions, and will be subject to available liquidity, market conditions, credit agreement restrictions, applicable legal requirements, contractual obligations and other factors. The Repurchase Program does not require us to acquire any specific number of shares of New Common Stock. We intend to purchase shares under the Repurchase Program opportunistically with available funds while maintaining sufficient liquidity to fund our capital development program. The Repurchase Program is authorized to extend through December 31, 2022 and may be suspended from time to time, modified, extended or discontinued by the board of directors at any time. Any shares of New Common Stock repurchased are expected to be cancelled.
COVID-19 Pandemic and Impact on Global Demand for Oil and Natural Gas

As a result of our business continuity measures, we have not experienced significant disruptions in executing our business operations due to COVID-19. While we did not experience significant disruptions to our operations in the first nine months 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. Restrictions 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. Additionally, 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.
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 and the timing and extent to which normal economic and operating conditions resume.
2021 Operational and Financial Highlights
During the third quarter of 2021, we had the following notable achievements:
•In September 2021, we finalized a settlement agreement with TC Energy Corporation ("TC") which rejected the firm transportation contracts between us and TC without any further payment or obligation by us or TC. As a result of the settlement agreement, TC assigned its damages claims from such rejection to us. In exchange, we agreed to make a payment of $43.8 million in cash to TC. We expect to recover all, or substantially all, of such amount through future
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distributions with respect to the assigned claims, with a material portion expected to be received in the next twelve months.
•In September 2021, we also reached an agreement in principle with Stingray Pressure Pumping LLC that fully resolves the longstanding litigation between the parties.
•In September 2021, we completed the six-well Angelo pad in the Utica. In early October 2021, we brought the pad online at a combined gross production rate of 250 MMcfe per day.
•On October 14, 2021, we amended and refinanced our Exit Credit Facility with the New Credit Facility. The amendment increased our elected commitment from $580 million to $700 million and increased our liquidity by more than $160 million.
2021 Production and Drilling Activity
Production Volumes
SuccessorPredecessor
Three Months Ended September 30, 2021Three Months Ended September 30, 2020
Natural gas (Mcf/day)
Utica678,154 763,387 
SCOOP188,292 139,233 
Other— 40 
Total866,446 902,660 
Oil and condensate (Bbl/day)
Utica958 1,579 
SCOOP4,335 3,204 
Other78 57 
Total5,371 4,840 
NGL (Bbl/day)
Utica2,516 2,917 
SCOOP9,918 7,128 
Other— 2 
Total12,434 10,047 
Combined (Mcfe/day)
Utica698,998 790,363 
SCOOP273,812 201,227 
Other471 393 
Total973,281 991,983 
Our total net production averaged approximately 973.3 MMcfe per day during the Current Successor Quarter, as compared to 992.0 MMcfe per day during the Prior Predecessor Quarter. The 2% decrease in production is largely the result of a decrease in the Utica due to timing of development activity in 2021 compared to the Prior Predecessor Quarter. We anticipate an increase in total net production during the fourth quarter of 2021 driven by our six-well Angelo development in the Utica turning to sales.
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SuccessorPredecessorNon-GAAP CombinedPredecessor
Period from May 18, 2021 through September 30, 2021Period from January 1, 2021 through May 17, 2021Nine Months Ended September 30, 2021Nine Months Ended September 30, 2020
Natural gas (Mcf/day)
Utica682,596 780,791 731,873 774,705 
SCOOP190,305 126,294 158,182 152,595 
Other38 63 51 44 
Total872,939 907,148 890,106 927,344 
Oil and condensate (Bbl/day)
Utica1,012 1,336 1,175 829 
SCOOP4,493 2,508 3,497 4,185 
Other76 35 55 73 
Total5,581 3,879 4,727 5,087 
NGL (Bbl/day)
Utica2,588 2,638 2,613 2,882 
SCOOP9,645 6,200 7,916 8,167 
Other— 3 2 1 
Total12,233 8,841 10,531 11,050 
Combined (Mcfe/day)
Utica704,196 804,633 754,598 796,972 
SCOOP275,134 178,545 226,662 226,705 
Other498 288 392 488 
Total979,828 983,466 981,653 1,024,165 
Our total net production averaged approximately 981.7 MMcfe per day during the Current Combined YTD Period, as compared to 1,024.2 MMcfe per day during the Prior Predecessor YTD Period. The 4% decrease in production is largely the result of a decrease in development activity in the Utica due to timing of development activity in 2021 when compared to the Prior Predecessor YTD Period.
Utica. We spud 12 gross (11.6 net) wells in the Utica during the Current Combined YTD Period, of which four were producing, two were being drilled, and six were in various stages of operations at September 30, 2021. In addition, we completed 11 gross and net operated wells. We did not participate in any additional wells that were drilled by other operators on our Utica acreage.
As of October 28, 2021, we had two operated drilling rigs running in the Utica, which we expect will continue through the remainder of 2021.
SCOOP. We spud four gross (3.9 net) wells in the SCOOP during the Current Combined YTD Period, of which one was being drilled and three were waiting on completion. In addition, we completed 11 gross (9.3 net) operated wells. We also participated in an additional 15 gross (1.6 net) wells that were drilled by other operators on our SCOOP acreage.
As of October 28, 2021, we had one operated drilling rig running in the SCOOP. We expect to add one operated drilling rig in the SCOOP in the fourth quarter of 2021.
RESULTS OF OPERATIONS
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Current Successor Quarter Compared to 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 Current Successor Quarter as compared to the Prior Predecessor Quarter: Some totals throughout below sections may not sum or recalculate due to rounding.
 SuccessorPredecessor
Three Months Ended September 30, 2021Three Months Ended September 30, 2020
Natural gas sales
Natural gas production volumes (MMcf)79,713 83,045 
Natural gas production volumes (MMcf/d)866 903 
Total sales$301,516 $155,163 
Average price without the impact of derivatives ($/Mcf)$3.78 $1.87 
Impact from settled derivatives ($/Mcf)$(1.04)$0.38 
Average price, including settled derivatives ($/Mcf)$2.74 $2.25 
Oil and condensate sales
Oil and condensate production volumes (MBbl)494 445 
Oil and condensate production volumes (MBbl/d)5 5 
Total sales$33,279 $16,012 
Average price without the impact of derivatives ($/Bbl)$67.37 $35.96 
Impact from settled derivatives ($/Bbl)$(8.77)$(3.38)
Average price, including settled derivatives ($/Bbl)$58.60 $32.58 
NGL sales
NGL production volumes (MBbl)1,144 924 
NGL production volumes (MBbl/d)12 10 
Total sales$45,153 $18,824 
Average price without the impact of derivatives ($/Bbl)$39.47 $20.37 
Impact from settled derivatives ($/Bbl)$(5.23)$— 
Average price, including settled derivatives ($/Bbl)$34.24 $20.37 
Natural gas, oil and condensate and NGL sales
Natural gas equivalents (MMcfe)89,542 91,262 
Natural gas equivalents (MMcfe/d)973 992 
Total sales$379,948 $189,999 
Average price without the impact of derivatives ($/Mcfe)$4.24 $2.08 
Impact from settled derivatives ($/Mcfe)$(1.04)$0.33 
Average price, including settled derivatives ($/Mcfe)$3.20 $2.41 
Production Costs:
Average lease operating expenses ($/Mcfe)$0.15 $0.15 
Average taxes other than income ($/Mcfe)$0.13 $0.07 
Average transportation, gathering, processing and compression ($/Mcfe)$0.94 $1.21 
Total lease operating expenses, midstream costs and taxes other than income ($/Mcfe)$1.22 $1.43 
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Natural Gas, Oil and NGL Sales
SuccessorPredecessor
Three Months Ended September 30, 2021Three Months Ended September 30, 2020
Natural gas$301,516 $155,163 
Oil and condensate33,279 16,012 
NGL45,153 18,824 
Natural gas, oil and NGL sales$379,948 $189,999 
The increase in natural gas sales without the impact of derivatives when comparing the Current Successor Quarter to the Prior Predecessor Quarter was due to a 102% increase in realized natural gas prices, partially offset by a 4% decrease in sales volumes. The realized price change was driven by the significant increase in the average Henry Hub gas index from $1.98 per Mcf in the Prior Predecessor Quarter to $4.01 per Mcf during the Current Successor Quarter.
The increase in oil and condensate sales without the impact of derivatives when comparing the Current Successor Quarter to the Prior Predecessor Quarter was due to an 87% increase in realized prices combined with an 11% increase in sales volumes. The realized price change was driven by the significant increase in the average WTI crude index from $40.77 per barrel in the Prior Predecessor Quarter to $70.56 per barrel during the Current Successor Quarter.
The increase in NGL sales without the impact of derivatives when comparing the Current Successor Quarter to the Prior Predecessor Quarter was due to a 94% increase in realized prices combined with a 24% increase in NGL sales volumes. The realized price change was driven by the significant increase in the average Mont Belvieu NGL index from $15.70 per barrel in the Prior Predecessor Quarter to $42.84 per barrel during the Current Successor Quarter.
