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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
ý☒QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2017 OR
¨
For the quarterly period ended June 30, 2023
OR
☐TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
For the transition period from to
Commission File Number 000-19514
001-19514
Gulfport Energy Corporation
(Exact Name of Registrant As Specified in Its Charter)
Delaware
73-1521290
Delaware
86-3684669
(State or Other Jurisdiction of
Incorporation or Organization)
(IRS Employer
Identification Number)
3001 Quail Springs Parkway
Oklahoma City, Oklahoma
713 Market Drive		73134
Oklahoma City,Oklahoma73114
(Address of Principal Executive Offices)(Zip Code)
(405) 252-4600
(Registrant Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common Stock, $0.0001 par value per shareGPORThe New York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
    Yes  ý     No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or such shorter period that the registrant was required to submit and post such files).     Yes  ý    No  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated filer   ý     Accelerated filer   ¨       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 OctoberJuly 27, 2017, 183,081,7762023, 18,678,638 shares of the registrant’s common stock were outstanding.



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GULFPORT ENERGY CORPORATION
TABLE OF CONTENTS
 
Page
Page
PART I FINANCIAL INFORMATION
Item 1.
24
24
35
4
Consolidated Statements of Stockholders’ Equity for the Nine Months Ended September 30, 2017 and 2016
57
69
710
1. Basis of Presentation
10
2. Property and Equipment
11
3. Debt
12
4. Mezzanine Equity
14
5. Equity
15
6. Stock-Based Compensation
16
7. Restructuring Costs
18
8. Earnings (Loss) Per Share
18
9. Commitments and Contingencies
19
10. Derivative Instruments
22
11. Fair Value Measurements
26
12. Revenue from Contracts with Customers
27
13. Leases
28
14. Income Taxes
29
15. Related Party Transactions
30
16. Subsequent Events
30
Item 2.
3731
32
33
35
40
45
Item 3.
5449
Item 4.
5650
Item 1.
5851
Item 1A.
5851
Item 2.
5851
Item 3.
5951
Item 4.
5951
Item 5.
5952
Item 6.
5953
6155

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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:
1145 Indenture. Agreement dated May 17, 2021 between the Company, UMB Bank, National Association, as trustee, and the guarantors party thereto, under section 1145 of the Bankruptcy Code for our 8.0% Senior Notes due 2026.
2026 Senior Notes. 8.0% Senior Notes due 2026.
4(a)(2) Indenture. Certain eligible holders have made an election entitling such holders to receive senior notes issued pursuant to an indenture, dated as of May 17, 2021, by and among the Company, UMB Bank, National Association, as trustee, and the guarantors party thereto, under Section 4(a)(2) of the Securities Act of 1933, as amended (the “Securities Act”) as opposed to its share of the up to $550 million aggregate principal amount of our Senior Notes due 2026. The 4(a)(2) Indenture’s terms are substantially similar to the terms of the 1145 Indenture. The primary differences between the terms of the 4(a)(2) Indenture and the terms of the 1145 Indenture are that (i) affiliates of the Issuer holding 4(a)(2) Notes are permitted to vote in determining whether the holders of the required principal amount of indenture securities have concurred in any direction or consent under the 4(a)(2) Indenture, while affiliates of the Issuer holding 1145 Notes will not be permitted to vote on such matters under the 1145 Indenture, (ii) the covenants of the 1145 Indenture (other than the payment covenant) require that the Issuer comply with the covenants of the 4(a)(2) Indenture, as amended, and (iii) the 1145 Indenture requires that the 1145 Securities be redeemed pro rata with the 4(a)(2) Securities and that the 1145 Indenture be satisfied and discharged if the 4(a)(2) Indenture is satisfied and discharged.
ASC. Accounting Standards Codification.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.
Board of Directors (Board). The board of directors of Gulfport Energy Corporation.
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.
Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas, oil and NGL.
Credit Facility. The Existing Credit Facility, as amended by the Joinder, Commitment Increase and Borrowing Base Redetermination Agreement, and Third Amendment to Credit Agreement dated as of May 1, 2023.
DD&A. Depreciation, depletion and amortization.
Disputed Claims Reserve. Reserve used to settle any pending claims of unsecured creditors that were in dispute as of the effective date of the Plan.
Emergence Date. 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.
Existing Credit Facility. The Third 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, as amended to date.
GAAP. Accounting principles generally accepted in the United States of America.
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 Credit Facility or certain other debt.
Incentive Plan. Gulfport Energy Corporation Stock Incentive Plan effective on the Emergence Date.
Indentures. Collectively, the 1145 Indenture and the 4(a)(2) Indenture governing the 2026 Senior Notes.
IRC. The Internal Revenue Code of 1986, as amended.
LIBOR. London Interbank Offered Rate.
LOE. Lease operating expenses.
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Marcellus. Refers to the Marcellus Play that includes the hydrocarbon bearing rock formations commonly referred to as the Marcellus formation located in the Appalachian Basin of the United States and Canada. Our acreage is located primarily in Belmont County in eastern Ohio.
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, with one barrel of NGL and crude oil being equivalent to 6,000 cubic feet of natural gas.
MMBtu. One million British thermal units.
MMcf. One million cubic feet of natural gas.
MMcfe. One million cubic feet of natural gas equivalent, with one barrel of NGL and crude oil being equivalent to 6,000 cubic feet of natural gas.
Natural Gas Liquids (NGL). Hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, adsorption or other methods in gas processing or cycling plants. Natural gas liquids primarily include ethane, propane, butane, isobutene, pentane, hexane and natural gasoline.
Net Acres or Net Wells. Refers to the sum of fractional working interests owned in gross acres or gross wells.
NYMEX. New York Mercantile Exchange.
Parent. Gulfport Energy Corporation.
Plan. The Amended Joint Chapter 11 Plan of Reorganization of Gulfport Energy Corporation and Its Debtor Subsidiaries.
Repurchase Program. A stock repurchase program to acquire up to $400 million of Gulfport's outstanding common stock. It is authorized to extend through March 31, 2024, and may be suspended from time to time, modified, extended or discontinued by the Board of Directors at any time.
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.
Section 382. Internal Revenue Code Section 382.
SOFR. Secured Overnight Financing Rate.
Successor. The post-emergence from bankruptcy reorganized organization for periods subsequent to May 17, 2021.
Utica. Refers to the Utica Play that includes the hydrocarbon bearing rock formations commonly referred to as the Utica 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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Cautionary Note Regarding Forward-Looking Statements
This Form 10-Q may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), and the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify forward looking statements by terms such as “may,” “will,” “should,” “could,” “would,” “expects,” “plans,” “anticipates,” “intends,” “believes,” “estimates,” “projects,” “predicts,” “potential” and similar expressions intended to identify forward-looking statements. All statements, other than statements of historical facts, included in this Form 10-Q that address activities, events or developments that we expect or anticipate will or may occur in the future, including the expected impact of the war in Ukraine 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, 2022 and elsewhere in this Form 10-Q. All forward-looking statements speak only as of the date of this Form 10-Q.
All forward-looking statements, expressed or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report.
We may use the Investors section of our website (www.gulfportenergy.com) to communicate with investors. It is possible that the financial and other information posted there could be deemed to be material information. The information on our website is not part of this Quarterly Report on Form 10-Q.


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

June 30, 2023December 31, 2022
Assets
Current assets:
Cash and cash equivalents$5,269 $7,259 
Accounts receivable—oil, natural gas, and natural gas liquids sales92,104 278,404 
Accounts receivable—joint interest and other17,883 21,478 
Prepaid expenses and other current assets6,453 7,621 
Short-term derivative instruments140,686 87,508 
Total current assets262,395 402,270 
Property and equipment:
Oil and natural gas properties, full-cost method
Proved oil and natural gas properties2,695,104 2,418,666 
Unproved properties188,461 178,472 
Other property and equipment7,419 6,363 
Total property and equipment2,890,984 2,603,501 
Less: accumulated depletion, depreciation and amortization(705,153)(545,771)
Total property and equipment, net2,185,831 2,057,730 
Other assets:
Long-term derivative instruments54,308 26,525 
Operating lease assets20,600 26,713 
Other assets32,590 21,241 
Total other assets107,498 74,479 
Total assets$2,555,724 $2,534,479 
Liabilities, Mezzanine Equity and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities$307,720 $437,384 
Short-term derivative instruments59,367 343,522 
Current portion of operating lease liabilities12,756 12,414 
Total current liabilities379,843 793,320 
Non-current liabilities:
Long-term derivative instruments61,557 118,404 
Asset retirement obligation33,638 33,171 
Non-current operating lease liabilities7,844 14,299 
Long-term debt648,267 694,155 
Total non-current liabilities751,306 860,029 
Total liabilities$1,131,149 $1,653,349 
Commitments and contingencies (Note 9)
Mezzanine Equity:
Preferred stock - $0.0001 par value, 110.0 thousand shares authorized, 46.5 thousand issued and outstanding at June 30, 2023, and 52.3 thousand issued and outstanding at December 31, 202246,459 52,295 
Stockholders’ Equity:
Common stock - $0.0001 par value, 42.0 million shares authorized, 18.7 million issued and outstanding at June 30, 2023, and 19.1 million issued and outstanding at December 31, 20222 2 
Additional paid-in capital384,082 449,243 
Common stock held in reserve, 62 thousand shares at June 30, 2023, and 62 thousand shares at December 31, 2022(1,996)(1,996)
Retained Earnings996,028 381,872 
Treasury stock, at cost - no shares at June 30, 2023, and 3.9 thousand shares at December 31, 2022— (286)
Total stockholders’ equity$1,378,116 $828,835 
Total liabilities, mezzanine equity and stockholders’ equity$2,555,724 $2,534,479 
See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)(In thousands)
(Unaudited)
 Three months ended September 30, Nine months ended September 30,
 2017 2016 2017 2016
 (In thousands, except share data)
Revenues:       
Natural gas sales$223,340
 $122,018
 $606,544
 $271,873
Oil and condensate sales31,459
 21,799
 85,338
 60,799
Natural gas liquid sales33,559
 14,594
 88,985
 34,198
Net (loss) gain on natural gas, oil, and NGL derivatives(22,860) 35,281
 141,588
 (44,376)
 265,498
 193,692
 922,455
 322,494
Costs and expenses:
      
Lease operating expenses20,020
 17,471
 60,044
 48,789
Production taxes5,419
 3,525
 14,464
 9,492
Midstream gathering and processing69,372
 45,475
 176,258
 122,476
Depreciation, depletion and amortization106,650
 62,285
 254,887
 183,414
Impairment of oil and natural gas properties—
 212,194
 —
 601,806
General and administrative13,065
 10,467
 37,922
 32,941
Accretion expense456
 269
 1,148
 777
Acquisition expense33
 —
 2,391
 —
 215,015
 351,686
 547,114
 999,695
INCOME (LOSS) FROM OPERATIONS50,483
 (157,994) 375,341
 (677,201)
OTHER (INCOME) EXPENSE:
      
Interest expense27,130
 12,787
 74,797
 44,892
Interest income(37) (337) (927) (822)
Insurance proceeds—
 (3,750) —
 (3,750)
Loss (income) from equity method investments, net2,737
 (5,997) 20,945
 25,576
Other income(345) 6
 (863) (3)
 29,485
 2,709
 93,952
 65,893
INCOME (LOSS) BEFORE INCOME TAXES20,998
 (160,703) 281,389
 (743,094)
INCOME TAX EXPENSE (BENEFIT)2,763
 (3,407) 2,763
 (3,755)
NET INCOME (LOSS)$18,235
 $(157,296) $278,626
 $(739,339)
NET INCOME (LOSS) PER COMMON SHARE:       
Basic$0.10
 $(1.25) $1.56
 $(6.12)
Diluted$0.10
 $(1.25) $1.56
 $(6.12)
Weighted average common shares outstanding—Basic182,957,416
 125,408,866
 178,736,569
 120,771,046
Weighted average common shares outstanding—Diluted183,008,436
 125,408,866
 179,130,570
 120,771,046

Three Months Ended June 30, 2023Three Months Ended June 30, 2022
REVENUES:
Natural gas sales$159,246 $539,090 
Oil and condensate sales22,602 45,009 
Natural gas liquid sales26,070 54,106 
Net gain (loss) on natural gas, oil and NGL derivatives96,788 (172,871)
Total revenues304,706 465,334 
OPERATING EXPENSES:
Lease operating expenses16,155 14,239 
Taxes other than income7,938 16,682 
Transportation, gathering, processing and compression85,664 87,752 
Depreciation, depletion and amortization80,148 62,602 
General and administrative expenses8,611 8,271 
Restructuring costs2,893 — 
Accretion expense714 692 
Total operating expenses202,123 190,238 
INCOME FROM OPERATIONS102,583 275,096 
OTHER EXPENSE (INCOME):
Interest expense13,727 14,234 
Other, net(4,831)4,282 
Total other expense8,896 18,516 
INCOME BEFORE INCOME TAXES93,687 256,580 
Income tax expense— — 
NET INCOME$93,687 $256,580 
Dividends on preferred stock$(1,278)$(1,380)
Participating securities - preferred stock$(14,044)$(39,590)
NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS$78,365 $215,610 
NET INCOME PER COMMON SHARE:
Basic$4.23 $10.42 
Diluted$4.18 $10.34 
Weighted average common shares outstanding—Basic18,518 20,684 
Weighted average common shares outstanding—Diluted18,805 20,877 
See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)OPERATIONS
(Unaudited)
(In thousands)
 Three months ended September 30, Nine months ended September 30,
 2017 2016 2017 2016
 (In thousands)
Net income (loss)$18,235
 $(157,296) $278,626
 $(739,339)
Foreign currency translation adjustment (1)6,832
 (4,013) 12,719
 4,361
Other comprehensive income (loss)6,832
 (4,013) 12,719
 4,361
Comprehensive income (loss)$25,067
 $(161,309) $291,345
 $(734,978)
(Unaudited)

Six Months Ended June 30, 2023Six Months Ended June 30, 2022
REVENUES:
Natural gas sales$441,780 $944,302 
Oil and condensate sales53,316 75,248 
Natural gas liquid sales65,982 99,390 
Net gain (loss) on natural gas, oil and NGL derivatives474,849 (961,422)
Total revenues1,035,927 157,518 
OPERATING EXPENSES:
Lease operating expenses36,017 31,883 
Taxes other than income18,633 29,150 
Transportation, gathering, processing and compression173,281 172,544 
Depreciation, depletion and amortization159,242 124,886 
General and administrative expenses17,344 15,376 
Restructuring costs4,762 — 
Accretion expense1,478 1,384 
Total operating expenses410,757 375,223 
INCOME (LOSS) FROM OPERATIONS625,170 (217,705)
OTHER EXPENSE (INCOME):
Interest expense27,483 28,218 
Other, net(19,054)(10,528)
Total other expense8,429 17,690 
INCOME (LOSS) BEFORE INCOME TAXES616,741 (235,395)
Income tax expense— — 
NET INCOME (LOSS)$616,741 $(235,395)
Dividends on preferred stock$(2,585)$(2,828)
Participating securities - preferred stock$(92,611)$— 
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS$521,545 $(238,223)
NET INCOME (LOSS) PER COMMON SHARE:
Basic$27.91 $(11.36)
Diluted$27.60 $(11.36)
Weighted average common shares outstanding—Basic18,688 20,961 
Weighted average common shares outstanding—Diluted18,930 20,961 

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


See accompanying notes to consolidated financial statements.

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

Common Stock Held in ReserveTreasury StockPaid-in
Capital		Retained Earnings (Accumulated
Deficit)		Total Stockholders’
Equity
Common Stock
SharesAmountSharesAmount
Balance at January 1, 202221,537 $2 (938)$(30,216)$— $692,521 $(112,829)$549,478 
Net loss— — — — — — (491,975)(491,975)
Conversion of preferred stock1 — — — — 18 — 18 
Stock compensation— — — — — 1,755 — 1,755 
Repurchase of common stock under Repurchase Program(378)— — — (5,318)(30,194)— (35,512)
Issuance of common stock held in reserve— — 876 28,220 — — — 28,220 
Issuance of restricted stock, net of shares withheld for income taxes2 — — — — (80)— (80)
Dividends on preferred stock— — — — — (1,447)— (1,447)
Balance at March 31, 202221,162 $2 (62)$(1,996)$(5,318)$662,573 $(604,804)$50,457 
Net income— — — — — — 256,580 256,580 
Conversion of preferred stock342 — — — — 4,706 — 4,706 
Stock compensation— — — — — 2,145 — 2,145 
Issuance of restricted stock, net of shares withheld for income taxes8 — — — — (325)— (325)
Repurchase of common stock under Repurchase Program(1,382)— — — (2,491)(125,019)— (127,510)
Dividends on preferred stock— — — — — (1,380)— (1,380)
Balance at June 30, 202220,130 $2 (62)$(1,996)$(7,809)$542,700 $(348,224)$184,673 


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

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY CONTINUED
(In thousands)
(Unaudited)
Common Stock Held in ReserveTreasury StockPaid-in
Capital		Retained Earnings (Accumulated
Deficit)		Total Stockholders’
Equity
Common Stock
SharesAmountSharesAmount
Balance at January 1, 202319,097 $2 (62)$(1,996)$(286)$449,243 $381,872 $828,835 
Net income— — — — — — 523,054 523,054 
Stock compensation— — — — — 3,069 — 3,069 
Repurchase of common stock under Repurchase Program(457)— — — (201)(33,001)— (33,202)
Issuance of restricted stock, net of shares withheld for income taxes3 — — — — (287)— (287)
Dividends on preferred stock— — — — — — (1,307)(1,307)
Balance at March 31, 202318,643 $2 (62)$(1,996)$(487)$419,024 $903,619 $1,320,162 
Net income— — — — — — 93,687 93,687 
Conversion of preferred stock431 — — — — 5,836 — 5,836 
Stock compensation— — — — — 3,834 — 3,834 
Repurchase of common stock under Repurchase Program(448)— — — 487 (43,117)— (42,630)
Issuance of restricted stock, net of shares withheld for income taxes32 — — — — (1,493)— (1,493)
Dividends on preferred stock— — — — — (2)(1,278)(1,280)
Balance at June 30, 202318,658 $2 (62)$(1,996)$— $384,082 $996,028 $1,378,116 
See accompanying notes to consolidated financial statements.