Natural Gas, Oil and NGL Derivatives
SuccessorPredecessor
Three Months Ended September 30, 2021Three Months Ended September 30, 2020
Natural gas derivatives - fair value losses$(517,799)$(84,390)
Natural gas derivatives - settlement (losses) gains(82,566)31,742 
Total losses on natural gas derivatives(600,365)(52,648)
Oil and condensate derivatives - fair value (losses) gains(1,590)723 
Oil and condensate derivatives - settlement losses(4,336)(1,505)
Total losses on oil and condensate derivatives(5,926)(782)
NGL derivatives - fair value losses(10,201)(288)
NGL derivatives - settlement losses(5,984)(105)
Total losses on NGL derivatives(16,185)(393)
Total losses on natural gas, oil and NGL derivatives$(622,476)$(53,823)
We recognize fair value changes on our natural gas, oil and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationship between contract prices and the associated forward curves. The significant increase in losses compared to the Prior Predecessor Quarter result from the increase in both realized and futures pricing for oil, natural gas, and NGL. See Note 10 for hedged volumes and pricing.
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Lease Operating Expenses
SuccessorPredecessor
Three Months Ended September 30, 2021Three Months Ended September 30, 2020
Lease operating expenses
Utica$9,309 $10,284 
SCOOP4,527 3,226 
Other28 (117)
Total lease operating expenses$13,864 $13,393 
Lease operating expenses per Mcfe
Utica$0.14 $0.14 
SCOOP0.180.17
Other0.65(3.16)
Total lease operating expenses per Mcfe$0.15 $0.15 
LOE and LOE per Mcfe for the Current Successor Quarter were consistent compared to the Prior Predecessor Quarter.
Taxes Other Than Income
SuccessorPredecessor
Three Months Ended September 30, 2021Three Months Ended September 30, 2020
Production taxes$8,822 $4,028 
Property taxes2,3091,881
Other713193
Total taxes other than income$11,844 $6,102 
Total taxes other than income per Mcfe$0.13 $0.07 
The increase in total and per unit production taxes was primarily related to the significant increase in revenues and realized prices.
Transportation, Gathering, Processing and Compression
SuccessorPredecessor
Three Months Ended September 30, 2021Three Months Ended September 30, 2020
Transportation, gathering, processing and compression$84,435 $110,567 
Transportation, gathering, processing and compression per Mcfe$0.94 $1.21 
The decrease in total and per unit transportation, gathering, processing and compression was primarily related to savings associated with rejected midstream contracts and renegotiation through the bankruptcy process. Additionally, total costs decreased as a result of our 2% decrease in production.
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Depreciation, Depletion and Amortization
SuccessorPredecessor
Three Months Ended September 30, 2021Three Months Ended September 30, 2020
Depreciation, depletion and amortization of oil and gas properties$61,922 $49,120 
Depreciation, depletion and amortization of other property and equipment651 2,431 
Total Depreciation, depletion and amortization$62,573 $51,551 
Depreciation, depletion and amortization per Mcfe$0.70 $0.56 
The increase in depreciation, depletion and amortization of our oil and gas properties for the Current Successor Quarter compared to the Prior Predecessor Quarter is primarily the result of an increase in our depletion rate as a result of the fresh start valuations on our oil and gas properties. See Note 3 for more information on our fresh start valuation adjustments.
Impairment of Oil and Gas Properties
We did not record an impairment charge of our oil and gas properties during the Current Successor Quarter. We recorded a $270.9 million impairment charge of our oil and gas properties during the Prior Predecessor Quarter primarily as a result of the decline in the twelve month trailing first of month average price for natural gas, oil and NGLs.
General and Administrative Expenses
SuccessorPredecessor
Three Months Ended September 30, 2021Three Months Ended September 30, 2020
General and administrative expenses, gross$24,951 $29,171 
Reimbursed from third parties(3,182)(2,656)
Capitalized general and administrative expenses(5,078)(6,184)
General and administrative expenses, net$16,691 $20,331 
General and administrative expenses, net per Mcfe$0.19 $0.22 
The decrease in general and administrative expenses for the Current Successor Quarter compared to the Prior Predecessor Quarter was primarily driven by retention payments made in 2020 and our continued focus on the workforce and leadership structure to align to our current operating environment.
Restructuring and Liability Management
During the Current Successor Quarter and Prior Predecessor Quarter, we incurred restructuring charges related to reductions in workforce as we continued to align our workforce and leadership structure to our current operating environment. Additionally, during the Prior Predecessor Quarter, we incurred liability management charges related to legal advisors engaged to assist with the evaluation of a range of liability management alternatives prior to our ultimate Chapter 11 filing.
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The following table summarizes the restructuring and liability management charges incurred:
SuccessorPredecessor
Three months ended September 30, 2021Three months ended September 30, 2020
Reduction in workforce$2,858 $1,460 
Liability management— 7,524 
Total restructuring and liability management$2,858 $8,984 
Interest Expense
 SuccessorPredecessor
Three Months Ended September 30, 2021Three Months Ended September 30, 2020
Interest expense on Predecessor Senior Notes$— $28,134 
Interest expense on Pre-Petition Revolving Credit Facility— 4,280 
Interest expense on building loan and other(60)459 
Capitalized interest(117)(196)
Amortization of loan costs594 1,644 
Interest on DIP Credit Facility— — 
Interest on Exit Facility2,458 — 
Interest on First-Out Term Loan2,427 — 
Interest on Successor Senior Notes11,049 — 
Total interest expense$16,351 $34,321 
Interest expense per Mcfe$0.18 $0.38 
The decrease in interest expense when comparing the Current Successor Quarter to the Prior Predecessor Quarter was due the changes in our debt structure upon emergence from Chapter 11. See Note 5 for more information on our Exit Facility.
Income Taxes

The income tax expense of $0.7 million that was recognized for the Current Successor Quarter is a result of an Oklahoma refund claim that was filed during the third quarter of 2021, resulting in an adjustment to the benefit recorded during the Current Predecessor YTD Period. We did not record any income tax expense for the Prior Predecessor Quarter as a result of maintaining a full valuation allowance against our net deferred tax asset.
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Current Successor YTD Period and Current Predecessor YTD Period Compared to 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 Current Successor YTD Period, Current Predecessor YTD Period and the Current Combined YTD Period, as compared to such data for the Prior Predecessor YTD Period:
 SuccessorPredecessorNon-GAAP CombinedPredecessor
Period from May 18, 2021 through September 30, 2021Period from January 1, 2021 through May 17, 2021Nine Months Ended September 30, 2021Nine Months Ended September 30, 2020
Natural gas sales
Natural gas production volumes (MMcf)118,720 124,279 242,999 254,092 
Natural gas production volumes (MMcf/d)873 907 890 927 
Total sales$413,234 $344,390 $757,624 $456,859 
Average price without the impact of derivatives ($/Mcf)$3.48 $2.77 $3.12 $1.80 
Impact from settled derivatives ($/Mcf)$(0.75)$(0.03)$(0.38)$0.69 
Average price, including settled derivatives ($/Mcf)$2.73 $2.74 $2.74 $2.49 
Oil and condensate sales
Oil and condensate production volumes (MBbl)759 531 1,290 1,394 
Oil and condensate production volumes (MBbl/d)6 4 5 5 
Total sales$50,866 $29,106 $79,972 $47,553 
Average price without the impact of derivatives ($/Bbl)$67.02 $54.81 $61.99 $34.12 
Impact from settled derivatives ($/Bbl)$(5.71)$— $(3.36)$34.76 
Average price, including settled derivatives ($/Bbl)$61.31 $54.81 $58.63 $68.88 
NGL sales
NGL production volumes (MBbl)1,664 1,211 2,875 3,028 
NGL production volumes (MBbl/d)12 9 11 11 
Total sales$61,230 $36,780 $98,010 $45,989 
Average price without the impact of derivatives ($/Bbl)$36.80 $30.37 $34.09 $15.19 
Impact from settled derivatives ($/Bbl)$(3.60)$— $(2.08)$— 
Average price, including settled derivatives ($/Bbl)$33.20 $30.37 $32.01 $15.19 
Natural gas, oil and condensate and NGL sales
Natural gas equivalents (MMcfe)133,257 134,735 267,992 280,621 
Natural gas equivalents (MMcfe/d)980 983 982 1,024 
Total sales$525,330 $410,276 $935,606 $550,401 
Average price without the impact of derivatives ($/Mcfe)$3.94 $3.05 $3.49 $1.96 
Impact from settled derivatives ($/Mcfe)$(0.75)$(0.02)$(0.38)$0.80 
Average price, including settled derivatives ($/Mcfe)$3.19 $3.03 $3.11 $2.76 
Production Costs:
Average lease operating expenses ($/Mcfe)$0.13 $0.14 $0.14 $0.15 
Average taxes other than income ($/Mcfe)$0.13 $0.09 $0.11 $0.07 
Average transportation, gathering, processing and compression ($/Mcfe)$0.94 $1.20 $1.07 $1.19 
Total lease operating expenses, midstream costs and taxes other than income ($/Mcfe)$1.20 $1.43 $1.32 $1.41 
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Natural Gas, Oil and NGL Sales
SuccessorPredecessorNon-GAAP CombinedPredecessor
Period from May 18, 2021 through September 30, 2021Period from January 1, 2021 through May 17, 2021Nine Months Ended September 30, 2021Nine Months Ended September 30, 2020
Natural gas$413,234 $344,390 $757,624 $456,859 
Oil and condensate50,866 29,106 79,972 47,553 
NGL61,230 36,780 98,010 45,989 
Natural gas, oil and NGL sales$525,330 $410,276 $935,606 $550,401 
The increase in natural gas sales without the impact of derivatives was due to a 73% increase in realized natural gas prices partially offset by a 4% decrease in sales volumes. The realized price change was driven by the significant increase in the average Henry Hub gas index from $1.88 per Mcf in the Prior Predecessor YTD Period to $3.18 per Mcf during the Current Combined YTD Period.
The increase in oil and condensate sales without the impact of derivatives was due to a 82% increase in realized prices and partially offset by a 7% decrease in sales volumes. The realized price change was driven by the significant increase in the average WTI crude index from $38.23 per barrel in the Prior Predecessor YTD Period to $64.82 per barrel during the Current Combined YTD Period.
The increase in NGL sales without the impact of derivatives was due to a 124% increase in realized prices partially offset by an 5% decrease in NGL sales volumes. The realized price change was driven by the significant increase in the average Mont Belvieu NGL index from $15.04 per barrel in the Prior Predecessor YTD Period to $35.76 per barrel during the Current Combined YTD Period.
Natural Gas, Oil and NGL Derivatives
SuccessorPredecessorNon-GAAP CombinedPredecessor
Period from May 18, 2021 through September 30, 2021Period from January 1, 2021 through May 17, 2021Nine Months Ended September 30, 2021Nine Months Ended September 30, 2020
Natural gas derivatives - fair value losses$(638,063)$(123,080)$(761,143)$(147,661)
Natural gas derivatives - settlement (losses) gains(89,255)(3,362)(92,617)176,555 
Total (losses) gains on natural gas derivatives(727,318)(126,442)(853,760)28,894 
Oil and condensate derivatives - fair value losses(6,947)(6,126)(13,073)(4,289)
Oil and condensate derivatives - settlement (losses) gains(4,336)— (4,336)48,444 
Total (losses) gains on oil and condensate derivatives(11,283)(6,126)(17,409)44,155 
NGL derivatives - fair value losses(17,549)(4,671)(22,220)(620)
NGL derivatives - settlement (losses) gains(5,984)— (5,984)366 
Total losses on NGL derivatives(23,533)(4,671)(28,204)(254)
Contingent consideration arrangement - fair value losses— — — (1,381)
Total (losses) gains on natural gas, oil and NGL derivatives$(762,134)$(137,239)$(899,373)$71,414 
We recognize fair value changes on our natural gas, oil and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationship between contract prices and the associated forward curves. The significant increase in fair value losses is the result of a significant increase in futures pricing for oil, natural gas, and NGL at September 30, 2021. See Note 10 for hedged volumes and pricing.
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Lease Operating Expenses
SuccessorPredecessorNon-GAAP CombinedPredecessor
Period from May 18, 2021 through September 30, 2021Period from January 1, 2021 through May 17, 2021Nine Months Ended September 30, 2021Nine Months Ended September 30, 2020
Lease operating expenses
Utica$12,162 $13,991 $26,153 $30,572 
SCOOP5,757 5,449 11,206 10,539 
Other61 84 145 55 
Total lease operating expenses$17,980 $19,524 $37,504 $41,166 
Lease operating expenses per Mcfe
Utica$0.13$0.13$0.13$0.14
SCOOP0.150.220.180.17
Other0.902.151.360.41
Total lease operating expenses per Mcfe$0.13$0.14$0.14$0.15
The decrease in total LOE during the Current Combined YTD Period compared to the Prior Predecessor YTD Period 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 September 30, 2021Period from January 1, 2021 through May 17, 2021Nine Months Ended September 30, 2021Nine Months Ended September 30, 2020
Production taxes$12,561 $8,459 $21,020 $12,432 
Property taxes3,3772,5905,9675,743
Other9621,3002,262864
Total taxes other than income$16,900 $12,349 $29,249 $19,039 
Total taxes other than income per Mcfe$0.13 $0.09 $0.11 $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 September 30, 2021Period from January 1, 2021 through May 17, 2021Nine Months Ended September 30, 2021Nine Months Ended September 30, 2020
Transportation, gathering, processing and compression$125,811 $161,086 $286,897 $334,789 
Transportation, gathering, processing and compression per Mcfe$0.94 $1.20 $1.07 $1.19 
The decrease in transportation, gathering, processing and compression was primarily related to savings associated with rejected midstream contracts and renegotiation through the bankruptcy process. Additionally, total costs decreased as a result of our 4% decrease in production.
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Depreciation, Depletion and Amortization
SuccessorPredecessor
Period from May 18, 2021 through September 30, 2021Period from January 1, 2021 through May 17, 2021Nine Months Ended September 30, 2020
Depreciation, depletion and amortization of oil and gas properties$93,959 $60,831 $186,693 
Depreciation, depletion and amortization of other property and equipment$976 $1,933 $7,676 
Total Depreciation, depletion and amortization$94,935 $62,764 $194,369 
Depreciation, depletion and amortization per Mcfe$0.71 $0.47 $0.69 
The decrease in depreciation, depletion and amortization of our oil and gas properties for the Current Combined YTD Period compared to the Prior Predecessor YTD Period is primarily the result of impairments taken in 2020 which decreased the depletion rate, partially offset by an increase in the depletion rate for the Current Successor YTD Period as a result of the fresh start valuations on our oil and gas properties. See Note 3 for more information on fresh start adjustments.
Impairment of Oil and Gas Properties
We incurred a $117.8 million impairment charge of oil and gas properties during the Current Combined YTD Period. We recorded $1.4 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 for the calculation performed at the end of the second quarter of 2021, which led to the Current Combined YTD Period impairment charge.
Impairment of Other Property and Equipment
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 September 30, 2021Period from January 1, 2021 through May 17, 2021Nine Months Ended September 30, 2021Nine Months Ended September 30, 2020
General and administrative expenses, gross$34,818 $32,152 $66,970 $74,226 
Reimbursed from third parties(4,355)(4,957)(9,312)(8,731)
Capitalized general and administrative expenses(7,254)(8,020)(15,274)(19,776)
General and administrative expenses, net$23,209 $19,175 $42,384 $45,719 
General and administrative expenses, net per Mcfe$0.17 $0.14 $0.16 $0.16 
The decrease in total general and administrative expenses during the Current Combined YTD Period compared to the Prior Predecessor YTD Period was primarily driven by retention payments made in 2020 and our continued focus on workforce and leadership structure to align to our current operating environment.
Restructuring and Liability Management
During the Current Successor YTD Period and the Prior Predecessor YTD Period, we incurred restructuring charges related to reductions in workforce as we continued to align our workforce and leadership structure to our current operating environment. Additionally, during the Prior Predecessor YTD Period, we incurred liability management charges related to
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legal advisors engaged to assist with the evaluation of a range of liability management alternatives prior to our ultimate Chapter 11 filing. The following table summarizes the restructuring and liability management charges incurred:
SuccessorPredecessor
Period from May 18, 2021 through September 30, 2021Period from January 1, 2021 through May 17, 2021Nine months ended September 30, 2020
Reduction in workforce$2,858 $— $1,460 
Liability management— — 8,141 
Total restructuring and liability management$2,858 $— $9,601 
Interest Expense
 SuccessorPredecessor
Period from May 18, 2021 through September 30, 2021Period from January 1, 2021 through May 17, 2021Nine Months Ended September 30, 2020
Interest expense on Predecessor Senior Notes$— $— $85,433 
Interest expense on Pre-Petition Revolving Credit Facility— 2,044 9,305 
Interest expense on building loan and other556 (989)1,110 
Capitalized interest(117)— (907)
Amortization of loan costs1,014 — 4,736 
Interest on DIP Credit Facility— 3,104 — 
Interest on Exit Facility3,824 — — 
Interest on First-Out Term Loan3,664 — — 
Interest on Successor Senior Notes16,304 — — 
Total interest expense$25,245 $4,159 $99,677 
Interest expense per Mcfe$0.19 $0.03 $0.36 
The decrease in interest expense during the Current Combined YTD Period compared to the Prior Predecessor YTD Period was due the changes in our debt structure upon emergence from Chapter 11.