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GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)
 Nine months ended September 30,
 2017 2016
 (In thousands)
Cash flows from operating activities:   
Net income (loss)$278,626
 $(739,339)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:   
Accretion of discount—Asset Retirement Obligation1,148
 777
Depletion, depreciation and amortization254,887
 183,414
Impairment of oil and natural gas properties—
 601,806
Stock-based compensation expense4,793
 5,730
Loss from equity investments21,495
 25,988
Change in fair value of derivative instruments(129,692) 184,013
Deferred income tax expense (benefit)—
 17,211
Amortization of loan commitment fees3,548
 2,912
Amortization of note discount and premium—
 (1,716)
Changes in operating assets and liabilities:   
Increase in accounts receivable(43,345) (55,916)
Increase in accounts receivable—related party(346) (80)
Increase in prepaid expenses(2,531) (6,835)
Increase in other assets(5,665) —
Increase in accounts payable, accrued liabilities and other111,335
 28,265
Settlement of asset retirement obligation(2,520) (955)
Net cash provided by operating activities491,733
 245,275
Cash flows from investing activities:   
Deductions to cash held in escrow—
 8
Additions to other property and equipment(16,288) (20,131)
Acquisition of oil and natural gas properties(1,339,456) —
Additions to oil and natural gas properties(789,743) (441,128)
Proceeds from sale of oil and natural gas properties4,079
 41,534
Proceeds from sale of other property and equipment658
 —
Funding of restricted cash185,000
 —
Contributions to equity method investments(44,844) (18,510)
Distributions from equity method investments4,114
 14,220
Insurance proceeds—
 3,750
Net cash used in investing activities(1,996,480) (420,257)
Cash flows from financing activities:   
Principal payments on borrowings(183) (1,685)
Borrowings on line of credit365,000
 —
Borrowings on term loan2,951
 16,499
Debt issuance costs and loan commitment fees(8,261) (241)
Proceeds from issuance of common stock, net of offering costs(5,364) 411,711
Net cash provided by financing activities354,143
 426,284
Net (decrease) increase in cash and cash equivalents(1,150,604) 251,302
Cash and cash equivalents at beginning of period1,275,875
 112,974
Cash and cash equivalents at end of period$125,271
 $364,276
Supplemental disclosure of cash flow information:   
Interest payments$50,826
 $35,193
Income tax payments$—
 $—
Supplemental disclosure of non-cash transactions:   
Capitalized stock based compensation$3,195
 $3,820
Asset retirement obligation capitalized$11,557
 $6,726
Interest capitalized$8,753
 $8,920
Foreign currency translation gain on equity method investments$12,719
 $7,137
(Unaudited)
Six Months Ended June 30, 2023Six Months Ended June 30, 2022
Cash flows from operating activities:
Net income (loss)$616,741 $(235,395)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization159,242 124,886 
Net (gain) loss on derivative instruments(474,849)961,422 
Net cash receipts (payments) on settled derivative instruments52,886 (433,466)
Other, net9,227 5,071 
Changes in operating assets and liabilities, net48,159 (39,318)
Net cash provided by operating activities411,406 383,200 
Cash flows from investing activities:
Additions to oil and natural gas properties(283,406)(181,787)
Proceeds from sale of oil and natural gas properties2,648 580 
Other, net(835)(58)
Net cash used in investing activities(281,593)(181,265)
Cash flows from financing activities:
Principal payments on Credit Facility(518,000)(836,000)
Borrowings on Credit Facility472,000 796,000 
Debt issuance costs and loan commitment fees(6,920)(169)
Dividends on preferred stock(2,587)(2,828)
Repurchase of common stock under Repurchase Program(74,516)(155,212)
Other, net(1,780)(405)
Net cash used in financing activities(131,803)(198,614)
Net (decrease) increase in cash and cash equivalents(1,990)3,321 
Cash and cash equivalents at beginning of period7,259 3,260 
Cash and cash equivalents at end of period$5,269 $6,581 
See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
These consolidated financial statements have been prepared by
1.BASIS OF PRESENTATION
Description of Company
Gulfport Energy Corporation (the “Company”"Company" or “Gulfport”"Gulfport") without audit, pursuant tois an independent natural gas-weighted exploration and production company focused on the production of natural gas, crude oil and NGL in the United States. The Company's principal properties are located in eastern Ohio targeting the Utica and Marcellus and in central Oklahoma targeting the SCOOP Woodford and Springer formations.
Basis of Presentation
The accompanying unaudited condensed consolidated financial statements of Gulfport were prepared in 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 six months ended June 30, 2023, and the six months ended June 30, 2022. The Company's annual report on Form 10-K for the year ended December 31, 2022, should be read in conjunction with this Form 10-Q. The accompanying unaudited consolidated financial statements reflect all normal recurring adjustments which, in the opinion of management, are necessary for a fair presentationstatement of the results for the interim periods, 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 have been omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. These 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 thereto includedbalances have been eliminated. The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern.
Accounts Payable and Accrued Liabilities
Accounts payable and accrued liabilities consisted of the following (in thousands):
June 30, 2023December 31, 2022
Revenue payable and suspense$149,232 $222,721 
Accounts payable59,382 37,807 
Accrued transportation, gathering, processing and compression34,135 56,138 
Accrued capital expenditures30,640 36,464 
Accrued contract rejection damages and shares held in reserve1,996 40,996 
Other accrued liabilities32,335 43,258 
Total accounts payable and accrued liabilities$307,720 $437,384 
Other, net (in thousands)
Other, net in the Company’s most recent annual report on Form 10-K. ResultsCompany's consolidated statements of operations for the three and nine month periods ended September 30, 2017 are not necessarily indicative of the results expected for the full year.
1.ACQUISITIONS
Vitruvian Acquisition
In December 2016, the Company, through its wholly-owned subsidiary Gulfport MidCon LLC (“Gulfport MidCon”) (formerly known as SCOOP Acquisition Company, LLC), entered into an agreement to acquire certain assets of Vitruvian II Woodford, LLC (“Vitruvian”), an unrelated third-party seller (the “Vitruvian Acquisition”). The assets included in the Vitruvian Acquisition include 46,400 net surface acres located in Grady, Stephens and Garvin Counties, Oklahoma. On February 17, 2017, the Company completed the Vitruvian Acquisition for a total initial purchase price of approximately $1.85 billion, consisting of $1.35 billion in cash, subject to certain adjustments, and approximately 23.9 million shares of the Company’s common stock (of which approximately 5.2 million shares were placed in an indemnity escrow). The cash portion of the purchase price was funded with the net proceeds from the December 2016 common stock and senior note offerings and cash on hand. Acquisition costs of $0.03 million and $2.4 million were incurred during the three and ninesix months ended SeptemberJune 30, 2017, respectively,2023, included $17.8 million related to the Vitruvian Acquisition.
Allocation of Purchase Price
The Vitruvian Acquisition qualifiedinterim TC claim distribution and a $1 million administrative payment to Rover as a business combination for accounting purposes and, as such, the Company estimated the fair valuepart of the acquired properties asexecuted settlement. The distribution and settlement is more fully described in Note 9. The timing and amount of any future distributions to Gulfport are not certain, and the February 17, 2017 acquisition date. The fair valuetotal amount will be impacted by the liquidating trust's distributions and resolution of the assets acquired and liabilities assumed was estimated using assumptions that represent Level 3 inputs. See Noteother remaining bankruptcy claims. Additionally, Other, net included a $5.0 million recoupment of previously placed collateral for certain firm transportation commitments during our Chapter 11 for additional discussion of the measurement inputs.filing.
The Company estimated that the consideration paidOther, net in the Vitruvian AcquisitionCompany's consolidated statements of operations for these properties approximated the fair value that would be paid by a typical market participant. As a result, no goodwill or bargain purchase gain was recognized in conjunction with the purchase.
The following table summarizes the consideration paid in the Vitruvian Acquisition to acquire the properties and the fair value amount of the assets acquired as of February 17, 2017. Both the consideration paid and the fair value assignedsix months ended June 30, 2022, included $11.5 million related to the assets is preliminaryTC claim distribution received as discussed in Note 9. Additionally, Other, net included a $5.1 million payment to settle certain gas imbalance positions and subject to adjustment.

a $5.2 million receipt of funds from a litigation settlement.
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Supplemental Cash Flow and Non-Cash Information (in thousands)
Six Months Ended June 30, 2023Six Months Ended June 30, 2022
Supplemental disclosure of cash flow information:
Interest payments, net of amounts capitalized$26,122 $26,386 
Changes in operating assets and liabilities, net:
Accounts receivable - oil and natural gas sales$186,300 $(84,043)
Accounts receivable - joint interest and other$3,595 $(4,111)
Accounts payable and accrued liabilities$(140,832)$44,045 
Prepaid expenses$(973)$3,385 
Other assets$69 $1,406 
Total changes in operating assets and liabilities, net$48,159 $(39,318)
Supplemental disclosure of non-cash transactions:
Capitalized stock-based compensation$1,861 $1,326 
Asset retirement obligation capitalized$73 $18 
Asset retirement obligation removed due to divestiture$(919)$(7)
Release of common stock held in reserve$— $28,220 
Interest capitalized$1,839 $— 
2.PROPERTY AND EQUIPMENT
  (In thousands)
Consideration:  
     Cash, net of purchase price adjustments $1,354,093
     Fair value of Gulfport’s common stock issued 464,639
Total Consideration $1,818,732
   
Estimated Fair value of identifiable assets acquired and liabilities assumed:  
     Oil and natural gas properties  
       Proved properties $362,264
       Unproved properties 1,462,957
     Asset retirement obligations (6,489)
Total fair value of net identifiable assets acquired $1,818,732

The equity consideration included in the initial purchase price was based on an equity offering price of $20.96 on December 15, 2016. The decrease in the price of Gulfport’s common stock from $20.96 on December 15, 2016 to $19.48 on February 17, 2017 resulted in a decrease to the fair value of the total consideration paid as compared to the initial purchase price of approximately $35.3 million, which resulted in a closing date fair value lower than the initial purchase price.
Post-Acquisition Operating Results
For the three months ended September 30, 2017 and the period from the acquisition date of February 17, 2017 to September 30, 2017, the assets acquired in the Vitruvian Acquisition have contributed the following amounts of revenue to the Company’s consolidated statements of operations. The amount of net income contributed by the assets acquired is not presented below as it is impracticable to calculate due to the Company integrating the acquired assets into its overall operations using the full cost method of accounting.
    Period from
    February 17, 2017
  Three months ended to
  September 30, 2017 September 30, 2017
  (In thousands)
Revenue $60,940
 $137,706
Pro Forma Information (Unaudited)

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

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2.PROPERTY AND EQUIPMENT
The major categories of property and equipment and related accumulated depletion, depreciation, amortization and impairment as of September 30, 2017 and December 31, 2016DD&A are as follows:follows (in thousands):
June 30, 2023December 31, 2022
Proved oil and natural gas properties$2,695,104 $2,418,666 
Unproved properties188,461 178,472 
Other depreciable property and equipment7,033 5,977 
Land386 386 
Total property and equipment2,890,984 2,603,501 
Accumulated DD&A(705,153)(545,771)
Property and equipment, net$2,185,831 $2,057,730 
 September 30, 2017 December 31, 2016
 (In thousands)
Oil and natural gas properties$8,867,239
 $6,071,920
Office furniture and fixtures34,875
 21,204
Building44,530
 42,530
Land4,820
 5,252
Total property and equipment8,951,464
 6,140,906
Accumulated depletion, depreciation, amortization and impairment(4,043,879) (3,789,780)
Property and equipment, net$4,907,585
 $2,351,126

Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the Company's oil and natural gas properties. At September 30, 2017, the calculated ceiling was greater than the net book valueThe Company did not record an impairment of the Company’s oil and natural gas properties, thus no ceiling test impairment was required for the nine months ended September 30, 2017. An impairment of$212.2 million and $601.8 millionwas required forits oil and natural gas properties for the three andnineor six months ended SeptemberJune 30, 2016, respectively.2023 or 2022.
Included in oil and natural gas properties at September 30, 2017 is the cumulative capitalization of $155.5 million inCertain general and administrative costs incurred andare capitalized to the full cost pool. Generalpool and administrative costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All general and administrative costs not directly associated with exploration and development activities werecapitalized are charged to expense as they wereare incurred. Capitalized general and administrative costs were approximately $8.9$5.4 million and $25.6$10.5 million, for the three and ninesix months ended SeptemberJune 30, 2017,2023, respectively, and $7.2$5.0 million and $22.2$9.7 million for the three and ninesix months ended SeptemberJune 30, 2016,2022, respectively.
The following table summarizes the Company’s non-producing properties excluded from amortization by area at September 30, 2017:
 September 30, 2017
 (In thousands)
Utica$1,517,555
MidContinent1,435,992
Niobrara2,182
Southern Louisiana536
Bakken99
Other368
 $2,956,732
At December 31, 2016, approximately $1.6 billion of non-producing leasehold costs was not subject to amortization.
The Company evaluates the costs excluded from its amortization calculation at least annually. SubjectIndividually insignificant unevaluated properties are grouped for evaluation and periodically transferred to industry conditions and the levelevaluated properties over a timeframe consistent with their expected development schedule.
11
Table of the Company’s activities, the inclusion of most of the above referenced costs into the Company’s amortization calculation typically occurs within three to five years. However, the majority ofContents

The following table summarizes the Company’s non-producing leases have five-year extension terms which could extend this time frame beyond five years.properties excluded from amortization by area (in thousands):

June 30, 2023December 31, 2022
Utica$159,412 $147,370 
SCOOP29,049 31,102 
Total unproved properties$188,461 $178,472 
9
Table of ContentsAsset Retirement Obligation


AThe following table provides a reconciliation of the Company’s asset retirement obligation for the ninesix months ended SeptemberJune 30, 20172023 and 2016 is as follows:2022 (in thousands):
Six Months Ended June 30, 2023Six Months Ended June 30, 2022
Asset retirement obligation, beginning of period$33,171 $28,264 
Liabilities incurred73 22 
Liabilities settled(165)— 
Liabilities removed due to divestitures(919)(7)
Accretion expense1,478 1,384 
Total asset retirement obligation, end of period$33,638 $29,663 
3.DEBT
 September 30, 2017 September 30, 2016
 (In thousands)
Asset retirement obligation, beginning of period$34,276
 $26,437
Liabilities incurred11,557
 6,726
Liabilities settled(2,520) (955)
Accretion expense1,148
 777
Asset retirement obligation as of end of period44,461
 32,985
Less current portion195
 75
Asset retirement obligation, long-term$44,266
 $32,910
3.EQUITY INVESTMENTS
Investments accounted for by the equity method consist of the following as of September 30, 2017 and December 31, 2016:
   Carrying value 
(Income) loss from equity method investments

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

$243,920

$2,737
 $(5,997) $20,945
 $25,576
(1)
On June 5, 2017, Mammoth Energy Services, Inc. acquired Stingray Cementing LLC, Stingray Energy Services LLC and Sturgeon Acquisitions LLC. See below under Mammoth Energy Partners LP/Mammoth Energy Services, Inc. for information regarding these transactions.
The tables below summarize financial information for the Company’s equity investments as of September 30, 2017 and December 31, 2016.