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 $49.6 million gain on debt extinguishment. We did not repurchase any of our senior notes in the Current Combined YTD Period.
Equity Investments
SuccessorPredecessorNon-GAAP CombinedPredecessor
Period from May 18, 2021 through September 30, 2021Period from January 1, 2021 through May 17, 2021Nine Months Ended September 30, 2021Nine Months Ended September 30, 2020
Loss from equity method investments, net$— $342 $342 $10,987 
During the Prior Predecessor YTD Period, our share of net loss from Mammoth was in excess of the carrying value of our investment, which reduced our investment to zero. Our carrying value remained at zero through the Current Predecessor YTD Period until the use of Mammoth Shares to settle Class 4A claims at the Emergence Date. See Note 13 to our consolidated financial statements for further discussion on our equity investments.
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Reorganization Items, Net.
The following table summarizes the components in reorganization items, net included in our consolidated statements of operations for the Current Successor YTD Period and Current Predecessor YTD Period ended September 30, 2021:
SuccessorPredecessor
Period from May 18, 2021 through September 30, 2021Period from January 1, 2021 through May 17, 2021
Legal and professional advisory fees$— $(81,565)
Net gain on liabilities subject to compromise— 575,182 
Fresh start adjustments, net— (160,756)
Elimination of predecessor accumulated other comprehensive income— (40,430)
Debt issuance costs— (3,150)
Other items, net— (22,383)
Reorganization items, net$— $266,898 
See Note 3 for further discussion of the components of reorganization items, net.
Income Taxes
We recorded an income tax benefit of $7.3 million during the Current Combined YTD Period as a result of an Oklahoma refund claim associated with an examination relating to historical tax returns that was filed in the third quarter of 2021. For the Prior Predecessor YTD Period, we had an effective tax rate of (0.5)% 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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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 and any debt or 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 Current Successor YTD 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 credit agreements and issuances of equity and debt securities. Our ability to issue additional indebtedness, dispose of assets or access the capital markets was substantially limited or nonexistent during the Chapter 11 Cases and required court approval in most instances. Accordingly, our liquidity in the Predecessor 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 New Credit Facility and cash on hand will provide sufficient liquidity to fund our operations, capital expenditures, interest expense, debt repayments and any return of capital to shareholders, if declared by the Board, during the next 12 months.
To the extent actual operating results, realized commodity prices or uses of cash differ from our assumptions, our liquidity could be adversely affected. 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.
As of September 30, 2021, we had $4.5 million of cash and cash equivalents, $35.6 million of borrowings under our Exit Facility, $165.0 million of borrowings under our First-Out Term Loan, $115.5 million of letters of credit outstanding, and $550 million of outstanding 2026 Notes. Our total principal amount of funded debt as of September 30, 2021 was $750.6 million.
As of October 28, 2021, after giving effect to the New Credit Facility, we had $6.2 million of cash and cash equivalents, $246.0 million of borrowings under our New Credit Facility, $97.1 million of letters of credit outstanding, and $550 million of outstanding 2026 Notes. The increase in borrowings since September 30, 2021 was primarily due to the $43.8 million payment made to TC pursuant to the settlement agreement as discussed in Note 9.
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 featured an initial borrowing base of $580.0 million. The Exit Credit Facility consisted of the Exit Facility and the First-Out Term Loan. Subsequent to the end of the third quarter of 2021, we amended and refinanced the Exit Credit Facility with the New Credit Facility.
As discussed in Note 17, on October 14, 2021, we entered into the Third Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A., as administrative agent, and various lender parties. The New Credit Facility provides for an aggregate maximum principal amount of up to $1.5 billion, an initial borrowing base of $850.0 million and an initial aggregate elected commitment amount of $700.0 million. The credit agreement also provides for a $175.0 million sublimit of the aggregate commitments that is available for the issuance of letters of credit.
The Exit Facility provided for a $150.0 million sublimit of the aggregate commitments that is available for the issuance of letters of credit. The Exit Facility also included 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 bore 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 bore 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 September 30, 2021, the Exit Facility and the First-Out Term Loan 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.
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The Successor Senior Notes are guaranteed on a senior unsecured basis by each of the Company's subsidiaries that guarantee the Exit Credit Facility as well as the New Credit Facility effective October 14, 2021.
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 under the New Credit Facility.
On September 30, 2021, the company paid a PIK dividend on its New Preferred Stock, which included 2,065 shares of New Preferred Stock paid in kind and approximately $30 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 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. See Item 3. Quantitative and Qualitative Disclosures About Market Risk included in Item 1 of this report for further discussion on the impact of commodity price risk on our financial position. Additionally, see Note 10 of the notes to our consolidated financial statements for further discussion of derivatives and hedging activities.
Capital Expenditures. Our capital expenditures have historically been related to the execution of our drilling and 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.
Our capital expenditures for 2021 are currently estimated to be in the range of $270 million to $290 million for drilling and completion expenditures. In addition, we currently expect to spend approximately $20 million in 2021 for non-drilling and completion expenditures, which includes acreage expenses, primarily lease extensions in the Utica Shale.
Proceeds from Issuance of New Preferred Stock. On the Emergence Date, pursuant to the Plan, we 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.
Cash Flow from Operating Activities. Net cash flow provided by operating activities was $164.6 million for the Current Successor YTD Period and $172.2 million for the Current Predecessor YTD Period as compared to $200.0 million for the Prior
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Predecessor YTD Period. The increase was primarily the result of an increase in cash receipts from our oil and natural gas purchasers due to increased realized commodities pricing, partially offset by reorganization items related to our Chapter 11 Cases.
Uses of Funds. The following table presents the uses of our cash and cash equivalents for the Current Successor YTD Period, Current Predecessor YTD Period, and the Prior Predecessor YTD Period:
SuccessorPredecessor
Period from May 18, 2021 through September 30, 2021Period from January 1, 2021 through May 17, 2021Nine Months Ended September 30, 2020
Oil and Natural Gas Property Cash Expenditures:
Drilling and completion costs$109,077 $94,128 $299,896 
Leasehold acquisitions3,474 2,752 18,449 
Other6,755 5,450 19,634 
Total oil and natural gas property expenditures$119,306 $102,330 $337,979 
Other Uses of Cash and Cash Equivalents
Principal payments on Pre-Petition Revolving Credit Facility, net$— $292,911 $— 
Principal payments on DIP credit facility— 157,500 — 
Principal payments on Exit Credit Facility, net102,145 — — 
Cash paid to repurchase senior notes— — 22,827 
Other1,357 7,497 1,459 
Total other uses of cash and cash equivalents$103,502 $457,908 $24,286 
Total uses of cash and cash equivalents$222,808 $560,238 $362,265 
Drilling and Completion Costs. During the Current Combined YTD Period, we spud 12 gross (11.6 net) and commenced sales from 11 gross and net operated wells in the Utica for a total cost of approximately $152.2 million. During the Current Combined YTD Period, we spud four gross (3.9 net) and commenced sales from 11 gross (9.3 net) operated wells in the SCOOP for a total cost of approximately $65.8 million.
During the Current Combined YTD Period, we did not participate in any wells that were spud or turned to sales by other operators on our Utica acreage. In addition, 15 gross (1.6 net) wells were spud and 21 gross (0.05 net) wells were turned to sales by other operators on our SCOOP acreage during the 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.
Share Repurchase Program
On November 1, 2021, our board of directors has approved a stock Repurchase Program to acquire up to $100.0 million of our outstanding New Common Stock. Purchases under the Repurchase Program may be made from time to time in open market or privately negotiated transactions, and will be subject to available liquidity, market conditions, credit agreement restrictions, applicable legal requirements, contractual obligations and other factors. The Repurchase Program does not require us to acquire any specific number of shares of New Common Stock. We intend to purchase shares under the Repurchase Program opportunistically with available funds while maintaining sufficient liquidity to fund our capital development program. The Repurchase Program is authorized to extend through December 31, 2022 and may be suspended from time to time, modified, extended or discontinued by the board of directors at any time. Any shares of New Common Stock repurchased are expected to be cancelled.
Contractual and Commercial Obligations
We have various contractual obligations in the normal course of our operations and financing activities. See Note 3 for discussion of changes in contractual obligations as a result of emergence from bankruptcy. See Note 9 of the notes to our consolidated financial statements for discussion of changes to our firm transportation and gathering agreements subsequent to
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the 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, 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 September 30, 2021, our material off-balance sheet arrangements and transactions include $115.5 million in letters of credit outstanding against our Exit Facility and $90.1 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. There are no other transactions, arrangements or other relationships with the unauditedunconsolidated entities or other persons that are reasonably likely to 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 related notes thereto presentedEstimates
As of September 30, 2021, there have been no significant changes in this Quarterlyour critical accounting policies from those disclosed in our 2020 Annual Report on Form 10-Q.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 such things as the potential effects of the Chapter 11 Cases on our operations, management, and employees, our ability to consummate the restructuring, our ability to continue as a going concern, 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), share repurchases, 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.
Investors should note that we announce financial information in SEC filings. 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.
Overview
We are an independent natural gas-weighted exploration and production company focused on the exploration, acquisition and production of natural gas, crude oil and NGL in the United States with primary focus in the Appalachia and Anadarko
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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.
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 are being administered jointly under the caption In re Gulfport Energy Corporation, et al., Case No. 20-35562 (DRJ). We continue to operate our businesses as "debtors-in-possession" under the jurisdiction of the Bankruptcy Court, in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court.

The Bankruptcy Court has granted first- and second-day motions filed by us that were designed primarily to mitigate the impact of the Chapter 11 Cases on our operations, customers and employees. As a result, we are able to conduct normal business activities and pay all associated obligations for the period following the Bankruptcy Filing and are authorized to pay owner royalties, employee wages and benefits and certain vendors and suppliers in the ordinary course for goods and services provided. During the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of business require the prior approval of the Bankruptcy Court.

For the duration of the Chapter 11 Cases, our operations and ability to develop and execute our business plan are subject to the risks and uncertainties associated with the Chapter 11 process as described in "Risk Factors" in Item 1A. of our Annual Report on Form 10-K for the year ended December 31, 2020. As a result of these risks and uncertainties, the number of our shares of common stock and stockholders, assets, liabilities, officers and/or directors could be significantly different following the outcome of the Chapter 11 Cases, and the description of our operations, properties and capital plans included in this Form 10-Q may not accurately reflect our operations, properties and capital plans following the Chapter 11 Cases.

During the Chapter 11 Cases, we expect our financial results to continue to be volatile as restructuring activities and expenses, contract terminations and rejections and claims assessments significantly impact our consolidated financial statements. As a result, our historical financial performance is likely not indicative of our financial performance after the date of the Bankruptcy Filing. In addition, we have incurred significant professional fees and other costs in connection with the Chapter 11 Cases and expect that we will continue to incur significant professional fees and costs throughout our Chapter 11 Cases until emergence.

See Note 2 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for a complete discussion of the Chapter 11 Cases.

Delisting of our Common Stock from Nasdaq

On November 27, 2020, our common stock was suspended from trading on NASDAQ. On November 30, 2020, our common stock began trading on the OTC Pink Marketplace maintained by the OTC Markets Group, Inc. under the symbol “GPORQ". On February 2, 2021, NASDAQ filed a Form 25 delisting our common stock from trading on NASDAQ, which delisting became effective 10 days after the filing of the Form 25. In accordance with Rule 12d2-2 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), the de-registration of our common stock under section 12(b) of the Exchange Act became effective on February 12, 2021.

COVID-19 Pandemic and Impact on Global Demand for Oil and Natural Gas

As a result of our business continuity measures, we have not experienced significant disruptions in executing our business operations due to COVID-19. While we did not experience significant disruptions to our operations in the first quarter 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. Restrictions 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. Additionally, 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.
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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 and the timing and extent to which normal economic and operating conditions resume. While we have seen meaningful recovery in demand during the second half 2020 and into 2021, significant uncertainty remains regarding the duration and extent of the impact of the pandemic on the energy industry, including demand and commodities pricing, although we expect to see further recovery as vaccines are distributed and more normal societal activity resumes.
2021 Operational and Financial Highlights
During the three months ended March 31, 2021, we had the following notable achievements:
•An order was entered to confirm our Plan by the Bankruptcy Court on April 28, 2021. We expect to emerge from Chapter 11 proceedings and complete our financial restructuring in May 2021.
•We continued to improve operational efficiencies and reduce drilling and completion costs in our operating areas. In the Utica, our average spud to rig release time was 17.0 days in the first quarter of 2021, which was a 9% improvement from full year 2020 levels.
•We have continued to decrease costs as a result of our ongoing cost reduction initiatives highlighted by a 7% decrease in lease operating expenses per Mcfe and a 13% decrease in general and administrative expenses per Mcfe for the first quarter of 2021 as compared to the first quarter of 2020.


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2021 Production and Drilling Activity
Production Volumes
Three months ended March 31,
2021% of Total2020% of TotalChange% Change
Natural gas (Mcf/day)
Utica797,452 88 %785,781 83 %11,671 1 %
SCOOP111,708 12 %159,886 17 %(48,178)(30)%
Other80 — %39 — %41 105 %
Total909,240 945,706 (36,466)(5)%
Oil and condensate (Bbl/day)
Utica1,403 37 %592 10 %811 137 %
SCOOP2,379 62 %5,174 89 %(2,795)(54)%
Other40 1 %78 1 %(38)(49)%
Total3,822 5,844 (2,022)(35)%
NGL (Bbl/day)
Utica2,665 32 %3,197 26 %(532)(17)%
SCOOP5,758 68 %8,974 74 %(3,216)(36)%
Other4 — %— — %4 100 %
Total8,427 12,171 (3,744)(31)%
Combined (Mcfe/day)
Utica821,858 84 %808,520 77 %13,338 2 %
SCOOP160,528 16 %244,771 23 %(84,243)(34)%
Other343 — %508 — %(165)(32)%
Total982,729 1,053,799 (71,070)(7)%
Our total net production averaged approximately 982.7 MMcfe per day during the three months ended March 31, 2021, as compared to 1,053.8 MMcfe per day during the same period in 2020. The 7% decrease in production is largely the result of a decrease in development activities in the SCOOP throughout 2020.
Utica. From January 1, 2021 through March 31, 2021, we spud nine gross (nine net) wells in the Utica, of which five were being drilled and four were in various stages of operations at March 31, 2021. In addition, we completed seven gross and net operated wells. We did not participate in any additional wells that were drilled by other operators on our Utica acreage.
As of April 30, 2021, we had two operated drilling rigs running in the Utica, both of which we expect to release in May 2021. We expect to add back one operated drilling rig in the Utica in the third quarter of 2021.
SCOOP. From January 1, 2021 through March 31, 2021, we did not spud any wells in the SCOOP. We completed three gross (2.69 net) operated wells. We also participated in an additional three gross wells that were drilled by other operators on our SCOOP acreage.
As of April 30, 2021, we had one operated drilling rig running in the SCOOP, which we expect will continue through the remainder of 2021.
RESULTS OF OPERATIONS
Comparison of the Three Month Periods Ended March 31, 2021 and 2020
We reported a net income of $8.8 million for the three months ended March 31, 2021 as compared to net loss of $517.5 million for the three months ended March 31, 2020. The graph below shows the change in the net income (loss) from the three
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months ended March 31, 2020 to the three months ended March 31, 2021. The material changes are further discussed by category on the following pages. Some totals and changes throughout below section may not sum or recalculate due to rounding.
gpor-20210331_g1.jpg
(1) Includes lease operating expenses, taxes other than income and transportation, gathering, processing and compression.
Natural Gas, Oil and NGL Sales
Three months ended March 31,
20212020change
($ In thousands)
Natural gas$235,321 $161,008 46 %
Oil and condensate18,239 23,151 (21)%
NGL23,776 16,913 41 %
Natural gas, oil and NGL sales$277,336 $201,072 38 %
The increase in natural gas sales without the impact of derivatives was due to a 54% increase in realized natural gas prices partially offset by a 5% decrease in sales volumes.
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The decrease in oil and condensate sales without the impact of derivatives was due to a 35% decrease in oil and condensate sales volumes partially offset by a 22% increase in realized oil and condensate prices.
The increase in NGL sales without the impact of derivatives was due to a 105% increase in realized prices partially offset by a 31% decrease in NGL sales volumes.
Natural Gas, Oil and NGL Derivatives
Three months ended March 31,
20212020
($ In thousands)
Natural gas derivatives - fair value losses$(25,538)$(15,125)
Natural gas derivatives - settlement gains125 60,978 
Total (losses) gains on natural gas derivatives(25,413)45,853 
Oil and condensate derivatives - fair value (losses) gains(1,731)43,374 
Oil and condensate derivatives - settlement gains— 9,500 
Total (losses) gains on oil and condensate derivatives(1,731)52,874 
NGL derivatives - fair value (losses) gains(2,834)665 
NGL derivatives - settlement gains— 255 
Total (losses) gains on NGL derivatives(2,834)920 
Contingent consideration arrangement - fair value losses— (1,381)
Total (losses) gains on natural gas, oil and NGL derivatives$(29,978)$98,266 
See Note 9 to our consolidated financial statements for further discussion of our derivative activity.