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

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

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

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The Company accounts for its investment in these VIEs following the equity method of accounting. The carrying amounts of the Company’s equity investments are classified as other non-current assets on the accompanying consolidated balance sheets. The Company’s maximum exposure to loss as a result of its involvement with these VIEs is based on the Company’s capital contributions and the economic performance of the VIEs, and is equal to the carrying value of the Company’s investments which is the maximum loss the Company could be required to record in the consolidated statements of operations. See Note 3 for further discussion of these entities, including the carrying amounts of each investment.
5.LONG-TERM DEBT
Long-term debtDebt consisted of the following items as of SeptemberJune 30, 20172023 and December 31, 2016:
2022 (in thousands):
 September 30, 2017 December 31, 2016
 (In thousands)
Revolving credit agreement (1)$365,000
 $—
7.75% senior unsecured notes due 2020 (2)—
 —
6.625% senior unsecured notes due 2023 (3)350,000
 350,000
6.000% senior unsecured notes due 2024 (4)650,000
 650,000
6.375% senior unsecured notes due 2025 (5)600,000
 600,000
Net unamortized debt issuance costs (6)(30,111) (27,174)
Construction loan (7)23,817
 21,049
Less: current maturities of long term debt(570) (276)
Debt reflected as long term$1,958,136
 $1,593,599
June 30, 2023December 31, 2022
8.0% senior unsecured notes due 2026$550,000 $550,000 
Credit Facility due 202799,000 145,000 
Net unamortized debt issuance costs(733)(845)
Total debt, net648,267 694,155 
Less: current maturities of long-term debt— — 
Total long-term debt, net$648,267 $694,155 
The Company capitalized approximately $2.1 million and $8.8 million in interest expense to undeveloped oil and natural gas properties during the three and nine months ended September 30, 2017, respectively. The Company capitalized approximately $4.7 million and $7.7 million in interest expense to undeveloped oil and natural gas properties during the three and nine months ended September 30, 2016, respectively. During the three and nine months ended September 30, 2016,Credit Facility
On October 14, 2021, the Company also capitalized approximately $0.5 million and $1.2 million, respectively, in interest expense related to building construction. Construction on the building was completed in December 2016 and, as such, the Company did not capitalize any interest expense related to building construction for the three and nine months ended September 30, 2017.
(1) The Company has entered into a senior secured revolving credit facility,the Existing Credit Facility with JPMorgan Chase Bank, N.A., as amended, with The Bank of Nova Scotia, as the lead arranger and administrative agent, and certain lenders from timevarious lender parties. The Existing Credit Facility provided for an aggregate maximum principal amount of up to time party thereto.$1.5 billion. The credit agreementExisting Credit Facility also provides for a maximum facility amount of $1.5 billion and matures on June 6, 2018. On December 13, 2016, the Company further amended its revolving credit facility to, among other things, (a) reset the maturity date to December 31, 2021, (b) adjust lenders, (c) increase the basket for unsecured debt issuances to $1.6 billion, (d) increase the interest rates by 50 basis points, (e) increase the mortgage requirement to 85% (from 80%), and (f) add deposit account control agreement language. On March 29, 2017, the Company further amended its revolving credit facility to, among other things, amend the definition$175.0 million sublimit of the term EBITDAX to permit pro forma treatment of acquisitionsaggregate commitments that involveis available for the payment of consideration by Gulfport and its subsidiaries in excess of $50.0 million and of dispositions of property or series of related dispositions of properties that yields gross proceeds to Gulfport or any of its subsidiaries in excess of $50.0 million. On May 4, 2017, the revolving credit facility was further amended to increase the borrowing base from $700.0 million to $1.0 billion, adjust certain of the Company’s investment baskets and add five additional banks to the syndicate.
As of September 30, 2017, $365.0 million was outstanding under the revolving credit facility and the total availability for future borrowings under this facility, after giving effect to an aggregate of $237.5 millionissuance of letters of credit, was $397.5 million. The Company’s wholly-owned subsidiaries have guaranteed the obligations of the Company under the revolving credit facility.credit.
In connection with the Company's fall redetermination under its revolving credit facility, the lead lenders have proposed to increase the Company'sThe borrowing base from $1.0 million to $1.2 billion, with an elected commitment of $1.0 billion, and decrease the interest rate by 50 basis points, subject to the approval of the additional required banks within the syndicate.
Advances under the revolving credit facility may be in the form of either base rate loansis redetermined semiannually on or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate, which ranges from 1.00% to 2.00%, plus (2) the highest of: (a) the

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federal funds rate plus 0.50%, (b) the rate of interest in effect for such day as publicly announced from time to time by agent as its “prime rate,” and (c) the eurodollar rate for an interest period of one month plus 1.00%. The interest rate for eurodollar loans is equal to (1) the applicable rate, which ranges from 2.00% to 3.00%, plus (2) the London interbank offered rate that appears on pages LIBOR01 or LIBOR02 of the Reuters screen that displays such rate for deposits in U.S. dollars, or, if such rate is not available, the rate as administered by ICE Benchmark Administration (or any other person that takes over administration of such rate) per annum equal to the offered rate on such other page or service that displays on average London interbank offered rate as determined by ICE Benchmark Administration (or any other person that takes over administration of such rate) for deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major New York money center banks of whom the agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. At September 30, 2017, amounts borrowed under the credit facility bore interest at the eurodollar rate (3.74%).
The revolving credit facility contains customary negative covenants including, but not limited to, restrictions on the Company’s and its subsidiaries’ ability to:
•incur indebtedness;
•grant liens;
•pay dividends and make other restricted payments;
•make investments;
•make fundamental changes;
•enter into swap contracts and forward sales contracts;
•dispose of assets;
•change the nature of their business; and
•enter into transactions with affiliates.
The negative covenants are subject to certain exceptions as specified in the revolving credit facility. The revolving credit facility also contains certain affirmative covenants, including, but not limited to the following financial covenants:
(i) the ratio of net funded debt to EBITDAX (net income, excluding (i) any non-cash revenue or expense associated with swap contracts resulting from ASC 815 and (ii) any cash or non-cash revenue or expense attributable to minority investments plus without duplication and, in the case of expenses, to the extent deducted from revenues in determining net income, the sum of (a) the aggregate amount of consolidated interest expense for such period, (b) the aggregate amount of income, franchise, capital or similar tax expense (other than ad valorem taxes) for such period, (c) all amounts attributable to depletion, depreciation, amortization and asset or goodwill impairment or writedown for such period, (d) all other non-cash charges, (e) exploration costs deducted in determining net income under successful efforts accounting, (f) actual cash distributions received from minority investments, (g) to the extent actually reimbursed by insurance, expenses with respect to liability on casualty events or business interruption, and (h) all reasonable transaction expenses related to dispositions and acquisitions of assets, investments and debt and equity offerings (provided that expenses related to any unsuccessful disposition will be limited to $3.0 million in the aggregate) for a twelve-month period may not be greater than 4.00 to 1.00; and
(ii) the ratio of EBITDAX to interest expense for a twelve-month period may not be less than 3.00 to 1.00.
The Company was in compliance with all covenants at September 30, 2017.
(2) On October 17, 2012, the Company issued $250.0 million in aggregate principal amount of 7.75% Senior Notes due 2020 (the “October Notes”) under an indenture among the Company, its subsidiary guarantors and Wells Fargo Bank, National Association, as the trustee (the “senior note indenture”). On December 21, 2012, the Company issued an additional $50.0 million in aggregate principal amount of 7.75% Senior Notes due 2020 (the “December Notes”) as additional securities under the senior note indenture. On August 18, 2014, the Company issued an additional $300.0 million in aggregate principal amount of 7.75% Senior Notes due 2020 (the “August Notes”). The August Notes were issued as additional securities under the senior note indenture. The October Notes, December Notes and the August Notes are collectively referred to as the “2020 Notes.”
In October 2016, the Company repurchased (in a cash tender offer) or redeemed all of the 2020 Notes, of which $600.0 million in aggregate principal amount was then outstanding, with the net proceeds from the issuance of its 6.000% Senior Notes

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due 2024 (the “2024 Notes”) discussed below and cash on hand, and the indenture governing the 2020 Notes was fully satisfied and discharged.
(3) On April 21, 2015, the Company issued $350.0 million in aggregate principal amount of 6.625% Senior Notes due 2023 (the “2023 Notes”) to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act (the “2023 Notes Offering”). The Company received net proceeds of approximately $343.6 million after initial purchaser discounts and commissions and estimated offering expenses.
The 2023 Notes were issued under an indenture, dated as of April 21, 2015, among the Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee. In October 2015, the 2023 Notes were exchanged for a new issue of substantially identical debt securities registered under the Securities Act. Pursuant to the indenture relating to the 2023 Notes, interest on the 2023 Notes accrues at a rate of 6.625% per annum on the outstanding principal amount thereof, payable semi-annually onaround May 1 and November 1 of each year.

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On May 2, 2022, the Company completed its semi-annual borrowing base redetermination and entered into the Amendment to Borrowing Base Redetermination Agreement and First Amendment to our Credit Agreement, which amended the Existing Credit Facility. The amendment, among other things, (a) increased the borrowing base under the Credit Facility from $850 million to $1.0 billion with the elected commitments remaining at $700 million, (b) amended certain covenants related to hedging to ease certain requirements and limitations, (c) amended the covenants governing restricted payments to (i) increase the Net Leverage Ratio allowing unlimited restricted payments from 1.00 to 1.00 to 1.25 to 1.00 and (ii) permit additional restricted payments to redeem preferred equity until December 31, 2022 provided certain leverage, no event of default or borrowing base deficiency and availability tests were met, and (d) provided for the transition from a LIBOR to a SOFR benchmark, with a 10 basis point credit spread adjustment for all tenors.
On October 31, 2022, the Company completed its semi-annual borrowing base redetermination and entered into the Borrowing Base Reaffirmation Agreement and Second Amendment to our Credit Agreement, which amended the Existing Credit Facility. The amendment, among other things, reconfirmed the borrowing base under the Credit Facility at $1.0 billion and the elected commitments at $700 million.
On May 1, 2023, the Company entered into that certain Joinder, Commitment Increase and Borrowing Base Redetermination Agreement, and Third Amendment to Credit Agreement (the “Third Amendment”) which amended the Company’s Existing Credit Facility (as amended, the “Credit Facility”). The Third Amendment, among other things, (a) increased the aggregate elected commitment amounts under the Credit Facility from $700 million to $900 million, (b) increased the borrowing base under the Credit Facility from $1 billion to $1.1 billion, (c) increased the excess cash threshold under the Credit Facility from $45 million to $75 million, and (d) extended the maturity date under the Credit Facility from October 14, 2025 to the earlier of (i) May 1, 2027 and (ii) the 91st day prior to the maturity date of the 2026 Senior Notes or any other permitted senior notes or any permitted refinancing debt under the Credit Facility having an aggregate outstanding principal amount equal to or exceeding $100 million; provided that such notes have not be refinanced, redeemed or repaid in full on or prior to such 91st day.
The Credit Facility bears interest at a rate equal to, at the Company’s election, either (a) SOFR benchmark 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 Company is required to pay a commitment fee of 0.50% per annum on the average daily unused portion of the current aggregate commitments under the Credit Facility. The Company is also required to pay customary letter of credit and fronting fees.
The Credit Facility requires the Company to maintain 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 Credit Facility, certain swap obligations and certain cash management obligations, are not guaranteed by Grizzly Holdings, Inc.the Company and will not be guaranteed by anythe wholly-owned domestic material subsidiaries of the Company’s future unrestricted subsidiaries.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).
(4) The Credit Facility also contains customary affirmative and negative covenants, including, among other things, as to compliance with laws (including environmental laws and anti-corruption laws), delivery of quarterly and annual financial statements and borrowing base certificates, conduct of business, maintenance of property, maintenance of insurance, 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 a number of limitations and exceptions.
As of June 30, 2023, the Company had $99.0 million outstanding borrowings under the Credit Facility, $74.4 million in letters of credit outstanding and was in compliance with all covenants under the credit agreement.
For the three and six months ended June 30, 2023, the Credit Facility bore interest at a weighted average rate of 8.13% and 7.85%, respectively.
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2026 Senior Notes
On October 14, 2016,the Emergence Date, pursuant to the terms of the Plan, the Company issued the 2024 Notes in$550 million aggregate principal amount of $650.0 million.its 8.0% senior notes due 2026. The 2024notes are guaranteed on a senior unsecured basis by each of the Company's subsidiaries that guarantee the Credit Facility. Interest on the 2026 Senior Notes is payable semi-annually, on June 1 and December 1 of each year. The 2026 Senior Notes were issued under an indenture,the Indentures, dated as of October 14, 2016,May 17, 2021, by and among the Company, the subsidiary guarantors party theretoIssuer, UMB Bank, National Association, as trustee, and the senior note indenture trustee (the “2024 Indenture”),Guarantors and mature on May 17, 2026.
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 qualified institutional buyers pursuant(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 2026 Senior Notes are rated investment grade, certain covenants will be terminated and cease to Rule 144A underapply.
Capitalization of Interest
The Company capitalized $1.0 million and $1.8 million in interest expense for the Securities Actthree and to certain non-U.S. persons in accordance with Regulation S undersix months ended June 30, 2023, respectively. The Company did not capitalize interest expense for the Securities Act (the “2024three and six months ended June 30, 2022.
Fair Value of Debt
At June 30, 2023, the carrying value of the outstanding debt represented by the 2026 Senior Notes Offering”). Under the 2024 Indenture, interestwas $549.3 million. Based on the 2024quoted market prices (Level 1), the fair value of the 2026 Senior Notes accrueswas determined to be $554.3 million at June 30, 2023.
4.MEZZANINE EQUITY
On the Emergence Date, the Company filed an amended and restated certificate of incorporation with the Delaware Secretary of State to provide for, among other things, (i) the authority to issue 42 million shares of common stock with a par value of $0.0001 per share and (ii) the designation of 110,000 shares of preferred stock, with a par value of $0.0001 per share and a liquidation preference of $1,000 per share (the "Liquidation Preference").
Preferred Stock
On the Emergence Date, the Successor issued 55,000 shares of preferred stock.
Holders of preferred stock are entitled to receive cumulative quarterly dividends at a rate of 6.000%10% per annum on the outstanding principal amount thereof from October 14, 2016, payable semi-annually on April 15 and October 15 of each year, commencing on April 15, 2017. The 2024 Notes will mature on October 15, 2024. The Company received approximately $638.9 million in net proceeds from the offering of the 2024 Notes, which was used, togetherLiquidation Preference with respect to cash on hand,dividends and 15% per annum of the Liquidation Preference with respect to purchasedividends paid in kind as additional shares of preferred stock (“PIK Dividends”). Gulfport currently has the outstanding 2020 Notes in a concurrent cash tender offer,option to pay feeseither cash dividends or PIK Dividends on a quarterly basis.
Each holder of shares of preferred stock has the right (the “Conversion Right”), at its option and expenses thereof, andat any time, to redeem any of the 2020 Notes that remained outstanding after the completion of the tender offer.
(5) On December 21, 2016, the Company issued $600.0 million in aggregate principal amount of 6.375% Senior Notes due 2025 (the “2025 Notes”). The 2025 Notes were issued under an indenture, dated as of December 21, 2016, among the Company, the subsidiary guarantors party thereto and the senior note indenture trustee (the “2025 Indenture”), to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. Under the 2025 Indenture, interest on the 2025 Notes accrues atconvert all or a rate of 6.375% per annum on the outstanding principal amount thereof from December 21, 2016, payable semi-annually on May 15 and November 15 of each year, commencing on May 15, 2017. The 2025 Notes will mature on May 15, 2025. The Company received approximately $584.7 million in net proceeds from the offering of the 2025 Notes, which was used, together with the net proceeds from the Company’s December 2016 common stock offering and cash on hand, to fund the cash portion of the purchase priceshares of 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 shares of preferred stock outstanding at June 30, 2023 would convert to approximately 3.3 million shares of common stock if all holders of preferred stock exercised their Conversion Right.
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Gulfport shall have the right, but not the obligation, to redeem all, but not less than all, of the outstanding shares of preferred stock by notice to the holders of preferred stock, at the greater of (i) the aggregate value of the 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 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 preferred stock by cash payment of the Redemption Price per share of 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 preferred stock, the Company is required to redeem a pro rata portion of each holder’s shares of preferred stock.
The preferred stock has no stated maturity and will remain outstanding indefinitely unless repurchased or redeemed by Gulfport or converted into common stock.
The preferred stock has been classified as mezzanine equity in the accompanying consolidated balance sheets due to the redemption features noted above.
Dividends and Conversions
During the three and six months ended June 30, 2023, the Company paid $1.3 million and $2.6 million, respectively, of cash dividends to holders of our preferred stock.
The following table summarizes activity of the Company’s preferred stock for the Vitruvian Acquisition. See “Note 1 – Acquisitions” for additional discussion of the Vitruvian Acquisition.
(6) In accordance with ASU 2015-03, loan issuance costs related to the 2023 Notes, the 2024 Notes and the 2025 Notes (collectively the “Notes”) have been presented as a reduction to the Notes. At September 30, 2017, total unamortized debt issuance costs were $5.5 million for the 2023 Notes, $10.2 million for the 2024 Notes and $14.3 million for the 2025 Notes. In addition, loan commitment fee costs for the construction loan agreement described immediately below were $0.1 million at September 30, 2017.
(7) On June 4, 2015, the Company entered into a construction loan agreement (the “Construction Loan”) with InterBank for the construction of a new corporate headquarters in Oklahoma City, which was substantially completed in December 2016. The Construction Loan allows for maximum principal borrowings of $24.5 million and required the Company to fund 30% of the cost of the construction before any funds could be drawn, which occurred in January 2016. Interest accrues daily on the outstanding principal balance at a fixed rate of 4.50% per annum and was payable on the last day of the month through May 31, 2017. Monthly interest and principal payments are due beginningsix months ended June 30, 2017, with the final payment due June 4, 2025. At September 30, 2017, the total borrowings under the Construction Loan were approximately $23.8 million.2023:
Preferred stock at December 31, 202252,295 
6.Conversion of preferred stockCOMMON STOCK AND CHANGES IN CAPITALIZATION(5,836)
Preferred stock at June 30, 202346,459 
Issuance
5.EQUITY
On the Emergence Date, the Company filed an amended and restated certificate of incorporation with the Delaware Secretary of State to provide for, among other things, (i) the authority to issue 42 million shares of common stock with a par value of $0.0001 per share and (ii) the designation of 110,000 shares of preferred stock, with a par value of $0.0001 per share and a Liquidation Preference of $1,000 per share.
Common Stock
On March 15, 2016, the CompanyEmergence Date, Gulfport issued 16,905,000approximately 19.8 million shares of common stock and 1.7 million shares of common stock were issued to the Disputed Claims Reserve.
In January 2022, approximately 876,000 shares in the Disputed Claims Reserve at December 31, 2021 were issued to certain claimants. As of June 30, 2023, approximately 62,000 shares continue to be held in the Disputed Claims Reserve and may be issued upon finalization of remaining claims.