Natural Gas, Oil and NGL Production and Pricing
The following table summarizes our oil and condensate, natural gas and NGL production and related pricing for the three months ended March 31, 2021, as compared to such data for the three months ended March 31, 2020:
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 Three months ended March 31,
 20212020
($ In thousands)
Natural gas sales
Natural gas production volumes (MMcf)81,832 86,059 
Natural gas production volumes (MMcf) per day909 946 
Total sales235,321 161,008 
Average price without the impact of derivatives ($/Mcf)2.88 1.87 
Impact from settled derivatives ($/Mcf)— 0.71 
Average price, including settled derivatives ($/Mcf)2.88 2.58 
Oil and condensate sales
Oil and condensate production volumes (MBbl)344 532 
Oil and condensate production volumes (MBbl) per day4 6 
Total sales18,239 23,151 
Average price without the impact of derivatives ($/Bbl)53.03 43.53 
Impact from settled derivatives ($/Bbl)— 17.86 
Average price, including settled derivatives ($/Bbl)53.03 61.39 
NGL sales
NGL production volumes (MBbl)758 1,108 
NGL production volumes (MBbl) per day8 12 
Total sales23,776 16,913 
Average price without the impact of derivatives ($/Bbl)31.35 15.27 
Impact from settled derivatives ($/Bbl)— — 
Average price, including settled derivatives ($/Bbl)31.35 15.27 
Natural gas, oil and condensate and NGL sales
Natural gas equivalents (MMcfe)88,446 95,896 
Natural gas equivalents (MMcfe) per day983 1,054 
Total sales277,336 201,072 
Average price without the impact of derivatives ($/Mcfe)3.14 2.10 
Impact from settled derivatives ($/Mcfe)— 0.74 
Average price, including settled derivatives ($/Mcfe)3.14 2.84 
Production Costs:
Average lease operating expenses ($/Mcfe)$0.14 $0.15 
Average production taxes ($/Mcfe)$0.07 $0.05 
Average transportation, gathering, processing and compression ($/Mcfe)$1.20 $1.15 
Total lease operating expenses, midstream costs and production taxes ($/Mcfe)$1.41 $1.35 
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Lease Operating Expenses
Three months ended March 31,
20212020change
($ In thousands, except per unit)
Lease operating expenses
Utica$9,222 $9,898 (7)%
SCOOP3,357 4,765 (30)%
Other(1)
74 32 131 %
Total lease operating expenses$12,653 $14,695 (14)%
Lease operating expenses per Mcfe
Utica$0.12 $0.13 (7)%
SCOOP0.23 0.21 9 %
Other(1)
2.41 0.69 251 %
Total lease operating expenses per Mcfe$0.14 $0.15 (7)%
 _____________________
(1)    Includes Niobrara and Bakken.
The decrease in total LOE was primarily the result of a 7% decrease in production as well as ongoing cost reduction initiatives. The decrease in per unit LOE is primarily the result of ongoing cost reduction initiatives.
Taxes Other Than Income
Three months ended March 31,
20212020change
($ In thousands, except per unit)
Production taxes$5,803 $4,799 21 %
Property taxes1,912 1,282 49 %
Other989 556 78 %
Total taxes other than income$8,704 $6,637 31 %
Production taxes per Mcfe$0.07 $0.05 40 %
The increase in total and per unit production taxes was primarily related to an increase in revenues due to an increase in realized prices.
Transportation, Gathering, Processing and Compression
Three months ended March 31,
20212020change
($ In thousands, except per unit)
Transportation, gathering, processing and compression$105,867 $110,357 (4)%
Transportation, gathering, processing and compression per Mcfe$1.20 $1.15 4 %
The decrease in transportation, gathering, processing and compression was primarily related to a 7% decrease in our production. The increase in per unit transportation, gathering, processing and compression is primarily related to Utica
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production volumes falling below our minimum volume commitments on certain firm transportation and gathering contracts during the three months ended March 31, 2021.
Depreciation, Depletion and Amortization
Three months ended March 31,
20212020change
($ In thousands, except per unit)
Depreciation, depletion and amortization of oil and gas properties$39,767 $75,359 (47)%
Depreciation, depletion and amortization of other property and equipment$1,380 $2,669 (48)%
Total Depreciation, depletion and amortization$41,147 $78,028 (47)%
Depreciation, depletion and amortization per Mcfe$0.47 $0.81 (42)%
The decrease in DD&A of oil and gas properties 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 throughout 2020, as well as a decrease in our production.
Impairment of Oil and Gas Properties
We did not incur an oil and natural gas properties impairment charge during the three months ended March 31, 2021 while we recorded a $553.3 million impairment charge of oil and gas properties during the three months ended March 31, 2020. No impairment was required during the Current Quarter primarily due to the combination of improved commodity prices and a decrease in the net book value of our oil and gas properties stemming from impairment charges in 2020.
Impairment of Other Property and Equipment
We recognized a $14.6 million impairment charge on the Company's corporate headquarters during the three months ended March 31, 2021 as a result in a change in expected future use.
General and Administrative Expenses
Three months ended March 31,
20212020change
($ In thousands, except per unit)
General and administrative expenses, gross$21,317 $24,105 (12)%
Reimbursed from third parties$(3,039)$(3,052)— %
Capitalized general and administrative expenses$(5,521)$(5,431)2 %
General and administrative expenses, net$12,757 $15,622 (18)%
General and administrative expenses, net per Mcfe$0.14 $0.16 (13)%
The decrease in general and administrative expenses on a total and per unit basis was primarily driven by our continued focus on reducing costs across our organization and lower non-recurring legal and consulting expenses.
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Interest Expense
Three months ended March 31,
 20212020
($ In thousands, except per unit)
Interest expense on senior notes$— $29,119 
Interest expense on pre-petition revolving credit facility1,020 2,165 
Interest expense on building loan and other75 340 
Capitalized interest— (187)
Amortization of loan costs— 1,553 
Interest on DIP credit facility2,166 — 
Total interest expense$3,261 $32,990 
Interest expense per Mcfe$0.04 $0.34 
Weighted average debt outstanding under revolving credit facility$307,208 $81,978 
The decrease of total and per unit interest expense was due to the cessation of interest accrual on borrowings classified as subject to compromise as of the petition date.
Gain on Debt Extinguishment.
In July of 2019, our Board of Directors authorized $100 million of cash to be used to repurchase its senior notes in the open market at discounted values to par. In December 2019, our Board of Directors increased the authorized size of the senior note repurchase program to $200 million in total. During the three months ended March 31, 2020, we repurchased in the open market $25.9 million aggregate principal amount of our outstanding Senior Notes for $10.2 million in cash and recognized a $15.3 million gain on debt extinguishment. We did not repurchase any of our Senior Notes in the three months ended March 31, 2021.
Equity Investments
Three months ended March 31,
20212020change
($ In thousands, except per unit)
Loss from equity method investments, net$342 $10,789 (97)%
During the three months ended March 31, 2020, our share of net loss from Mammoth was in excess of the carrying value of our investment, which reduced our investment to zero. Our carrying value has remained at zero as of March 31, 2021 and thus no additional net loss or income was recorded . See Note 4 to our consolidated financial statements for further discussion on our equity investments.
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Reorganization Items, Net.
The following table summarizes the components in reorganization items, net included in our consolidated statements of operations for the three months ended March 31, 2021:
Three months ended March 31, 2021
(in thousands)
Adjustment to allowed claims$2,088 
Legal and professional fees40,783 
Gain on settlement of pre-petition accounts payable(4,150)
Reorganization items, net$38,721 
We have incurred and will continue to incur additional gains and losses associated with our reorganization, primarily related to legal and professional fees related to our ongoing Chapter 11 cases.
Income Taxes
We recorded no income tax expense for the three months ended March 31, 2021 as a result of maintaining a full valuation allowance of $911.4 million against our net deferred tax asset. We recorded income tax expense of $7.3 million for the three months ended March 31, 2020 as a result of the recognition of a valuation allowance against a state deferred tax asset.
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Liquidity and Capital Resources
Overview. Historically, our primary sources of capital funding and liquidity have been our operating cash flow, borrowings under our Pre-Petition Revolving Credit Facility and issuances of equity and debt securities. Our ability to issue additional indebtedness, dispose of assets or access the capital markets may be substantially limited or nonexistent during the Chapter 11 Cases and will require court approval in most instances. Accordingly, our liquidity will depend mainly on cash generated from operating activities and available funds under the DIP Credit Facility as discussed below.
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, the creditors are stayed from taking any action as a result of the default under Section 362 of the Bankruptcy Code.
As of March 31, 2021, we had a cash balance of $179.7 million compared to $89.9 million as of December 31, 2020, and a net working capital deficit of $137.1 million as of March 31, 2021, compared to a net working capital deficit of $100.5 million as of December 31, 2020. As of March 31, 2021, our working capital deficit includes $279.8 million of debt due in the next 12 months. Our total principal debt as of both March 31, 2021 and December 31, 2020 was $2.3 billion. As of March 31, 2021, we had no borrowing capacity available under the Pre-Petition Revolving Credit Facility, with outstanding borrowings of $316.8 million and $121.2 million utilized for various letters of credit and $76.5 million of borrowing capacity available under the DIP Credit Facility, with outstanding borrowings of $157.5 million and $28.5 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.
We believe our cash flow from operations, borrowing capacity under the DIP Credit Facility and cash on hand will provide sufficient liquidity during the Chapter 11 process. We expect to continue to incur significant costs related to our ongoing Chapter 11 Cases until our expected emergence in May 2021, including fees for legal, financial and restructuring advisors to the Company, certain of our creditors and royalty interest owners.
Our ability to continue as a going concern is contingent on our ability to comply with the financial and other covenants contained in our DIP Credit Facility, our ability to successfully implement the Plan and obtain exit financing, among other factors. As a result of the Bankruptcy Filing, the realization of assets and the satisfaction of liabilities are subject to uncertainty. While operating as debtors-in-possession under Chapter 11, we may settle liabilities, subject to the approval of the Bankruptcy Court or as otherwise permitted in the ordinary course of business (and subject to restrictions contained in the DIP Credit Facility), for amounts other than those reflected in the accompanying consolidated financial statements.
The Bankruptcy Court entered an order confirming the Plan on April 28, 2021. See Note 2 for discussion of the exit facility to become effective upon emergence.
Debtor-In-Possession Credit Facility. Pursuant to the RSA, the Consenting RBL Lenders have 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 $105 million of new money and $157.5 million to roll up a portion of the existing outstanding obligations under the Pre-Petition Revolving Credit Facility. The proceeds of the DIP Credit Facility may be 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.
Advances under our DIP Credit Facility may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate of 3.50%, plus (2) the base rate. The interest rate for eurodollar loans is equal to (1) the applicable rate of 4.50%, plus (2) the highest of: (a) 1% or (b) the eurodollar rate. As of March 31, 2021 amounts borrowed under our DIP Credit Facility bore interest at the weighted average rate of 5.50%. In addition to paying interest on outstanding principal and letters of credit posted under the DIP Credit Facility, we are required to pay a commitment fee of 0.50% per annum to the lenders of the DIP Credit Facility in respect of the unutilized DIP commitments thereunder and a letter of credit fee equal to 0.20% per annum.
The DIP Credit Facility includes negative covenants that, subject to significant exceptions, limit our ability and the ability of our restricted subsidiaries to, among other things, (i) create liens on assets, property revenues, (ii) make investments, (iii) incur additional indebtedness, (iv) engage in mergers, consolidations, liquidations and dissolutions, (v) sell assets, (vi) pay dividends and distributions or repurchase capital stock, (vii) cease for any reason to be the operator of its properties, (viii) enter into letters of credit without prior written consent, (ix) enter into certain commodity hedging contracts except commodity
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hedging contracts with terms approved by the Bankruptcy Court in the hedging order or certain interest rate contracts, (x) change lines of business, (xi) engage in certain transactions with affiliates and (xii) incur more than a certain amount in capital expenditures in any calendar month. The DIP Credit Facility includes certain customary representations and warranties, affirmative covenants and events of default, including but not limited to defaults on account of nonpayment, breaches of representations and warranties and covenants, certain bankruptcy-related events, certain events under ERISA, material judgments and a change in control. If an event of default occurs, the lenders under the DIP Credit Facility will be entitled to take various actions, including the acceleration of all amounts due under the DIP Credit Facility and all actions permitted to be taken under the loan documents or application of law. In addition, the DIP Credit Facility is subject to various other financial performance covenants, including compliance with certain financial metrics and adherence to a budget approved by our DIP Credit Facility lenders.
Pre-Petition Revolving Credit Facility. We have entered into a senior secured revolving credit facility agreement, as amended, with The Bank of Nova Scotia, as the lead arranger and administrative agent and certain lenders from time to time party thereto. The credit agreement provides for a maximum borrowing base amount of $580 million and matures on December 31, 2021. The $316.8 million of outstanding borrowings under the Pre-Petition Revolving Credit Facility as of March 31, 2021 that were not rolled up into the DIP Credit Facility will remain outstanding throughout the Chapter 11 Cases and will continue to accrue interest on amounts drawn after the Petition Date. Additionally, as of March 31, 2021, we had an aggregate of $121.2 million of letters of credit outstanding under our Pre-Petition Revolving Credit Facility. This facility is secured by substantially all of our assets. Our wholly-owned subsidiaries, excluding Grizzly Holdings and Mule Sky, guarantee our obligations under our revolving credit facility.
Advances under our Pre-Petition Revolving Credit Facility may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate, which ranges from 0.25% to 1.25%, plus (2) the highest of: (a) the federal funds rate plus 0.50%, (b) the rate of interest in effect for such day as publicly announced from time to time by the administrative agent as its “prime rate,” and (c) the eurodollar rate for an interest period of one month plus 1.00%. The interest rate for eurodollar loans is equal to (1) the applicable rate, which ranges from 1.25% to 2.25%, plus (2) the London interbank offered rate that appears on pages LIBOR01 or LIBOR02 of the Reuters screen that displays such rate for deposits in U.S. dollars, or, if such rate is not available, the rate as administered by ICE Benchmark Administration (or any other person that takes over administration of such rate) per annum equal to the offered rate on such other page or other service that displays an average London interbank offered rate as administered by ICE Benchmark Administration (or any other person that takes over the administration of such rate) for deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major New York money center banks of whom the administrative agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. As of March 31, 2021, amounts borrowed under our revolving credit facility bore interest at the weighted average rate of 3.12%.
Senior Notes. In April 2015, we issued an aggregate of $350.0 million in principal amount of our 2023 Notes. Interest on these senior notes accrues at a rate of 6.625% per annum on the outstanding principal amount thereof, payable semi-annually on May 1 and November 1 of each year. As of March 31, 2021, $324.6 million principal amount remained outstanding. The 2023 Notes mature on May 1, 2023.
In October 2016, we issued an aggregate of $650.0 million in principal amount of our 2024 Notes. Interest on the 2024 Notes accrues at a rate of 6.000% per annum on the outstanding principal amount thereof, payable semi-annually on April 15 and October 15 of each year. As of March 31, 2021, $579.6 million principal amount remained outstanding. The 2024 Notes mature on October 15, 2024.
In December 2016, we issued an aggregate of $600.0 million in principal amount of our 2025 Notes. Interest on the 2025 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof, payable semi-annually on May 15 and November 15 of each year. As of March 31, 2021, $507.9 million principal amount remained outstanding. The 2025 Notes mature on May 15, 2025.
In October 2017, we issued $450.0 million in aggregate principal amount of our 2026 Notes. Interest on the 2026 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof, payable semi-annually on January 15 and July 15 of each year. As of March 31, 2021, $374.6 million principal amount remained outstanding. The 2026 Notes mature on January 15, 2026.
All amounts outstanding on our Senior Notes have been classified as liabilities subject to compromise on the accompanying consolidated balance sheets as of March 31, 2021 and December 31, 2020.
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Building Loan. On June 4, 2015, we entered into a loan for the construction of our corporate headquarters in Oklahoma City, which was substantially completed in December 2016. Interest accrues daily on the outstanding principal balance at a fixed rate of 4.50% per annum. The building loan matures on June 4, 2025. As of March 31, 2021, the total borrowings under the building loan were approximately $21.9 million, which has been classified as liabilities subject to compromise on the accompanying consolidated balance sheets as of March 31, 2021.
Supplemental Guarantor Financial Information. The 2023 Notes, 2024 Notes, 2025 Notes and 2026 Notes are guaranteed on a senior unsecured basis by all existing consolidated subsidiaries that guarantee our secured revolving credit 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 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 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 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 March 31, 2021, we had the following open natural gas, oil and NGL derivative instruments:
Natural Gas Derivatives
YearType of Derivative InstrumentIndexDaily Volume (MMBtu/day)Weighted
Average Price ($)
2021SwapsNYMEX Henry Hub351,316 $2.73 
2021Basis SwapsTetco M232,384 $(0.63)
2021Basis SwapsRex Zone 385,309 $(0.22)
2022Basis SwapsRex Zone 314,795 $(0.10)
2021Costless CollarsNYMEX Henry Hub390,509 $2.54/$2.93
2022Costless CollarsNYMEX Henry Hub186,438 $2.63/$3.04
2022Sold Call OptionsNYMEX Henry Hub152,675 $2.90 
2023Sold Call OptionsNYMEX Henry Hub627,675 $2.90 
Oil Derivatives
YearType of Derivative InstrumentIndexDaily Volume (Bbl/day)Weighted
Average Price ($)
2021SwapsNYMEX WTI1,505 $53.07 
NGL Derivatives
YearType of Derivative InstrumentIndexDaily Volume (Bbl/day)Weighted
Average Price ($)
2021SwapsMont Belvieu C32,074 $27.80 
2022SwapsMont Belvieu C3496 $27.30 
See Note 9 of the notes to our consolidated financial statements for further discussion of derivatives and hedging activities.