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Common Stock Offering
On June 26, 2023, Gulfport completed an underwritten public offering of 1.5 million shares of its common stock in an underwrittenby certain stockholders at a price to the public of $95.00 per share. Gulfport did not sell any of its common stock as part of this offering (which included 2,205,000and did not receive any proceeds from the sale of the shares sold pursuantby the selling stockholders.
Concurrent with the closing of the offering, Gulfport purchased 263,158 shares of its common stock at $95.00 per share. The repurchase is part of the Company's existing $400 million share repurchase program discussed below.
Share Repurchase Program
In November 2021 the Company's Board of Directors approved the Repurchase Program to acquire up to $100 million of common stock and subsequently increased the authorization to $300 million, extending through June 30, 2023. On February 27, 2023, the Board of Directors approved an optionincrease to the authorization up to $400 million. The additional $100 million authorization expires on March 31, 2024. 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 Company to acquire any specific number of shares of common stock. The Company intends to purchase shares sold pursuantunder the Repurchase Program with available funds while maintaining sufficient liquidity to an optionfund its capital development program. The Repurchase Program may be suspended from time to purchase additionaltime, modified, extended or discontinued by the Board of Directors at any time.
The following table summarizes activity under the Repurchase Program for the six months ended June 30, 2023 (number of shares and dollar value of shares purchased shown in thousands):

Total Number of Shares PurchasedDollar Value of Shares PurchasedAverage Price Paid Per Share
First quarter 2023459 $32,873 $71.61 
Second quarter 2023442 41,358 93.67 
Total901 $74,231 $82.42 
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6.STOCK-BASED COMPENSATION

As of the Company’s common stock granted byEmergence Date, the CompanyBoard of Directors adopted the Incentive Plan with a share reserve equal to and exercised in full by, the underwriters). The net proceeds from this equity offering were approximately $411.7 million, after underwriting discounts and commissions and offering expenses. The Company used the net proceeds from this offering primarily to fund a portion of its 2017 capital development plan and for general corporate purposes.
On February 17, 2017, the Company completed the Vitruvian Acquisition for a total initial purchase price of approximately $1.85 billion, consisting of $1.35 billion in cash, subject to certain adjustments, and approximately 23.92.8 million shares of common stock. The Incentive Plan provides for the Company’s commongrant of incentive stock (of which approximately 5.2 million shares are subjectoptions, 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 both restricted stock units and performance vesting restricted stock units to employees and directors pursuant to the indemnity escrow). See “Note 1 - Acquisitions” for additional discussion of the Vitruvian Acquisition.
7.STOCK-BASED COMPENSATION
Incentive Plan, as discussed below. During the three and ninesix months ended SeptemberJune 30, 2017,2023, the Company’sCompany's stock-based compensation costexpense was $2.8$3.0 million and $8.0$5.6 million, respectively, of which the Company capitalized $1.1$1.0 million and $3.2$1.9 million, respectively, relating to its exploration and development efforts. During the three and ninesix months ended SeptemberJune 30, 2016,2022, the Company's stock-based compensation costexpense was $3.0$2.1 million and $9.6$3.9 million, respectively, of which the Company capitalized $1.2$0.7 million and $3.8$1.3 million, respectively, 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. As of June 30, 2023, the Company has awarded an aggregate of approximately 362,572 restricted stock units and approximately 274,624 performance vesting restricted stock units under the Incentive Plan.
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The following tabletables summarizes restricted stock activity for the ninesix months ended SeptemberJune 30, 2017:2023 and 2022:
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, 2023197,772 $77.49 190,804 $52.15 
Granted43,415 77.84 68,726 56.57 
Vested(11,608)70.86 — — 
Forfeited/canceled(971)87.68 (5,069)47.67 
Unvested shares as of March 31, 2023228,608 $77.85 254,461 $53.43 
Granted55,041 94.53 15,094 66.66 
Vested(43,088)86.28 — — 
Forfeited/canceled(1,401)89.08 (10,731)50.69 
Unvested shares as of June 30, 2023239,160 $80.10 258,824 $54.32 
 
Number of
Unvested
Restricted Shares
 
Weighted
Average
Grant Date
Fair Value
Unvested shares as of January 1, 2017613,056
 $32.90
Granted870,358
 15.15
Vested(399,843) 28.77
Forfeited(74,024) 30.45
Unvested shares as of September 30, 20171,009,547
 $19.42
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, 2022198,413 $66.04 153,138 $48.54 
Granted2,154 73.83 — — 
Vested(3,074)65.75 — — 
Forfeited/canceled(1,157)66.89 — — 
Unvested shares as of March 31, 2022196,336 $67.16 153,138 $48.54 
Granted76,038 97.55 37,666 66.82 
Vested(10,817)63.53 — — 
Forfeited/canceled(3,752)75.70 — — 
Unvested shares as of June 30, 2022257,805 $75.37 190,804 $52.15 
Restricted Stock Units
Restricted stock units awarded under the Incentive Plan generally vest over a period of 3 or 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 SeptemberJune 30, 2017 related to restricted shares2023, was $17.2$15.7 million. The expense is expected to be recognized over a weighted average period of 1.612.23 years.

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 at the end of a three-year performance period, subject to earlier termination of the performance period in the event of a change in control. The grant date fair values were determined using the Monte Carlo simulation method and are being recorded ratably over the performance period.
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The table below summarizes the assumptions used in the Monte Carlo simulation to determine the grant date fair value of awards granted during the six months ended June 30, 2023:
8.EARNINGS PER SHARE
Grant dateJanuary 24, 2023March 3, 2023April 3, 2023
Forecast period (years)333
Risk-free interest rates3.88%4.64%3.79%
Implied equity volatility87.2%86.4%70.8%
Stock price on the date of grant$72.99$82.20$79.50
Unrecognized compensation expense as of June 30, 2023, related to performance vesting restricted shares was $7.4 million. The expense is expected to be recognized over a weighted average period of 1.99 years.
7.RESTRUCTURING COSTS
During the three and six months ended June 30, 2023, Gulfport recognized $2.9 million and $4.8 million, respectively, in personnel-related restructuring expenses associated with changes in the organizational structure and leadership team resulting from the appointment of Gulfport's new CEO in January 2023. Of these expenses, $0.8 million and $1.3 million, for the three and six months ended June 30, 2023, respectively, resulted from accelerated vesting of certain share-based grants, which are non-cash charges. As of June 30, 2023, there were no remaining employee termination liabilities for the impacted employees.
8.EARNINGS (LOSS) PER SHARE
Basic income or loss per share attributable to common stockholders is computed as (i) net income or loss less (ii) dividends paid to holders of preferred stock less (iii) net income or loss attributable to participating securities divided by (iv) weighted average basic shares outstanding. Diluted net income or loss per share attributable to common 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 preferred stock and the treasury stock method is used to determine the dilutive impact of unvested restricted stock.
There were 0.3 million and 0.2 million shares of restricted stock that were considered dilutive for the three and six months ended June 30, 2023, respectively. There were 0.2 million shares of restricted stock that were considered dilutive for the three months ended June 30, 2022. There were no shares of restricted stock that were considered dilutive for the six months ended June 30, 2022. There were 3.3 million potential shares of common stock issuable due to the Company's convertible preferred stock for each of the three and six months ended June 30, 2023. There were 3.8 million potential shares of common stock issuable due to the Company's convertible preferred stock for each of the three and six months ended June 30, 2022. There were 0.2 million shares of restricted stock that were considered anti-dilutive during the six months ended June 30, 2022.
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Reconciliations of the components of basic and diluted net income (loss) per common share are presented in the tables below:
below (in thousands):
Three Months Ended June 30, 2023Three Months Ended June 30, 2022
Net income$93,687 $256,580 
Dividends on preferred stock(1,278)(1,380)
Participating securities - preferred stock(1)
(14,044)(39,590)
Net income attributable to common stockholders$78,365 $215,610 
Re-allocation of participating securities182 310 
Diluted net income attributable to common stockholders$78,547 $215,920 
Basic Shares18,518 20,684 
Dilutive Shares18,805 20,877 
Basic EPS$4.23 $10.42 
Dilutive EPS$4.18 $10.34 
_____________________
 Three months ended September 30,
 2017 2016
 Income Shares 
Per
Share
 (Loss) Shares 
Per
Share
 (In thousands, except share data)
Basic:           
Net income (loss)$18,235
 182,957,416
 $0.10
 $(157,296) 125,408,866
 $(1.25)
Effect of dilutive securities:
 
 
 
 
 
Stock options and awards—
 51,020
 
 —
 —
 
Diluted:
 —
 
 
 0 
Net income (loss)$18,235
 183,008,436
 $0.10
 $(157,296) 125,408,866
 $(1.25)
            
            
 Nine months ended September 30,
 2017 2016
 Income Shares Per
Share		 (Loss) Shares Per
Share
 (In thousands, except share data)
Basic:           
Net income (loss)$278,626
 178,736,569
 $1.56
 $(739,339) 120,771,046
 $(6.12)
Effect of dilutive securities:
 
 
 
 
 
Stock options and awards—
 394,001
 
 —
 —
 
Diluted:
 —
 
 
 —
 
Net income (loss)$278,626
 179,130,570
 $1.56
 $(739,339) 120,771,046
 $(6.12)
There were 603,068 and 598,753(1)    Preferred stock represents participating securities because it participates in any dividends on shares of common stock that were considered anti-dilutiveon a pari passu, pro rata basis. However, preferred stock does not participate in undistributed net losses.
Six Months Ended June 30, 2023Six Months Ended June 30, 2022
Net income (loss)$616,741 $(235,395)
Dividends on preferred stock(2,585)(2,828)
Participating securities - preferred stock(1)
(92,611)— 
Net income (loss) attributable to common stockholders$521,545 $(238,223)
Re-allocation of participating securities1,008 — 
Diluted net income (loss) attributable to common stockholders$522,553 $(238,223)
Basic Shares18,688 20,961 
Dilutive Shares18,930 20,961 
Basic EPS$27.91 $(11.36)
Dilutive EPS$27.60 $(11.36)
_____________________
(1)    Preferred stock represents participating securities because it participates in any dividends on shares of common stock on a pari passu, pro rata basis. However, preferred stock does not participate in undistributed net losses.
9.COMMITMENTS AND CONTINGENCIES
Commitments
Future Firm Transportation and Gathering Agreements
    The Company has contractual commitments with midstream and pipeline companies for future gathering and transportation of natural gas from the three monthsCompany'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 nine months ended September 30, 2016, respectively.


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, costs associated with utilized future firm transportation and gathering agreements are reflected in the Company's estimates of proved reserves.
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9.COMMITMENTS AND CONTINGENCIES
Plugging and Abandonment FundsA summary of these commitments at June 30, 2023, are set forth in the table below (in thousands):
In connection with the Company’s acquisition in 1997 of the remaining 50% interest in its WCBB properties, the Company assumed the seller’s (Chevron) obligation to contribute approximately $18,000 per month through March 2004 to a plugging and abandonment trust and the obligation to plug a minimum of 20 wells per year for 20 years commencing March 11, 1997. Chevron retained a security interest in production from these properties until the Company’s abandonment obligations to Chevron have been fulfilled. Beginning in 2009, the Company could access the trust for use in plugging and abandonment charges associated with the property, although it has not yet done so. As of September 30, 2017, the plugging and abandonment trust totaled approximately $3.1 million. At September 30, 2017, the Company had plugged 551 wells at WCBB since it began its plugging program in 1997, which management believes fulfills its minimum plugging obligation.
Remaining 2023$113,028 
2024218,797 
2025137,795 
2026134,324 
2027136,492 
Thereafter737,104 
Total$1,477,540 
Operating Leases
The Company leases office facilities under non-cancellable operating leases exceeding one year. Future minimum lease commitments under these leases at September 30, 2017 were as follows:
  (In thousands)
Remaining 2017 $27
2018 54
Total $81
Firm TransportationOther Operational Commitments
The Company hadentered into various contractual commitments to purchase inventory and other material to be used in future activities. The Company's commitment to purchase these materials spans 2023 and 2024, with approximately 3,077,000 MMBtu per day$39.6 million remaining in 2023 and $31.2 million for 2024.
Contingencies
Litigation and Regulatory Proceedings
As part of firm sales contracted with third parties. The table below presents these commitments at September 30, 2017 as follows:
  (MMBtu per day)
Remaining 2017 710,000
2018 561,000
2019 659,000
2020 526,000
2021 372,000
Thereafter 249,000
Total 3,077,000
Theits Chapter 11 Cases and restructuring efforts, the Company also had approximately $3.7 billion offiled motions to reject certain firm transportation contractedagreements between the Company and affiliates of TC Energy Corporation ("TC") and Rover Pipeline LLC ("Rover"). During the third quarter of 2021, Gulfport finalized a settlement agreement with third parties.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 them would be rejected without any further payment or obligation by either party, 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 table below presents these commitments at September 30, 2017 as follows:$43.8 million was paid on October 7, 2021. Gulfport expects to receive distributions for a significant portion of such amounts through future distributions with respect to the assigned claims pursuant to the terms of the Plan that became effective in May 2021. Any future distributions will be recognized once received by Gulfport. In February 2022, Gulfport received an initial distribution of $11.5 million from the above-mentioned claim, which is included in Other, net in the accompanying consolidated statements of operations.
During the first quarter of 2023, Gulfport finalized a settlement agreement with Rover that was approved by the Bankruptcy Court on February 21, 2023. Pursuant to the settlement agreement, Gulfport and Rover agreed that the firm transportation contracts between them would be rejected. The Bankruptcy Court Order provided Rover will: (a) receive an allowed $85.9 million Class 4A General Unsecured Claim (the “Rover Unsecured Claim”), (b) receive an administrative claim of $1.0 million payable by Gulfport, and (c) draw the full amount of its credit assurance. Gulfport paid the $1.0 million administrative claim during the first quarter, and has no further obligations to Rover. The Rover Unsecured Claim will receive distributions under the Plan payable from the liquidating trust, not Gulfport. On February 24, 2023, Gulfport received an additional $17.8 million interim distribution for its TC claim. The timing and amount of any future distributions to Gulfport are not certain, and the total amount received will be impacted by the liquidating trust’s distributions and resolution of other remaining bankruptcy claims. These payments are included in Other, net in the accompanying consolidated statements of operations.
20
  (In thousands)
Remaining 2017 $49,052
2018 238,767
2019 243,389
2020 240,746
2021 239,786
Thereafter 2,715,005
Total $3,726,745


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Other Commitments
Effective October 1, 2014, the Company entered into a Sand Supply Agreement with Muskie Proppant LLC (“Muskie”), a subsidiary of Mammoth Energy, that expires on September 30, 2018. Pursuant to this agreement, as amended, theThe Company has agreed to purchase annual and monthly amounts of proppant sand subject to exceptions specified in the agreement at agreed pricing plus agreed costs and expenses. Failure by either Muskie or the Company to deliver or accept the minimum monthly amount results in damages calculated per ton based on the difference between the monthly obligation amount and the amount actually delivered or accepted, as applicable. The Company incurred $0.2 million and $2.1 million related to non-utilization fees during the three months and nine months ended September 30, 2016, respectively. The Company did not incur any non-utilization fees during the three and nine months ended September 30, 2017.
Effective October 1, 2014, the Company entered into an Amended and Restated Master Services Agreement for pressure pumping services with Stingray Pressure Pumping LLC (“Stingray Pressure”), a subsidiary of Mammoth Energy, that expires on September 30, 2018. Pursuant to this agreement, as amended, Stingray Pressure has agreed to provide hydraulic fracturing, stimulation and related completion and rework services to the Company and the Company has agreed to pay Stingray Pressure a monthly service fee plus the associated costs of the services provided.
Future minimum commitments under these agreements at September 30, 2017 are as follows:
  (In thousands)
Remaining 2017 $13,110
2018 39,330
Total $52,440
Litigation
In two separate complaints, one filed by the State of Louisiana and the Parish of Cameron in the 38th Judicial District Court for the Parish of Cameron on February 9, 2016 and the other filed by the State of Louisiana and the District Attorney for the 15th Judicial District of the State of Louisiana in the 15th Judicial District Court for the Parish of Vermillion on July 29, 2016, the Company wasbeen named as a defendant among 26in three separate complaints, two filed by Siltstone Resources, LLC, and the third filed by the Ohio Public Works Commission (OPWC) (together, the "Complaints"). The Complaints all arise from restrictive covenants in favor of OPWC generally prohibiting any transfer and any use inconsistent with a green park space. OPWC filed crossclaims against Gulfport in the Siltstone matters alleging that the transfer of the mineral rights and the development of oil and gas on the property violated these restrictive covenants. On June 19, 2018, October 25, 2019, and March 15, 2019, each trial court in the Complaints entered judgment in favor of the Company and other defendants, finding the restrictive covenants only applied to the surface estate. OPWC appealed each judgement to the respective Ohio Courts of Appeal where the trial court decisions were reversed in favor of OPWC. The Company and certain other parties to the Complaints appealed the appellate court decisions to the Ohio Supreme Court. On February 23, 2022, the Ohio Supreme Court affirmed the first appellate decision and remanded the case back to the trial court. On December 27, 2022, the Ohio Supreme Court affirmed the other two complaints and remanded the matters back to the trial court. OPWC is seeking both injunctive relief to enforce the restrictive covenants and equitable relief. Liquidated damages were successfully discharged in the Company’s Chapter 11 proceedings through May 17, 2021. On July 18, 2023, OPWC filed a notice with the court stating that it will no longer be pursuing claims for injunctive relief.
The Company, along with other oil and gas companies, have been named as a defendant in a number of lawsuits where Plaintiffs assert their respective leases are limited to the Cameron Parish complaintMarcellus and among more than 40 oil and gas companies in the Vermillion Parish complaint, or the Complaints. The Complaints were filed under the State and Local Coastal Resources Management Act of 1978, as amended, and the rules, regulations, orders and ordinances adopted thereunder, which the Company referred to collectively as the CZM Laws,Utica shale geological formations and allege that certainDefendants have willfully trespassed and illegally produced oil, natural gas, and other hydrocarbon products beyond these respective formations. Plaintiffs seek the full value of any production from below the defendants’ oilMarcellus and gas exploration, production and transportation operations associated withUtica shale formations, unspecified damages from the developmentdiminution of the East Hackberry and West Hackberry oil and gas fields, in the case of the Cameron Parish complaint, and the Tigre Lagoon and Lac Blanc oil and gas fields, in the case of the Vermillion Parish complaint, were conducted in violation of the CZM Laws. The Complaints allege that such activities caused substantial damage to land and waterbodies located in the coastal zone of the relevant Parish, including due to defendants’ design, construction and use of waste pits and the alleged failure to properly close the waste pits and to clear, re-vegetate, detoxify and return the property affected to its original condition, as well as the defendants’ alleged discharge of waste into the coastal zone. The Complaints also allege that the defendants’ oil and gas activities have resulted in the dredging of numerous canals, which had a direct and significant impact on the state coastal waters within the relevant Parish and that the defendants, among other things, failed to design, construct and maintain these canals using the best practical techniques to prevent bank slumping, erosion and saltwater intrusion and to minimize the potential for inland movement of storm-generated surges, which activities allegedly have resulted in the erosion of marshes and the degradation of terrestrial and aquatic life therein. The Complaints also allege that the defendants failed to re-vegetate, refill, clean, detoxify and otherwise restore these canalsvalue to their original condition. In these two petitions, the plaintiffs seekmineral estate, unspecified punitive damages, and other appropriate relief under the CZM Laws, including the payment of costs necessary to clear, re-vegetate, detoxify and otherwise restore the affected coastal zone of the relevant Parish to its original condition, actual restoration of such coastal zone to its original condition, and the payment of reasonable attorney fees, and legal expenses, and pre-judgment and post judgment interest. On April 27, 2021, the Bankruptcy Court for the Southern District of Texas approved a settlement agreement in which the plaintiffs fully released the Company from all claims for amounts allegedly owed to the plaintiffs through the effective date of the Company’s Chapter 11 plan, which occurred on May 17, 2021. The plaintiffs are continuing to pursue alleged damages after May 17, 2021.
Business Operations
The Company was served with the Cameron complaintis involved in early May 2016various lawsuits and with the Vermillion complaint in early September 2016.  The Louisiana Attorney Generaldisputes incidental to its business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and the Louisiana Department of Natural Resources intervened in both the Cameron Parish suit and the Vermillion Parish suit.  Shortly after the Complaints were filed, certain defendants removed the cases to the lawsuit to the United States District Court for the Western District of Louisiana.  In both cases, the plaintiffs filed a motion to remand, and the plaintiffs agreed to an extension of time for all defendants to file responsive pleadings until the District Courts ruled on the motions to remand.  In the Vermilion Parish case, the District Court entered an order on September 26, 2017 remanding the lawsuit to the 15th Judicial District Court, State of Louisiana, Parish of Vermilion.  Pursuant to ancontract actions.

Environmental Contingencies
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agreement with plaintiffs’ counsel, all defendants have an extension of time through November 27, 2017 to file responsive pleadings to plaintiffs’ petitions in the Vermilion Parish lawsuit.  In the Cameron Parish lawsuit, the District Court has not ruled on plaintiffs’ motion to remand.  Briefing on the motion to remand has been completed; however, no hearing has been set for the motion to remand, and the District Court has not given the parties any indication regarding when a ruling should be expected. Due the procedural posture of lawsuits, the fact that responsive pleadings have not been filed and the fact that the parties have not begun discovery, the Company has not had the opportunity to evaluate the applicability of the allegations made in plaintiffs' complaints to the Company's operations and management cannot determine the amount of loss, if any, that may result.
In addition, due to theThe nature of the Company’soil and gas business carries with it is,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. The Company conducts periodic reviews, on a company-wide basis, to assess changes in its 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, it may, among other things, exclude a property from timethe transaction, require the seller to time, involvedremediate the property to its satisfaction in routine litigationan acquisition or subjectagree to disputesassume liability for the remediation of the property.
Other Matters
Based on management’s current assessment, they are of the opinion that no pending or claims relatedthreatened lawsuit or dispute relating to its business activities, including workers’ compensation claims and employment related disputes. In the opinion of the Company’s management, none of the pending litigation, disputes or claims against the Company, if decided adversely, willoperations is likely to have a material adverse effect on itstheir future consolidated financial condition, cash flows orposition, results of operations.operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.
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10.DERIVATIVE INSTRUMENTS

10.DERIVATIVE INSTRUMENTS
Natural Gas, Oil and Natural Gas LiquidsNGL Derivative Instruments
The Company seeks to reduce its exposuremitigate risks related to unfavorable changes in natural gas, oil and natural gas liquidsNGL prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps, costless collars and various types of option contracts. These contracts allow the Company to predict with greater certaintymitigate the effectiveimpact of declines in future natural gas, oil and natural gas liquidsNGL prices to be receivedby effectively locking in a floor price for hedged production anda certain level of the Company’s production. However, these hedge contracts also limit the benefit operating cash flows and earnings when market prices are less than the fixed prices provided in the contracts. However,to the Company will not benefit fromin periods of favorable price movements.
The volume of production subject to commodity derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market prices that are higher than the fixed pricesconditions. Gulfport may enter into commodity derivative contracts up to limitations set forth in theits Credit Facility.The Company generally enters into commodity derivative contracts for hedged production.approximately 30% to 70% of its forecasted current year annual production by the end of the first quarter of each fiscal year. The Company typically enters into commodity derivative contracts for the next 12 to 36 months. Gulfport does not enter into commodity derivative contracts for speculative purposes.
The Company does not currently have any commodity derivative transactions that have margin requirements or collateral provisions that would require payments prior to the scheduled settlement dates. The Company's commodity derivative contract counterparties are typically financial institutions and energy trading firms with investment-grade credit ratings. Gulfport routinely monitors and manages its exposure to counterparty risk by requiring specific minimum credit standards for all counterparties, actively monitoring counterparties' public credit ratings and avoiding the concentration of credit exposure by transacting with multiple counterparties. The Company has master netting agreements with some counterparties that allow the offsetting of receivables and payables in a default situation.
Fixed price swaps require that the Company receive a fixed price and pay a floating market price to the counterparty for the hedged community. They 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 theseCompany has entered into natural gas, crude oil and NGL fixed price swaps areswap contracts based onoff the NYMEX Henry Hub, for natural gas, Argus Louisiana Light Sweet Crude for oil, the NYMEX West Texas Intermediate for oil,WTI and Mont Belvieu for propane and pentane.C3 indices. Below is a summary of the Company’s open fixed price swap positions as of SeptemberJune 30, 2017.2023.
IndexDaily VolumeWeighted
Average Price
Natural Gas(MMBtu/d)($/MMBtu)
Remaining 2023NYMEX Henry Hub250,000 $4.12 
2024NYMEX Henry Hub304,973 $4.08 
2025NYMEX Henry Hub110,000 $4.09 
Oil(Bbl/d)($/Bbl)
Remaining 2023NYMEX WTI3,000 $74.47 
NGL(Bbl/d)($/Bbl)
Remaining 2023Mont Belvieu C33,000 $38.07 
22
 LocationDaily Volume (MMBtu/day) Weighted
Average Price
Remaining 2017NYMEX Henry Hub765,000
 $3.19
2018NYMEX Henry Hub898,000
 $3.06
2019NYMEX Henry Hub112,000
 $3.01
 LocationDaily Volume
(Bbls/day)		 Weighted
Average Price
Remaining 2017ARGUS LLS1,500
 $53.12
2018ARGUS LLS1,000
 $53.91
Remaining 2017NYMEX WTI4,500
 $54.89
2018NYMEX WTI3,000
 $52.24
 LocationDaily Volume
(Bbls/day)		 Weighted
Average Price
Remaining 2017Mont Belvieu C33,000
 $26.63
2018Mont Belvieu C33,500
 $28.03
Remaining 2017Mont Belvieu C5250
 $49.14
2018Mont Belvieu C5500
 $46.62

21


Each two-way price costless collar has a set floor and ceiling price for the hedged production. They are settled monthly based on differences between the floor and ceiling prices specified in the contract and the referenced settlement price. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the collar contracts, the Company will cash-settle the difference with the hedge counterparty. When the referenced settlement price is less than the floor price in the contract, the Company receives an amount from the counterparty based on the price difference multiplied by the hedged contract volume. Similarly, when the referenced settlement price exceeds the ceiling price specified in the contract, the Company pays the counterparty an amount based on the price difference multiplied by the hedged contract volume. No payment is due from either party if the referenced settlement price is within the range set by the floor and ceiling prices.
The Company has entered into natural gas costless collars based off the NYMEX Henry Hub natural gas index. Below is a summary of the Company's costless collar positions as of June 30, 2023.
IndexDaily VolumeWeighted Average Floor PriceWeighted Average Ceiling Price
Natural Gas(MMBtu/d)($/MMBtu)($/MMBtu)
Remaining 2023NYMEX Henry Hub285,000 $2.93 $4.78 
2024NYMEX Henry Hub180,000 $3.43 $5.49 
2025NYMEX Henry Hub60,000 $3.67 $4.65 
From time to time, the Company has sold natural gas call options in exchange for a premium, and used the associated premiums received to enhance the fixed price for a portion of the fixed price natural gas swaps listed above.swaps. Each shortsold call option has an established ceiling price. WhenIf at the time of settlement the referenced settlement price is aboveexceeds the price ceiling established by these short call options,price, the Company pays its counterparty an amount equal to the difference between the referenced settlement price and the price ceiling multiplied by the hedged contract volumes.
 LocationDaily Volume (MMBtu/day) Weighted Average Price
Remaining 2017NYMEX Henry Hub65,000
 $3.11
2018NYMEX Henry Hub103,000
 $3.25
2019NYMEX Henry Hub135,000
 $3.07
For No payment is due from either party if the referenced settlement price is below the price ceiling. Below is a portionsummary of the combined natural gas derivative instruments containing fixed price swaps andCompany's open sold call options, the counterparty has an option to extend the original terms an additional twelve months for the period January 2018 through December 2018. The option to extend the terms expires in December 2017. If extended, the Company would have additional fixed price swaps for 30,000 MMBtu per day at a weighted average pricepositions as of $3.36 per MMBtu and additional short call options for 30,000 MMBtu per day at a weighted average ceiling price of $3.36 per MMBtu.June 30, 2023.
For a portion of the natural gas fixed price swaps listed above, the counterparty has an option to extend the original terms an additional twelve months for the period January 2019 through December 2019. The option to extend the terms expires in December 2018. If executed, the Company would have additional fixed price swaps for 100,000 MMBtu per day at a weighted average price of $3.05 per MMBtu.
IndexDaily VolumeWeighted Average Price
Natural Gas(MMBtu/d)($/MMBtu)
Remaining 2023NYMEX Henry Hub407,925 $3.21 
2024NYMEX Henry Hub202,000 $3.33 
2025NYMEX Henry Hub193,315 $5.80 
In addition, the Company has entered into natural gas basis swap positions, which settle on the pricing index to basispositions. These instruments are arrangements that guarantee a fixed price differential of NGPL Mid-Continent to NYMEX Henry Hub.Hub from a specified delivery point. The Company receives the fixed price differential and pays the floating market price differential to the counterparty for the hedged community. As of SeptemberJune 30, 2017,2023, the Company had the following natural gas basis swap positions for NGPL Mid-Continent.open:
Gulfport PaysGulfport ReceivesDaily VolumeWeighted Average Fixed Spread
Natural Gas(MMBtu/d)($/MMBtu)
Remaining 2023Rex Zone 3NYMEX Plus Fixed Spread140,000 $(0.22)
Remaining 2023NGPL TXOKNYMEX Plus Fixed Spread80,000 $(0.35)
Remaining 2023TETCO M2NYMEX Plus Fixed Spread210,000 $(0.91)
2024Rex Zone 3NYMEX Plus Fixed Spread90,000 $(0.15)
2024NGPL TXOKNYMEX Plus Fixed Spread60,000 $(0.31)
2024TETCO M2NYMEX Plus Fixed Spread89,945 $(0.91)
23
 LocationDaily Volume (MMBtu/day) Hedged Differential
Remaining 2017NGPL Mid-Continent50,000
 $(0.26)
2018NGPL Mid-Continent12,000
 $(0.26)

Balance Sheet Presentation
The Company reports the fair value of derivative instruments on the consolidated balance sheets as derivative instruments under current assets, noncurrent assets, current liabilities and noncurrent liabilities on a gross basis. The Company determines the current and noncurrent classification based on the timing of expected future cash flows of individual trades. The following table presents the fair value of the Company’s derivative instruments on a gross basis at SeptemberJune 30, 20172023 and December 31, 2016:2022 (in thousands):
 September 30, 2017 December 31, 2016
 (In thousands)
Short-term derivative instruments - asset$35,332
 $3,488
Long-term derivative instruments - asset$6,409
 $5,696
Short-term derivative instruments - liability$29,130
 $119,219
Long-term derivative instruments - liability$19,712
 $26,759
June 30, 2023December 31, 2022
Short-term derivative asset$140,686 $87,508 
Long-term derivative asset54,308 26,525 
Short-term derivative liability(59,367)(343,522)
Long-term derivative liability(61,557)(118,404)
Total commodity derivative position$74,070 $(347,893)
Gains and Losses

22

The following table presents the gain and loss recognized in Netnet gain (loss) gain on natural gas, oil and NGL derivatives in the accompanying consolidated statements of operations for the three and ninesix months ended SeptemberJune 30, 20172023 and 2016.2022 (in thousands):
Net gain (loss) on derivative instruments
Three Months Ended June 30, 2023Three Months Ended June 30, 2022
Natural gas derivatives - fair value gains$37,792 $121,659 
Natural gas derivatives - settlement gains (losses)49,444 (288,936)
Total gains (losses) on natural gas derivatives87,236 (167,277)
Oil derivatives - fair value gains2,258 4,383 
Oil derivatives - settlement gains (losses)369 (14,281)
Total gains (losses) on oil and condensate derivatives2,627 (9,898)
NGL derivatives - fair value gains4,218 9,506 
NGL derivatives - settlement gains (losses)2,707 (5,202)
Total gains on NGL derivatives6,925 4,304 
Total gains (losses) on natural gas, oil and NGL derivatives$96,788 $(172,871)
24

 Net (loss) gain on derivative instruments
 Three months ended September 30, Nine months ended September 30,
 2017 2016 2017 2016
 (In thousands)
Natural gas derivatives$(7,077) $33,167
 $135,868
 $(43,454)
Oil derivatives(6,571) 1,708
 12,477
 362
Natural gas liquids derivatives(9,212) 406
 (6,757) (1,284)
Total$(22,860) $35,281
 $141,588
 $(44,376)
Net gain (loss) on derivative instruments
Six Months Ended June 30, 2023Six Months Ended June 30, 2022
Natural gas derivatives - fair value gains (losses)$411,940 $(497,660)
Natural gas derivatives - settlement gains (losses)49,271 (400,093)
Total gains (losses) on natural gas derivatives461,211 (897,753)
Oil derivatives - fair value gains (losses)6,990 (25,470)
Oil derivatives - settlement gains (losses)(74)(22,425)
Total gains (losses) on oil and condensate derivatives6,916 (47,895)
NGL derivatives - fair value gains (losses)3,033 (4,827)
NGL derivatives - settlement gains (losses)3,689 (10,947)
Total gains (losses) on NGL derivatives6,722 (15,774)
Total gains (losses) on natural gas, oil and NGL derivatives$474,849 $(961,422)
Offsetting of derivative assetsDerivative Assets and liabilitiesLiabilities
As noted above, the Company records the fair value of derivative instruments on a gross basis. The following table presentstables present 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.value (in thousands):
As of June 30, 2023
Gross Assets (Liabilities) Presented in the Consolidated Balance SheetsGross Amounts Subject to Master Netting AgreementsNet Amount
Derivative assets$194,994 $(73,391)$121,603 
Derivative liabilities$(120,924)$73,391 $(47,533)
 As of September 30, 2017
 Gross Assets (Liabilities) Gross Amounts  
 Presented in the Subject to Master Net
 Consolidated Balance Sheets Netting Agreements Amount
 (In thousands)
Derivative assets$41,741
 $(36,969) $4,772
Derivative liabilities$(48,842) $36,969
 $(11,873)
As of December 31, 2016
Gross Assets (Liabilities) Gross Amounts  
Presented in the Subject to Master Net
Consolidated Balance Sheets Netting Agreements AmountAs of December 31, 2022
(In thousands)Gross Assets (Liabilities) Presented in the Consolidated Balance SheetsGross Amounts Subject to Master Netting AgreementsNet Amount
Derivative assets$9,184
 $(9,184) $—
Derivative assets$114,033 $(80,345)$33,688 
Derivative liabilities$(145,978) $9,184
 $(136,794)Derivative liabilities$(461,926)$80,345 $(381,581)
Concentration of Credit Risk
By using derivative instruments that are not traded on an exchange, the Company is exposed to the credit risk of its counterparties. Credit risk is the risk of loss from counterparties not performing under the terms of the derivative instrument. When the fair value of a derivative instrument is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, it is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The Company’s derivative contracts are withspread between multiple counterparties to lessen its exposure to any individual counterparty. Additionally, the Company uses master netting agreements to minimize credit risk exposure. The creditworthiness of the Company’s counterparties is subject to periodic review. None of the Company’s derivative instrument contracts contain credit-risk related contingent features. Other than as provided by the Company’s revolving credit facility, the Company is not required to provide credit support or collateral to any of its counterparties under its derivative instruments, nor are the counterparties required to provide credit support to the Company.
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11.FAIR VALUE MEASUREMENTS
11.FAIR VALUE MEASUREMENTS
The Company records certain financial and non-financial assets and liabilities on the balance sheet at fair value. Fair value in accordance with FASB ASC 820, “Fair Value Measurement and Disclosures” (“FASB ASC 820”). FASB ASC 820 defines fair value asis the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. The statement establishes marketMarket or observable inputs asare the preferred