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Capital Expenditures. Our capital expenditures have historically been primarily related to the execution of our drilling and completion activities in addition to certain lease and other 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.
We continually monitor market conditions and are prepared to adjust our drilling program if commodity prices dictate. We believe our cash flow from operations, borrowing capacity under the DIP Credit Facility and cash on hand will provide sufficient liquidity during the Chapter 11 process. We expect to incur significant costs associated with our ongoing Chapter 11 Cases in 2021, including fees for legal, financial and restructuring advisors to the Company, certain of our creditors and royalty interest owners. Therefore, our ability to obtain confirmation of the Plan in a timely manner is critical to ensuring our liquidity is sufficient during the bankruptcy process.
Cash Flow from Operating Activities. Net cash flow provided by operating activities was $123.2 million for the three months ended March 31, 2021 as compared to $130.8 million for the same period in 2020. This decrease was primarily the result of working capital changes.
Uses of Funds. The following table presents the uses of our cash and cash equivalents for the three months ended March 31, 2021 and 2020:
 Three months ended March 31,
20212020
(In thousands)
Oil and Natural Gas Property Cash Expenditures:
Drilling and completion costs$51,702 $97,538 
Leasehold acquisitions2,354 7,346 
Other2,839 8,860 
Total oil and natural gas property expenditures$56,895 $113,744 
Other Uses of Cash and Cash Equivalents
Cash paid to repurchase senior notes$— $10,204 
Principal payments on borrowings, net— 55,106 
Other303 685 
Total other uses of cash and cash equivalents$303 $65,995 
Total uses of cash and cash equivalents$57,198 $179,739 
Drilling and Completion Costs. During three months ended March 31, 2021, we spud nine gross (9.0 net) and commenced sales from seven gross and net operated wells in the Utica for a total cost of approximately $46.4 million. During the three months ended March 31, 2021, we did not spud any wells and commenced sales from three gross (2.7 net) operated wells in the SCOOP for a total cost of approximately $23.9 million.
During the three months ended March 31, 2021, we did not participate in any wells that were spud or turned to sales by other operators on our Utica acreage. In addition, three gross (0.001 net) wells were spud and 10 gross (1.86 net) wells were turned to sales by other operators on our SCOOP acreage during the three months ended March 31, 2021.
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.
Contractual and Commercial Obligations
We have various contractual obligations in the normal course of our operations and financing activities. See Note 8 of the notes to our consolidated financial statements for further discussion of the amendments to our firm gathering and transportation agreements. 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, 2020.    
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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 March 31, 2021, our material off-balance sheet arrangements and transactions include $121.2 million in letters of credit outstanding against our Pre-Petition Revolving Credit Facility, $28.5 million in letters of credit outstanding against our DIP Credit Facility and $110.9 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. 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 resources. See Note 8 to our consolidated financial statements for further discussion of the various financial guarantees we have issued.
Critical Accounting Policies and Estimates
As of March 31, 2021, there have been no significant changes in our critical accounting policies from those disclosed in our 2020 Annual Report on Form 10-K.
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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 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 Boardboard of Directorsdirectors reviews our
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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 estimated 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 are typically reversed. The actual fixed prices on our derivative instruments is derived from the reference prices from 3rd party indices such as 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.
We have determined the fair value of our derivative instruments utilizing established index prices, volatility curves, discount factors and 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 910 of the notes to our consolidated financial statements for further discussion of the fair value measurements associated with our derivatives.
As of March 31,September 30, 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 March 31, 2021:
LocationDaily Volume (MMBtu/day)Weighted
Average Price
Remaining 2021NYMEX Henry Hub351,316 $2.73 
LocationDaily Volume
(Bbl/day)		Weighted
Average Price
Remaining 2021NYMEX WTI1,505 $53.07 
LocationDaily Volume
(Bbl/day)		Weighted
Average Price
Remaining 2021Mont Belvieu C22,074 $27.80 
2022Mont Belvieu C3496 $27.30 
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 on certain natural gas swaps that settled in 2020. Each call option has an established ceiling price of $2.90/MMBtu. If monthly NYMEX natural gas prices settle above the $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 as of March 31, 2021.
LocationDaily Volume (MMBtu/day)Weighted
Average Price
2022NYMEX Henry Hub152,675 $2.90 
2023NYMEX Henry Hub627,675 $2.90 
Below is a summary of our costless collar positions as of March 31, 2021.
LocationDaily Volume (MMBtu/day)Weighted Average Floor PriceWeighted Average Ceiling Price
2021NYMEX Henry Hub390,509 $2.54 $2.93 
2022NYMEX Henry Hub186,438 $2.63 $3.04 
Below is a summary of our basis swap positions as of March 31, 2021.
Gulfport PaysGulfport ReceivesDaily Volume (MMBtu/day)Weighted Average Fixed Spread
Remaining 2021Rex Zone 3NYMEX Plus Fixed Spread85,309 $(0.22)
Remaining 2021Tetco M2NYMEX Plus Fixed Spread32,384 $(0.63)
2022Rex Zone 3NYMEX Plus Fixed Spread14,795 $(0.10)
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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.propane. We will receive the fixed priced amount stated in the contract and pay to its counterparty the current market price as listed on the applicable index.
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Our 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 March 31,September 30, 2021, we had a net liability derivative position of $50.9$830.6 million as compared to a net assetliability derivative position of $100.9$80.6 million as of March 31,September 30, 2020. Utilizing actual derivative contractual volumes, a 10% increase in underlying commodity prices would have reduced the fair value of these instrumentsincreased our liability by approximately $87.4$231.5 million, while a 10% decrease in underlying commodity prices would have increased the fair value of these instrumentsdecreased our liability by approximately $80.0$220.3 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 eurodollarEurodollar loans. As such, our interest expense is sensitive to fluctuations in the prime rates in the United States, or, if the eurodollarEurodollar rates are elected, the eurodollarEurodollar rates. At March 31,September 30, 2021, we had $316.8$35.6 million in borrowings outstanding under our Pre-Petition Revolving CreditExit Facility which bore interest at a weighted average rate of 3.12%4.50%. At March 31,September 30, 2021, we had $157.5$165.0 million in borrowings outstanding under our DIP Credit FacilityFirst-Out Term Loan which bore interest at a weighted average rate of 5.50%. As of March 31,September 30, 2021, we did not have any interest rate swaps to hedge 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 March 31,September 30, 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 March 31,September 30, 2021, our disclosure controls and procedures are 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 absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that the Company's controls will succeed in 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
The information with respect to this Item 1. Legal Proceedings is set forth in Note 89 in the accompanying condensed consolidated financial statements. Additionally, see Note 1 in the accompanying condensed consolidated financial statements for additional discussion of on-going claims and disputes in our Chapter 11 proceedings, certain of which may be material.
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, 2020.2020 and our Quarterly Report on Form 10-Q for the quarter ended June 30, 2021.
ITEM 2.UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Unregistered Sales of Equity Securities
    None.
Issuer Repurchases of Equity Securities
Our common stock repurchase activity for the three months ended March 31, 2021 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 programs
January— $— — 
February86,401 $0.09 — 
March— $— — 
Total86,401 $0.09 — 
(1)During the three months ended March 31, 2021, we repurchased and canceled 86,401 shares of our common stock at a weighted average price of $0.09 to satisfy tax withholding requirements incurred upon the vesting of restricted stock unit awards.
None.
ITEM 3.DEFAULTS UPON SENIOR SECURITIES
Our Bankruptcy Filing described above constitutes an event of default that accelerated our obligations under our senior Pre-Petition Revolving Credit Facility and our Senior Notes. Under the Bankruptcy Code, the creditors under these debt agreements are stayed from taking any action against us as a result of an event of default. See Note 1 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 principal and interest amounts of debt included in liabilities subject to compromise on the accompanying unaudited consolidated balance sheet as of March 31, 2021 and our Bankruptcy Filing and the Chapter 11 Cases.None.
ITEM 4.MINE SAFETY DISCLOSURES
Not applicable.
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ITEM 5.OTHER INFORMATION
None.

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ITEM 6.EXHIBITS
INDEX OF EXHIBITS
Incorporated by Reference
Exhibit NumberDescriptionFormSEC File NumberExhibitFiling DateFiled or Furnished Herewith
2.18-K001-195142.14/29/2021
2.28-K001-195142.24/29/2021
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
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
10.18-K001-1951410.110/14/2021
10.2*8-K001-1951410.19/7/2021
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
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4.68-A001-195144.14/30/2020
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
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 or compensatory plan or arrangement
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SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: May 6,November 3, 2021
 
GULFPORT ENERGY CORPORATION
By:/s/    Quentin HicksWilliam Buese
Quentin HicksWilliam Buese
Executive Vice President & Chief Financial Officer

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