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sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The statement requires fairFair value measurements beare classified and disclosed in one of the following categories:
Level 1 – Quoted prices (unadjusted) in active markets for identical assets and liabilities.liabilities that the Company has the ability to access at the measurement date.
Level 2 – Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active and model-derived valuations whose inputs are observable or whose significant value drivers are observable.
Level 3 – Significant inputs to the valuation model are unobservable.
Valuation techniques that maximize the use of observable inputs are favored. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter.
Financial assets and liabilities
The following tables summarize the Company’s financial and non-financial assets and liabilities by FASB ASC 820 valuation level as of SeptemberJune 30, 20172023 and December 31, 2016:2022 (in thousands):
June 30, 2023
Level 1Level 2Level 3
Assets:
Derivative instruments$— $194,994 $— 
Contingent consideration arrangement— — 3,100 
Total assets$— $194,994 $3,100 
Liabilities:
Derivative instruments$— $120,924 $— 
 September 30, 2017
 Level 1 Level 2 Level 3
 (In thousands)
Assets:     
Derivative Instruments$—
 $41,741
 $—
Liabilities:     
Derivative Instruments$—
 $48,842
 $—

December 31, 2016
Level 1 Level 2 Level 3December 31, 2022
(In thousands)Level 1Level 2Level 3
Assets:     Assets:
Derivative Instruments$—
 $9,184
 $—
Derivative instrumentsDerivative instruments$— $114,033 $— 
Contingent consideration arrangementContingent consideration arrangement— — 4,900 
Total assetsTotal assets$— $114,033 $4,900 
Liabilities:     Liabilities:
Derivative Instruments$—
 $145,978
 $—
Derivative instrumentsDerivative instruments$— $461,926 $— 
The Company estimates the fair value of all derivative instruments using industry-standard models that consideredconsider various assumptions, including current market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data.
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The estimatedCompany's SCOOP water infrastructure sale, which closed in the first quarter of 2020, included a contingent consideration arrangement. As of June 30, 2023, the fair valuesvalue of proved oil and natural gas properties assumedthe contingent consideration was $3.1 million, of which all $3.1 million is included in business combinations are based on aother assets in the accompanying consolidated balance sheets. The fair value of the contingent consideration arrangement is calculated using discounted cash flow modeltechniques and market assumptions as to future commodity prices, projectionsis based on internal estimates of estimated quantities of oil and natural gas reserves, expectations for timing and amount ofthe Company's future development program and operating costs, projections of future rates ofwater production expected recovery rates and risk-adjusted discount rates. The estimated fair values of unevaluated oil and natural gas properties was based on geological studies, historical well performance, location and applicable mineral lease terms. Based onlevels. Given the unobservable nature of certain of the inputs, the estimated fair value measurement of the oil and gas properties assumedcontingent consideration arrangement is deemed to use Level 3 inputs. The asset retirement obligations assumed as part ofCompany has elected the business combination were estimated using the same assumptionsfair value option for this contingent consideration arrangement and, methodology as described below. See Note 1 for further discussion of the Vitruvian Acquisition.
therefore, records changes in fair value in earnings. The Company estimates asset retirement obligations pursuantrecognized a $0.1 million loss for the three months ended June 30, 2023 with respect to this contingent consideration arrangement. The Company recognized losses of a $1.2 million and $0.1 million for the provisionssix months ended June 30, 2023 and 2022, respectively, with respect to this contingent consideration arrangement. These fair value changes are included in other expense (income) in the accompanying consolidated statements of FASB ASC Topic 410, Asset Retirementoperations.
Non-financial assets and Environmental Obligations (“FASB ASC 410”). liabilities
The initial measurement of asset retirement obligations at fair value is

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calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 2 for further discussion of the Company’s asset retirement obligations. Asset retirement obligations incurred during the nine months ended September 30, 2017 were approximately $11.6 million.
The fairFair value of the common stock received from Mammoth Energy in connection with the Company’s contribution of all of its membership interests in Sturgeon, Stingray Energy and Stingray Cementing was estimated using Level 1 inputs, as the price per share was a quoted price in an active market for identical Mammoth Energy common shares.other financial instruments
Due to the unobservable nature of the inputs, the fair value of the Company’s investment in Grizzly was estimated using assumptions that represent Level 3 inputs. The Company estimated the fair value of the investment as of March 31, 2016 to be approximately $39.1 million. See Note 3 for further discussion of the Company’s investment in Grizzly.
Due to the unobservable nature of the inputs, the fair value of the Company’s initial investment in Strike Force was estimated using assumptions that represent Level 3 inputs. The Company’s estimated fair value of the investment as of the February 1, 2016 contribution date was $22.5 million. See Note 3 for further discussion of the Company’s contribution to Strike Force.
12.FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts on the accompanying consolidated balance sheet for cash and cash equivalents, accounts receivable, and accounts payable and accrued liabilities and current debt are carried at cost, which approximates market value due to their short-term nature. Long-term debt related to the Construction LoanCompany's Credit Facility is carried at cost, which approximates market value based on the borrowing rates currently available to the Company with similar terms and maturities.
At September 30, 2017,
12.REVENUE FROM CONTRACTS WITH CUSTOMERS
Revenue Recognition
The Company’s revenues are primarily derived from the carrying valuesale of natural gas, oil condensate and NGL. These sales 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 outstanding debt represented by the Notes was approximately $1.6 billion, including the unamortized debt issuance cost of approximately $5.5 million relatedproduct is transferred to the 2023 Notes, approximately $10.2 million relatedcustomer. 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 2024 Notescustomer. The payment date is usually within 30 days of the end of the calendar month in which the commodity is delivered.
Gathering, processing and approximately $14.3 million relatedcompression fees attributable to gas processing, as well as any transportation fees, including firm transportation fees, incurred to deliver the product to the 2025 Notes. Based onpurchaser, are presented as transportation, gathering, processing and compression expense in the quoted market price, the fair valueaccompanying consolidated statements of operations.
Transaction Price Allocated to Remaining Performance Obligations
A significant number of the Notes was determined to be approximately $1.6 billion at September 30, 2017.
13.CONDENSED CONSOLIDATING FINANCIAL INFORMATION
On October 17, 2012, December 21, 2012 and August 18, 2014,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 issuedhas utilized the 2020 Notes in an aggregate of $600.0 million principal amount. The 2020 Notes were subsequently exchanged for substantially identical notespractical expedient allowed in the same aggregate principal amountrevenue accounting standard that were registered under the Securities Act. In October 2016,exempts the Company repurchased (in a cash tender offer) or redeemed allfrom disclosure of the 2020 Notes,transaction price allocated to remaining performance obligations if the performance obligation is part of which $600.0 million in aggregate principal amount was then outstanding, with the net proceeds from the issuancea contract that has an original expected duration of the 2024 Notes discussed below and cash on hand.
On April 21, 2015, the Company issued $350.0 million in aggregate principal amount of the 2023 Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. In connection with the 2023 Notes Offering, the Company and its subsidiary guarantors entered into a registration rights agreement, dated as of April 21, 2015, pursuant to which the Company agreed to file a registration statement with respect to an offer to exchange the 2023 Notes for a new issue of substantially identical debt securities registered under the Securities Act. The exchange offer for the 2023 Notes was completed on October 13, 2015.
On October 14, 2016, the Company issued $650.0 million in aggregate principal amount of the 2024 Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. The net proceeds from the issuance of the 2024 Notes, together with cash on hand, were used to repurchaseone year or redeem all of the then-outstanding 2020 Notes in October 2016.
On December 21, 2016, the Company issued $600.0 million in aggregate principal amount of the 2025 Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. The Company used the net proceeds from the issuance of the 2025 Notes, together with the net proceeds from the December 2016 underwritten offering of the Company’s common stock and cash on hand, to fund the cash portion of the purchase price for the Vitruvian Acquisition.

less.
25
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In connection with the 2024 Notes and the 2025 Notes Offerings,For product sales that have a contract term greater than one year, the Company and its subsidiary guarantors entered into two registration rights agreements, pursuant to whichhas utilized the practical expedient that exempts the Company agreed to file a registration statement with respect to offers to exchange the 2024 Notes and the 2025 Notes for new issues of substantially identical debt securities registered under the Securities Act. The exchange offers for the 2024 Notes and the 2025 Notes were completed on September 13, 2017.
The 2020 Notes were, and the 2023 Notes, the 2024 Notes and the 2025 Notes are, guaranteed on a senior unsecured basis by all existing consolidated subsidiaries that guarantee the Company’s secured revolving credit facility or certain other debt (the “Guarantors”). The 2020 Notes were not, and the 2023 Notes, the 2024 Notes and the 2025 Notes are not, guaranteed by Grizzly Holdings, Inc. (the “Non-Guarantor”). The Guarantors are 100% owned by Gulfport (the “Parent”), and the guarantees are full, unconditional, joint and several. There are no significant restrictions on the abilityfrom disclosure of the Parent ortransaction price allocated to remaining performance obligations if the Guarantorsvariable consideration is allocated entirely to obtain fundsa wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Currently, the Company's product sales that have a contractual term greater than one year have no long-term fixed consideration.
Contract Balances
Receivables from each other incontracts with customers are recorded when the formright to consideration becomes unconditional, generally when control of a dividend or loan.
The following condensed consolidating balance sheets, statements of operations, statements of comprehensive (loss) income and statements of cash flows are provided for the Parent, the Guarantors and the Non-Guarantor and include the consolidating adjustments and eliminations necessary to arrive at the information for the Company on a condensed consolidated basis. The informationproduct has been presented usingtransferred to the equity method of accounting for the Parent’s ownership of the Guarantorscustomer. Receivables from contracts with customers were $92.1 million and the Non-Guarantor.


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


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


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

21,283

1

—

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

(1)
—

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

56,193

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

$56,490

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


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CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(Amounts in thousands)

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

—

—

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

 

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

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


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CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(Amounts in thousands)

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


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CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(Amounts in thousands)

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

 

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


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CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Amounts in thousands)
 Three months ended September 30, 2017
 Parent Guarantors Non-Guarantor Eliminations Consolidated
          
Net income (loss)$18,235
 $56,490
 $(297) $(56,193) $18,235
Foreign currency translation adjustment6,832
 158
 6,674
 (6,832) 6,832
Other comprehensive income (loss)6,832
 158
 6,674
 (6,832) 6,832
Comprehensive income (loss)$25,067
 $56,648
 $6,377
 $(63,025) $25,067


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


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


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

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


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


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14.RECENT ACCOUNTING PRONOUNCEMENTS
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers, which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The core principle of the new standard is for the recognition of revenue to depict the transfer of goods or services to customers in amounts that reflect the payment to which the company expects to be entitled in exchange for those goods or services. The new standard will also result in enhanced revenue disclosures, provide guidance for transactions that were not previously addressed comprehensively and improve guidance for multiple-element arrangements. The ASU is effective for annual periods beginning after December 15, 2016, and interim periods within those years. The new standard permits retrospective application using either of the following methodologies: (i) restatement of each prior reporting period presented (full retrospective method) or (ii) recognition of a cumulative-effect adjustment$278.4 million as of the date of initial application (modified retrospective method). In July 2015, the FASB decided to defer the effective date by one year (until 2018). The Company is evaluating the impact of this ASU on its consolidated financial statementsJune 30, 2023 and working to identify any potential differences that would result from applying the requirements of the ASU to existing contractsDecember 31, 2022, respectively, and current accounting policies and practices. This evaluation requires, among other things, a review of the contracts it has with customers within each of the revenue streams identified within the Company's business, including natural gas sales,are reported in accounts receivable - oil and condensatenatural gas sales, and natural gas liquid sales.liquids sales in the accompanying consolidated balance sheets. The Company does not believe further disaggregationcurrently 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 revenueproduction that was delivered to the purchaser and the price that will be required underreceived for the new standard. Substantially allsale of the Company's revenueproduct. The differences between the estimates and the actual amounts for product sales is earned pursuant to agreements under which they have currently interpreted one performance obligation, whichrecorded in the month that payment is satisfied at a point-in-time. As partreceived from the purchaser. For each of the evaluation work to-date,periods presented, revenue recognized in the reporting periods related to performance obligations satisfied in prior reporting periods was not material.
13.LEASES
Nature of Leases
The Company has substantially completed its contract reviews and documentation. Due to industry-wide ongoing discussionsoperating leases on certain application issues, the Company cannot reasonably estimate the expected financial statement impact; however, it does not expect the impactequipment with remaining lease durations in excess of the application of the new standard to have a material impact on net income or cash flows based on the reviews performed to-date.one year. The Company is currently assessing the requirements for additional disclosuresrecognizes a right-of-use asset and documentation of new policies, procedures, system, control and data requirements. The Company’s expectation is to adopt the standard on January 1, 2018, using the modified retrospective method. Based on the analysis to-date, the Company has not identified any material impact on their consolidated financial statements other than additional disclosures requirements.
In February 2016, the FASB issued ASU No. 2016-02, Leases. The guidance requires the lessee to recognize most leaseslease liability on the balance sheet thereby resultingfor 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. The Company 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. At June 30, 2023, the Company had one active long-term drilling rig contract.
The Company rents office space for its corporate headquarters, field locations and certain other equipment from third parties, which expire at various dates through 2026. 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 recognitiondetermination of the lease assets and liability for thoseterms.
Discount Rate
As most of the Company's leases currently classified as operating leases. The accounting for lessors is largely unchanged. The guidance is effective for periods after December 15, 2018, with early adoption permitted. Thedo not provide an implicit rate, the Company is in the process of evaluating the impact of this guidance onuses its consolidated financial statements and related disclosures; however,incremental borrowing rate based on the Company’s currentinformation available at commencement date in determining the present value of lease payments. The Company's incremental borrowing rate reflects the estimated rate of interest that it would pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment.
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Future amounts due under operating lease liabilities as of June 30, 2023 were as follows (in thousands):
Remaining 2023$6,866 
202413,439 
2025836 
2026561 
202710 
Total lease payments$21,712 
Less: imputed interest(1,113)
Total$20,599 
The tables below summarize lease costs for the periods presented (in thousands):
Three Months Ended June 30, 2023Three Months Ended June 30, 2022
Operating lease cost$3,443 $50 
Variable lease cost— — 
Short-term lease cost8,050 10,160 
Total lease cost(1)
$11,493 $10,210 

Six Months Ended June 30, 2023Six Months Ended June 30, 2022
Operating lease cost$6,886 $100 
Variable lease cost— — 
Short-term lease cost17,298 18,782 
Total lease cost(1)
$24,184 $18,882 
_____________________
(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 related to leases it is notwas as follows (in thousands):
Six Months Ended June 30, 2023Six Months Ended June 30, 2022
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases$4,236 $72 
The weighted-average remaining lease term as of June 30, 2023 was 1.68 years. The weighted-average discount rate used to determine the operating lease liability as of June 30, 2023 was 6.71%.
14.INCOME TAXES
The Company records its quarterly tax provision based on an estimate of the annual effective tax rate expected to have a material impact.

In March 2016,apply to continuing operations for the FASB issued ASU No. 2016-05, Effectvarious jurisdictions in which it operates. The tax effects of Derivative Contract Novations on Existing Hedge Accounting Relationships. The guidance was issued to clarify that changecertain items, such as tax rate changes, significant unusual or infrequent items, and certain changes in the counterparty toassessment 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 six months ended June 30, 2023, the Company's effective tax rate for the period was 0%, which differs from the statutory rate of 21% primarily as a derivative instrument that had been designated asresult of the hedging instrument under Topic 815, does not require designation of that hedging relationship provided that all other hedge accounting criteria continue to be met. The Company adopted the standard as of January 1, 2017. There was no impact on the Company’s consolidated financial statements because all current derivative instruments are not designated for hedge accounting.
In March 2016, the FASB issued ASU No. 2016-09, Improvements to Employee Share-Based Payment Accounting. This guidance was intended to simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The Company adopted the standard as of January 1, 2017. The Company has elected to recognize forfeitures of awards as they occur. The adoption of this standard did not have a material impactvaluation allowance on the Company's consolidated financial statements.

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

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Instruments. This ASU amends guidance on reporting credit losses for assets held at amortized cost basis and available for sale debt securities. For assets held at amortized cost basis, this ASU eliminates the probable initial recognition threshold in current GAAP and instead, requires an entity to reflect its current estimate of all expected credit losses. The

deferred tax assets.
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amendments affect loans, debt securities, trade receivables, net investments in leases, off balance sheet credit exposure, reinsurance receivablesAt each reporting period, the Company weighs all available positive and any other financial assets not excluded from the scope that have the contractual right to receive cash. The Company is currently evaluating the impact this standard will have on its financial statements and related disclosures and does not anticipate it to have a material affect.

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

In December 2016, the FASB issued ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers. This guidance updates narrow aspects of the guidance issued in Update 2014-09. This amendment is effective for periods after December 15, 2017, with early adoption permitted. The Company is in the process of evaluating the impact of this ASU on its consolidated financial statements.
In January 2017, the FASB issued ASU No. 2017-01, Clarifying the Definition of a Business. Under the current business combination guidance, there are three elements of a business: inputs, processes and outputs. The revised guidance adds an initial screen testnegative evidence to determine if substantiallywhether 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 fair valuebenefit from the deferred tax assets will not be realized. To assess that likelihood, the Company uses estimates and judgment regarding future taxable income and considers the tax laws in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities and tax planning strategies as well as the current and forecasted business economics of the grossoil and gas industry. Based upon the Company’s analysis, the Company determined a full valuation allowance was necessary against its net deferred tax assets acquiredas of June 30, 2023.
The Company will continue to evaluate whether the valuation allowance is concentratedneeded in a single assetfuture 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 groupnew 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 similar assets. Ifthe tax attributes if the Company recognizes taxable income. As long as the Company concludes that screen is met, the set ofvaluation allowance against its net deferred tax assets is necessary, the Company likely will not a business.have any additional deferred income tax expense or benefit.
15.RELATED PARTY TRANSACTIONS
Share Repurchase Program
Concurrent with the closing of the offering transaction discussed in Note 5, the Company purchased 215,060 shares of its common stock from Silver Point Capital, L.P. for approximately $20.4 million. The new framework also specifiesrepurchase is part of the minimum required inputsCompany's existing $400 million share repurchase program. Upon closing of the transaction on June 26, 2023, the repurchased common stock was cancelled.
16.SUBSEQUENT EVENTS
Natural Gas, Oil and processes necessaryNGL Derivative Instruments
Subsequent to be a business. This amendment is effective for periods after December 15, 2017, with early adoption permitted. The Company is in the processJune 30, 2023, as of evaluating the impact of this ASU on its consolidated financial statements.
15.SUBSEQUENT EVENTS
Derivatives
In October of 2017,July 27, 2023, the Company entered into fixed price swaps for 2018 for approximately 1,500 Bbls of oil per day at a weighted average price of $52.05 per Bbl. The Company’s fixed price swap contracts are tied to the commodity prices on NYMEX WTI. The Company will receive the fixed price amount stated in the contract and pay to its counterparty the current market price as listed on NYMEX for oil.following derivative contracts:
Senior Notes Offering
On October 11, 2017, the Company issued $450.0 million in aggregate principal amount of its 6.375% Senior Notes due 2026 (the “2026 Notes”) to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. Interest on the 2026 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof from October 11, 2017, payable semi-annually on January 15 and July 15 of each year, commencing on January 15, 2018. The 2026 Notes will mature on January 15, 2026. A portion of the net proceeds from the issuance of the 2026 Notes was used to repay all of the Company's outstanding borrowings under its secured revolving credit facility on October 11, 2017 and the balance will be used to fund the remaining anticipated outspend related to the Company's 2017 capital development plans.



PeriodType of Derivative InstrumentIndexDaily Volume (MMBtu)Weighted
Average Price
2024Basis SwapsRex Zone 340,000 $(0.15)
2024Basis SwapsNGPL TXOK10,000 $(0.27)
2024SwapsMont Belvieu C3500 $29.13
2024Costless CollarsNYMEX WTI1,000 $62.00 / $80.00
2025Costless CollarsNYMEX Henry Hub20,000 $3.60 / $4.20
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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’sITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Introduction
Management's Discussion and Analysis of Financial Condition and Results of Operations” sectionOperations (MD&A) is intended to provide the reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and audited consolidatedcertain other factors that may affect the Company's operating results. MD&A should be read in conjunction with the financial statements and related notesNotes included in ourPart 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, 2022 (“2022 Form 10-K”) and withanalyzes the unaudited consolidated financial statementschanges in the results of operations between the periods of April 1, 2023 through June 30, 2023, January 1, 2023 through June 30, 2023, April 1, 2022 through June 30, 2022 and related notes thereto presentedJanuary 1, 2022 through June 30, 2022. For definitions of commonly used natural gas and oil terms found in this Quarterly Report on Form 10-Q.
Disclosure Regarding Forward-Looking Statements
This report includes “forward-looking statements” within10-Q, please refer to the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. All statements other than statements of historical facts included“Definitions” provided in this report that address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as estimated future net revenues from oil and natural gas reserves and the present value thereof, future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, competitive strength, goals, expansion and growth of our business and operations, plans, references to future success, reference to intentions as to future matters and other such matters are forward-looking statements. These statements are based on certain assumptions and analysis made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate in the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, general economic, market or business conditions; the opportunities (or lack thereof) that may be presented to and pursued by us; competitive actions by other oil and natural gas companies; our ability to identify, complete and integrate acquisitions of properties (including those recently acquired from Vitruvian II Woodford, LLC) and businesses; changes in laws or regulations; adverse weather conditions and natural disasters such as hurricanes and other factors, including those listed in the “Risk Factors” section of our most recent Annual Report on Form 10-K, Quarterly Reports on Form 10-Q or any other filings we make with the SEC, many of which are beyond our control. Consequently, all of the forward-looking statements made in this report are qualified by these cautionary statements, and we cannot assure you that the actual results or developments anticipated by us will be realized or, even if realized, that they will have the expected consequences to or effects on us, our business or operations. We have no intention, and disclaim any obligation, to update or revise any forward-looking statements, whether as a result of new information, future results or otherwise.report.
Overview
We areGulfport is an independent oil and natural gasgas-weighted exploration and production company focused on the exploration, exploitation, acquisition and production of natural gas, crude oil and natural gas liquidswith assets primarily located in the United States. Our corporate strategy is to internally identify prospects, acquire lands encompassing those prospectsAppalachia and evaluate those prospects using subsurface geology and geophysical data and exploratory drilling. Using this strategy, we have developed an oil and natural gas portfolio of proved reserves, as well as development and exploratory drilling opportunities on high potential conventional and unconventional oil and natural gas prospects.Anadarko basins. Our principal properties are located in eastern Ohio targeting the Utica Shale primarilyand Marcellus and in Eastern Ohio andcentral Oklahoma targeting the SCOOP Woodford and SCOOP Springer playsformations. Our strategy is to develop our assets in Oklahoma.a safe, environmentally responsible manner, while generating sustainable cash flow, improving margins and operating efficiencies and returning capital to shareholders. 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.
Recent Developments
Leadership Changes
In January 2023, our CEO Tim Cutt, resigned his position as CEO. Mr. Cutt, who served as CEO and Chairman since 2021, retained his position of Chairman of the Board of Directors. Subsequent to Mr. Cutt's resignation, Gulfport named John Reinhart CEO and Director, effective January 24, 2023. In addition, Matthew Rucker joined Gulfport's leadership team as Senior Vice President of Operations.
In April 2023, Gulfport named Michael Hodges Executive Vice President and Chief Financial Officer. William Buese resigned as Executive Vice President and Chief Financial Officer of the Company on April 1, 2023. Mr. Buese remained with the Company as an adviser until his termination on May 3, 2023.
Credit Facility
On May 1, 2023, the Company entered into that certain Joinder, Commitment Increase and Borrowing Base Redetermination Agreement, and Third Amendment to Credit Agreement (the “Third Amendment”) which amended the Company’s Existing Credit Facility (as amended, the “Credit Facility”). The Third Amendment, among other interests, we hold an acreage position alongthings, (a) increased the Louisiana Gulf Coast inaggregate elected commitment amounts under the West Cote Blanche Bay, or WCBB,Credit Facility from $700 million to $900 million, (b) increased the borrowing base under the Credit Facility from $1 billion to $1.1 billion, (c) increased the excess cash threshold under the Credit Facility from $45 million to $75 million, and Hackberry fields, an acreage position in(d) extended the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC, or Grizzly,maturity date under the Credit Facility from October 14, 2025 to the earlier of (i) May 1, 2027 and an approximate 25.1% equity interest in Mammoth Energy Services, Inc., or Mammoth Energy, an oil field services company listed on(ii) the Nasdaq Global Select Market (TUSK). We seek91st day prior to achieve reserve growth and increase our cash flow through our annual drilling programs.
2017 Operational and Other Highlights
Production increased 63% to 110,367 net million cubic feet of natural gas equivalent, or MMcfe, for the three months ended September 30, 2017 from 67,541 MMcfe for the three months ended September 30, 2016. Our net daily production mix for the third quarter of 2017 averaged 1,199.6 MMcfe per day and was comprised of approximately 88% natural gas, 8% natural gas liquids, or NGLs, and 4% oil.
On February 17, 2017, we, through our wholly-owned subsidiary Gulfport MidCon LLC, or Gulfport MidCon (formerly known as SCOOP Acquisition Company, LLC), completed our acquisition, which we refer to as the Acquisition, of certain assets from Vitruvian II Woodford, LLC, an unrelated third-party seller, for a total purchase price of approximately $1.85 billion, consisting of $1.35 billion in cash, subject to certain adjustments, and approximately 23.9 million sharesmaturity date of the Company’s common stock (of which approximately 5.2 million shares were2026 Senior Notes or any other permitted senior notes or any permitted refinancing debt under the Credit Facility having an aggregate outstanding principal amount equal to or exceeding $100 million; provided that such notes have not be refinanced, redeemed or repaid in full on or prior to such 91st day.




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placed in an indemnity escrow). The Acquisition included approximately 46,000 net surface acres with multiple producing zones, including the Woodford and Springer formations in the South Central Oklahoma Oil Province, or SCOOP, resource play, in Grady, Stephens and Garvin Counties, Oklahoma.Common Stock Offering
On June 5, 2017, we acquired approximately 2.026, 2023, Gulfport completed an underwritten public offering of 1.5 million shares of Mammoth Energyits common stock in connectionby certain stockholders at a price to the public of $95.00 per share. Gulfport did not sell any of its common stock as part of this offering and did not receive any proceeds from the sale of the shares sold by the selling stockholders.
Concurrent with our contributionthe closing of allthe offering, Gulfport purchased 263,158 shares of our membership interests in Sturgeon Acquisitions LLC, Stingray Energy Services LLC and Stingray Cementing LLC, which we referits common stock at $95.00 per share. The repurchase is part of the Company's existing $400 million share repurchase program discussed below.
Share Repurchase Program
On February 27, 2023, the Company's Board of Directors approved an increase to as Sturgeon, Stingray Energy and Stingray Cementing, respectively, bringing our equity interest in Mammoth Energythe authorized common stock Repurchase Program from $300 million to approximately 25.1%.
$400 million. The additional $100 million authorization expires on March 31, 2024. During the three months ended SeptemberJune 30, 2017, we spud 23 gross (23.0 net) wells2023, the Company repurchased 441,512 shares for $41.4 million at a weighted average price of $93.67 per share. As of June 30, 2023, the Company repurchased 3.8 million shares for $325.0 million at a weighted average price of $85.51 per share since the inception of the Repurchase Program.
Inflation, Rising Interest Rates and Changes in Commodity Prices
The annual rate of inflation in the Utica Shale, participatedUnited States continues to be elevated as compared to historical averages. The Federal Reserve has tightened monetary policy by approving a series of increases to the Federal Funds Rate. Furthermore, the Chairman of the Federal Reserve signaled that the Federal Reserve would continue to take necessary action to bring inflation down and to ensure price stability. The inflationary environment has impacted interest rates on our Credit Facility borrowings throughout 2022 and into 2023. Interest rates on our Credit Facility borrowings have increased from a weighted average of 4.01% and 3.59% for the three and six months ended June 30, 2022, respectively, to 8.13% and 7.85% for the three and six months ended June 30, 2023, respectively. Additional increases in aninterest rates may have a negative impact on the Company’s ability to continue to execute its business strategy.
Our revenues, the value of our assets, and our ability to obtain bank loans or additional four gross (1.3 net) wellscapital on attractive terms have been and will continue to be affected by changes in natural gas, oil and NGL prices and the costs to produce our reserves. Natural gas, oil and NGL prices are subject to significant fluctuations that are beyond our ability to control or predict. Certain of our capital expenditures and expenses are affected by general inflation and we expect costs for 2023 to continue to be a function of supply and demand; however, we do not expect inflation to significantly impact cash flow in 2023 as a result of commitments that were drilledentered into during 2022.
Impact of the War in Ukraine
The invasion of Ukraine by other operators on our Utica Shale acreageRussia and spud six gross and net wells and recompleted nine gross and net wells on our Louisiana acreage. In addition, during the three months ended September 30, 2017, seven gross (6.1 net) wells were spudsanctions imposed in response to the crisis have increased volatility in the SCOOP. We also participatedglobal financial markets and are expected to have further global economic consequences, including disruptions of the global energy markets and the amplification of inflation and supply chain constraints. The ultimate impact of the war in an additional three gross (0.03 net) wells that were drilled by other operatorsUkraine will depend on our SCOOP acreage. Offuture developments and the 36 new wells we spud, at September 30, 2017, 28 were in various stages of completiontiming and eight were being drilled. In addition, 19 gross (17.9 net) operated wellsextent to which normal economic and nine gross (2.1 net) non-operated wells were turned-to-sales in our Utica Shale operating areaconditions resume.
2023 Operational and six gross (5.6 net) operated wells and 12 gross (0.43 net) non-operated wells were turned-to-sales in our SCOOP operating area during the three months ended September 30, 2017.Financial Highlights
During the nine months ended September 30, 2017,second quarter of 2023, we reducedhad the following notable achievements:
•Reported total net production of 1,039.3 MMcfe per day.
•Turned to sales 13 gross (11.9 net) operated wells.
•Generated $107.4 million of operating cash flows.
•Repurchased 441,512 shares for $41.4 million at a weighted average price of $93.67 per share.
•Increased our unit lease operating expense by 16%borrowing base from $1.0 billion to $0.21 per Mcfe from $0.26 per Mcfe during the nine months ended September 30, 2016.

During the nine months ended September 30, 2017, we decreased$1.1 billion and increased our unit general and administrative expense by 22% to $0.13 per Mcfe from $0.17 per Mcfe during the nine months ended September 30, 2016.
On October 11, 2017, we issued $450.0 million in aggregate principal amount of our 6.375% Senior Notes due 2026, or the 2026 Notes, to qualified institutional buyers pursuant to Rule 144Aelected commitment under the Securities Act andCredit Facility from $700 million to certain non-U.S. persons in accordance with Regulation S under$900 million.
•Extended the Securities Act. Interest on the 2026 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof from October 11, 2017, payable semi-annually on January 15 and July 15 of each year, commencing on January 15, 2018. The 2026 Notes will mature on January 15, 2026. A portionmaturity of the net proceeds from the issuance of the 2026 Notes was usedCredit Facility to repay all of our outstanding borrowings under our secured revolving credit facility on October 11, 2017 and the balance will be used to fund the remaining anticipated outspend related to our 2017 capital development plans.




May 2027.
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20172023 Production and Drilling Activity
During the three months ended September 30, 2017, our total net production was 97,824,927 cubic feet, or Mcf, of natural gas, 685,316 barrels of oil and 59,007,909 gallons of NGLs for a total of 110,367 MMcfe, as compared to 58,150,669 Mcf of natural gas, 521,356 barrels of oil and 43,837,087 gallons of NGLs, or 67,541 MMcfe, for the three months ended September 30, 2016. Production Volumes
Three Months Ended June 30, 2023Three Months Ended June 30, 2022
Natural gas (Mcf/day)
Utica751,272 637,854 
SCOOP194,639 220,637 
Other— (10)
Total945,910 858,481 
Oil and condensate (Bbl/day)
Utica556 722 
SCOOP2,977 3,960 
Other— (4)
Total3,533 4,678 
NGL (Bbl/day)
Utica2,440 2,109 
SCOOP9,596 9,983 
Other— 2 
Total12,036 12,093 
Combined (Mcfe/day)
Utica769,246 654,840 
SCOOP270,077 304,293 
Other1 (27)
Total1,039,323 959,106 
Totals may not sum or recalculate due to rounding.
Our total net production averaged approximately 1,199.61,039.3 MMcfe per day during the three months ended SeptemberJune 30, 20172023, as compared to 734.1959.1 MMcfe per day during the same period in 2016. The 63% increase in production is largely the result of the continuing development of our Utica Shale acreage and production attributable to the Acquisition.
Utica Shale. As of November 1, 2017, we held leasehold interests in approximately 235,000 gross (213,000 net) acres in the Utica Shale. From January 1, 2017 through November 1, 2017, we spud 89 gross (84.1 net) wells, of which 16 were producing, 69 were in various stages of completion and four were being drilled at November 1, 2017. In addition, 16 gross (5.5 net) wells were drilled by other operators on our Utica Shale acreage during the nine months ended September 30, 2017.
As of November 1, 2017, we had four operated horizontal rigs under contract on our Utica Shale acreage. We currently intend to spud 96 gross (91 net) horizontal wells, and commence sales from 68 gross (61 net) wells, on our Utica Shale acreage in 2017.
Aggregate net production from our Utica Shale acreage during the three months ended September 30, 2017 was approximately 90,822 MMcfe, or an average of 987.2 MMcfe per day, of which 94% was from natural gas and 6% was from oil and NGLs.
SCOOP. As of November 1, 2017, we held leasehold interests in approximately 50,400 net acres in the SCOOP. From January 1, 2017 through November 1, 2017, 16 gross (13.6 net) wells were spud, of which four were being drilled and 12 were waiting on completion at November 1, 2017. In addition, 25 gross (0.8 net) wells were drilled by other operators on our SCOOP acreage during the period from February 17, 2017 to September 30, 2017.
As of November 1, 2017, we had four horizontal rigs under contract on our SCOOP acreage. We currently intend to spud 22 gross (18 net) wells, and commence sales from 18 gross (16 net) wells, on our SCOOP acreage in 2017.
Aggregate net production from our SCOOP acreage during the three months ended September 30, 2017 was approximately 17,888 MMcfe, or an average of 194.4 MMcfe per day, of which 70% was from natural gas and 30% was from oil and NGLs.
WCBB. From January 1, 2017 through November 1, 2017, we spud ten new wells and recompleted 59 wells. Aggregate net production from the WCBB field during the three months ended September 30, 2017 was approximately 1,255 MMcfe, or an average of 13.6 MMcfe per day, 98% of which was from oil.
East Hackberry Field. From January 1, 2017 through November 1, 2017, we spud five new wells and recompleted 20 wells. Aggregate net production from the East Hackberry field during the three months ended September 30, 2017 was approximately 296 MMcfe, or an average of 3.2 MMcfe per day, of which 98% was from oil and 2% was from natural gas.
West Hackberry Field. From January 1, 2017 through November 1, 2017, we did not spud any wells in our West Hackberry field. Aggregate net production from the West Hackberry field during the three months ended September 30, 2017 was approximately 19.7 MMcfe, or an average of 214.5 Mcfe per day, all of which was from oil.
We currently intend to drill 15 gross and net wells and perform recompletion activities on our acreage in Southern Louisiana.
Niobrara Formation. As of September 30, 2017, we held leases for approximately 4,000 net acres in the Niobrara Formation in Northwestern Colorado. From January 1, 2017 through November 1, 2017, there were no wells spud on our Niobrara Formation acreage. Aggregate net production was approximately 19.9 MMcfe, or an average of 216.5 Mcfe per day during the three months ended SeptemberJune 30, 2017, all2022. The 8% increase in production per day is largely the result of which was from oil.our 2022 and 2023 development programs.
Bakken
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Six Months Ended June 30, 2023Six Months Ended June 30, 2022
Natural gas (Mcf/day)
Utica735,133 699,489 
SCOOP210,030 191,806 
Other— 11 
Total945,163 891,306 
Oil and condensate (Bbl/day)
Utica573 710 
SCOOP3,555 3,447 
Other— 1 
Total4,128 4,158 
NGL (Bbl/day)
Utica2,564 2,145 
SCOOP10,496 9,052 
Other— 1 
Total13,060 11,198 
Combined (Mcfe/day)
Utica753,956 716,621 
SCOOP294,335 266,798 
Other1 25 
Total1,048,292 983,444 
Totals may not sum or recalculate due to rounding.
Our total net production averaged approximately 1,048.3 MMcfe per day during the six months ended June 30, 2023, as compared to 983.4 MMcfe per day during the six months ended June 30, 2022. The 7% increase in production per day is largely the result of our 2022 and 2023 development programs.
Utica. As of September 30, 2017, we held approximately 778 net acresWe spud two gross (1.67 net) wells in the Bakken Formation of Western North Dakota and Eastern Montana with interests in 18 wells and overriding royalty interests in certain existing and future wells. Aggregate net production from this acreageUtica during the three months ended SeptemberJune 30, 2017 was approximately 64.5 MMcfe, or an average2023. In addition, we commenced sales on 11 gross (10.15 net) operated wells.
As of 701.4 Mcfe per day, of which 78% was from oil, 15% was from natural gas and 7% was from NGLs.July 27, 2023, we had one operated drilling rig running in Ohio drilling the Marcellus formation.

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Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations are based upon consolidated financial statements, which have been prepared in accordance with accounting principles generally acceptedSCOOP. We did not spud any operated wells in the United States of America, or GAAP. The preparation of these consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management. We analyze our estimates including those related to oil and natural gas properties, revenue recognition, income taxes and commitments and contingencies, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements:
Oil and Natural Gas Properties. We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including non-productive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month price for the prior twelve months, adjusted for any contract provisions or financial derivatives, if any, that hedge our oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown is required. Such capitalized costs, including the estimated future development costs and site remediation costs of proved undeveloped properties are depleted by an equivalent units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one barrel of oil. No gain or loss is recognized upon the disposal of oil and natural gas properties, unless such dispositions significantly alter the relationship between capitalized costs and proven oil and natural gas reserves. Oil and natural gas properties not subject to amortization consist of the cost of undeveloped leaseholds and totaled approximately $3.0 billion at September 30, 2017 and $1.6 billion at December 31, 2016. These costs are reviewed quarterly by management for impairment, with the impairment provision included in the cost of oil and natural gas properties subject to amortization. Factors considered by management in its impairment assessment include our drilling results and those of other operators, the terms of oil and natural gas leases not held by production and available funds for exploration and development.
Ceiling Test. Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling (as defined in the preceding paragraph). If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown is required. Ceiling test impairment can give us a significant loss for a particular period; however, future depletion expense would be reduced. A decline in oil and gas prices may result in an impairment of oil and gas properties. For instance, as a result of the decline in commodity prices in 2015 and 2016 and subsequent reduction in our proved reserves, we recognized a ceiling test impairment of $715.5 million for the year ended December 31, 2016. At September 30, 2017, the calculated ceiling was greater than the net book value of our oil and natural gas properties, thus no ceiling test impairment was required for the nine months ended September 30, 2017. If prices of oil, natural gas and natural gas liquids decline in the future, we may be required to further write down the value of our oil and natural gas properties, which could negatively affect our results of operations.
Asset Retirement Obligations. We have obligations to remove equipment and restore land at the end of oil and gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells and associated production facilities.
We account for abandonment and restoration liabilities under FASB ASC 410 which requires us to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, we increase the carrying amount of the related long-lived asset by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related

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long-lived asset. Upon settlement of the liability or the sale of the well, the liability is reversed. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements.
The fair value of the liability associated with these retirement obligations is determined using significant assumptions, including current estimates of the plugging and abandonment or retirement, annual inflation of these costs, the productive life of the asset and our risk adjusted cost to settle such obligations discounted using our credit adjusted risk free interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to the carrying amount of the related long-lived asset, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of our oil and natural gas assets, the costs to ultimately retire these assets may vary significantly from previous estimates.
Oil and Gas Reserve Quantities. Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Netherland, Sewell & Associates, Inc. and to a lesser extent our personnel have prepared reserve reports of our reserve estimates at December 31, 2016 on a well-by-well basis for our properties.
Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Our reserve estimates and the projected cash flows derived from these reserve estimates have been prepared in accordance with the guidelines of the Securities and Exchange Commission, or SEC. The accuracy of our reserve estimates is a function of many factors including the following:
the quality and quantity of available data;
the interpretation of that data;
the accuracy of various mandated economic assumptions; and
the judgments of the individuals preparing the estimates.
Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. Therefore, reserve estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered.
Income Taxes. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in incomeSCOOP during the period the rate change is enacted. Deferred tax assets are recognized in the year in which realization becomes determinable. Periodically, management performs a forecast of its taxable income to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established, if in management’s opinion, it is more likely than not that some portion will not be realized. At September 30, 2017, a valuation allowance of $548.4 million had been provided against the net deferred tax asset, with the exception of certain state net operating losses, or NOL, and alternative minimum tax, or AMT, credits that we expect to be able to utilize with NOL carrybacks and tax planning in the amount of $4.7 million.
Revenue Recognition. We derive almost all of our revenue from the sale of crude oil and natural gas produced from our oil and natural gas properties. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment on substantially all of these sales from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers that month and the price we will receive. Variances between our estimated revenue and actual payment received for all prior months are recorded at the end of the quarter after payment is received. Historically, our actual payments have not significantly deviated from our accruals.

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Investments—Equity Method. Investments in entities greater than 20% and less than 50% and/or investments in which we have significant influence are accounted for under the equity method. Under the equity method, our share of investees’ earnings or loss is recognized in the statement of operations.
We review our investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, we recognize an impairment provision. For the three months ended March 31, 2016,June 30, 2023. We commenced sales on two gross (1.74 net) operated wells.
As of July 27, 2023, we recognizeddid not have an impairment loss related to our investment in Grizzly of approximately $23.1 million.
Commitments and Contingencies. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. We are involved in certain litigation for which the outcome is uncertain. Changesoperated drilling rig running in the certainty and the ability to reasonably estimate a loss amount, if any, may result in the recognition and subsequent paymentSCOOP.
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Table of legal liabilities.Contents
Derivative Instruments and Hedging Activities. We seek to reduce our exposure to unfavorable changes in oil, natural gas and natural gas liquids prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps and various types of option contracts. We follow the provisions of FASB ASC 815, “Derivatives and Hedging,” as amended. It requires that all derivative instruments be recognized as assets or liabilities in the balance sheet, measured at fair value. We estimate the fair value of all derivative instruments using industry-standard models that considered various assumptions including current market and contractual prices for the underlying instruments, implied volatility, time value and nonperformance risk, as well as other relevant economic measures.
The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. While we have historically designated derivative instruments as accounting hedges, effective January 1, 2015, we discontinued hedge accounting prospectively. Our current commodity derivative instruments are not designated as hedges for accounting purposes. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities.
See Item 3. “Quantitative and Qualitative Disclosures About Market Risk” for a summary of our derivative instruments in place as of September 30, 2017.
RESULTS OF OPERATIONS
Comparison of the Three MonthsMonth Periods Ended SeptemberJune 30, 20172023 and 20162022
We reported net income of $18.2 millionNatural Gas, Oil and Condensate and NGL Production and Pricing (sales totals in thousands)
The following table summarizes our natural gas, oil and condensate and NGL production and related pricing for the three months ended SeptemberJune 30, 2017 as compared to a net loss of $157.3 million for the three months ended September 30, 2016. This $175.5 million period-to-period increase was due primarily to a $71.8 million increase in natural gas, oil and NGL revenues and no impairment charge for the three months ended September 30, 2017 as compared to a $212.2 million impairment of oil and natural gas properties for the three months ended September 30, 2016, partially offset by a $23.9 million increase in midstream gathering and processing expenses, an $8.7 million increase in loss from equity method investments, net, a $14.3 million increase in interest expense and a $2.5 million increase in lease operating expenses for the three months ended September 30, 20172023 as compared to the three months ended SeptemberJune 30, 2016.2022. Some totals below may not sum or recalculate due to rounding.
Three Months Ended June 30, 2023Three Months Ended June 30, 2022
Natural gas sales
Natural gas production volumes (MMcf)86,078 78,122 
Natural gas production volumes (MMcf) per day946 858 
Total sales$159,246 $539,090 
Average price without the impact of derivatives ($/Mcf)$1.85 $6.90 
Impact from settled derivatives ($/Mcf)$0.57 $(3.70)
Average price, including settled derivatives ($/Mcf)$2.42 $3.20 
Oil and condensate sales
Oil and condensate production volumes (MBbl)321 426 
Oil and condensate production volumes (MBbl) per day4 5 
Total sales$22,602 $45,009 
Average price without the impact of derivatives ($/Bbl)$70.30 $105.72 
Impact from settled derivatives ($/Bbl)$1.15 $(33.55)
Average price, including settled derivatives ($/Bbl)$71.45 $72.17 
NGL sales
NGL production volumes (MBbl)1,095 1,100 
NGL production volumes (MBbl) per day12 12 
Total sales$26,070 $54,106 
Average price without the impact of derivatives ($/Bbl)$23.80 $49.17 
Impact from settled derivatives ($/Bbl)$2.47 $(4.73)
Average price, including settled derivatives ($/Bbl)$26.27 $44.44 
Natural gas, oil and condensate and NGL sales
Natural gas equivalents (MMcfe)94,578 87,279 
Natural gas equivalents (MMcfe) per day1,039 959 
Total sales$207,918 $638,205 
Average price without the impact of derivatives ($/Mcfe)$2.20 $7.31 
Impact from settled derivatives ($/Mcfe)$0.56 $(3.53)
Average price, including settled derivatives ($/Mcfe)$2.76 $3.78 
Production Costs:
Average lease operating expenses ($/Mcfe)$0.17 $0.16 
Average taxes other than income ($/Mcfe)$0.08 $0.19 
Average transportation, gathering, processing and compression ($/Mcfe)$0.91 $1.01 
Total LOE, taxes other than income and midstream costs ($/Mcfe)$1.16 $1.36 
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Natural Gas, Oil and Gas Revenues. For the three months ended September 30, 2017, we reported natural gas, oilCondensate and NGL revenues of $265.5 million as compared to oil and natural gas revenues of $193.7 million during the same period in 2016. This $71.8 million, or 37%, increase in revenues was primarily attributable to the following:Sales (in thousands)
A $58.1 million
Three Months Ended June 30, 2023Three Months Ended June 30, 2022% Change
Natural gas$159,246 $539,090 (70)%
Oil and condensate22,602 45,009 (50)%
NGL26,070 54,106 (52)%
Natural gas, oil and condensate and NGL sales$207,918 $638,205 (67)%
The decrease in natural gas, oil and NGL sales due to an unfavorable change in gains and losses from derivative instruments. Of the total change, $59.3 million was due to unfavorable changes in the fair value of our open derivative positions in each period, offset by a $1.2 million favorable change in settlements related to our derivative positions.

A $101.3 million increase in natural gas sales without the impact of derivatives when comparing the three months ended June 30, 2023, to the three months ended June 30, 2022 was due to an 8%a 73% decrease in realized natural gas prices, partially offset by a 10% increase in naturalsales volumes. The realized price change was primarily driven by the decrease in the average Henry Hub gas market prices and a 68% increaseindex from $7.17 per Mcf in natural gas sales volumes.the three months ended June 30, 2022, to $2.10 per Mcf during the three months ended June 30, 2023.

A $9.6 million increaseThe decrease in oil and condensate sales without the impact of derivatives when comparing the three months ended June 30, 2023, to the three months ended June 30, 2022, was due to a 9% increase34% decrease in realized oil and condensate market prices and a 31% increase24% decrease in oil and condensate sales volumes. The realized price change was primarily driven by the decrease in the average WTI crude index from $108.41 per barrel in the three months ended June 30, 2022, to $73.78 per barrel during the three months ended June 30, 2023.


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A $19.0 million increaseThe decrease in natural gas liquidsNGL sales without the impact of derivatives when comparing the three months ended June 30, 2023, to the three months ended June 30, 2022, was due to a 73%52% decrease in realized prices. The realized price change was primarily driven by the decrease in the average Mont Belvieu NGL index from $51.49 per barrel in the three months ended June 30, 2022, to $25.99 per barrel during the three months ended June 30, 2023.
Natural Gas, Oil and NGL Derivatives (in thousands)
Three Months Ended June 30, 2023Three Months Ended June 30, 2022
Natural gas derivatives - fair value gains$37,792 $121,659 
Natural gas derivatives - settlement gains (losses)49,444 (288,936)
Total gains (losses) on natural gas derivatives87,236 (167,277)
Oil derivatives - fair value gains2,258 4,383 
Oil derivatives - settlement gains (losses)369 (14,281)
Total gains (losses) on oil and condensate derivatives2,627 (9,898)
NGL derivatives - fair value gains4,218 9,506 
NGL derivatives - settlement gains (losses)2,707 (5,202)
Total gains on NGL derivatives6,925 4,304 
Total gains (losses) on natural gas, oil and NGL derivatives$96,788 $(172,871)
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 change in the total gain (loss) for the three months ended June 30, 2023 compared to the three months ended June 30, 2022, was primarily the result of a decrease in futures pricing for oil, natural gas, and NGLs. See Note 10 of our consolidated financial statements for hedged volumes and pricing.
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Lease Operating Expenses (in thousands, except per unit)
Three Months Ended June 30, 2023Three Months Ended June 30, 2022% Change
Lease operating expenses
Utica$10,376 $9,633 8 %
SCOOP5,779 4,613 25 %
Other— (7)(100)%
Total lease operating expenses$16,155 $14,239 13 %
Lease operating expenses per Mcfe
Utica$0.15 $0.16 (6)%
SCOOP0.24 0.17 41 %
Other— 2.73 (100)%
Total lease operating expenses per Mcfe$0.17 $0.16 5 %
The increase in total and per unit LOE for the three months ended June 30, 2023 compared to the three months ended June 30, 2022, was primarily the result of increased water hauling and labor expenses in our Utica operations and increased water hauling, compression and labor expenses throughout our SCOOP operations.
Taxes Other Than Income (in thousands, except per unit)
Three Months Ended June 30, 2023Three Months Ended June 30, 2022% Change
Production taxes$5,667 $13,620 (58)%
Property taxes1,794 1,892 (5)%
Other477 1,170 (59)%
Total taxes other than income$7,938 $16,682 (52)%
Total taxes other than income per Mcfe$0.08 $0.19 (56)%
The decrease in total and per unit taxes other than income for the three months ended June 30, 2023 compared to the three months ended June 30, 2022, was primarily related to a decrease in production taxes resulting from the decrease in our natural gas, liquids market pricesoil and NGL revenues excluding the impact of hedges discussed above.
Transportation, Gathering, Processing and Compression (in thousands, except per unit)
Three Months Ended June 30, 2023Three Months Ended June 30, 2022% Change
Transportation, gathering, processing and compression$85,664 $87,752 (2)%
Transportation, gathering, processing and compression per Mcfe$0.91 $1.01 (10)%
Transportation, gathering, processing and compression for the three months ended June 30, 2023 compared to the three months ended June 30, 2022 decreased on a 35%per unit basis primarily as a result of lower minimum volume commitments as a result of our 8% increase in naturalproduction.
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Depreciation, Depletion and Amortization (in thousands, except per unit)
Three Months Ended June 30, 2023Three Months Ended June 30, 2022% Change
Depreciation, depletion and amortization of oil and gas properties$79,940 $62,283 28 %
Depreciation, depletion and amortization of other property and equipment208 318 (35)%
Total depreciation, depletion and amortization$80,148 $62,602 28 %
Depreciation, depletion and amortization per Mcfe$0.85 $0.72 18 %
The increase in total and per unit depreciation, depletion and amortization of our oil and gas liquids sales volumes.properties for the three months ended June 30, 2023 compared to the three months ended June 30, 2022, was primarily the result of our drilling and development activities subsequent to the second quarter of 2022.

General and Administrative Expenses (in thousands, except per unit)
Three Months Ended June 30, 2023Three Months Ended June 30, 2022% Change
General and administrative expenses, gross$17,755 $16,568 7 %
Reimbursed from third parties(3,739)(3,338)12 %
Capitalized general and administrative expenses(5,405)(4,960)9 %
General and administrative expenses, net$8,611 $8,271 4 %
General and administrative expenses, net per Mcfe$0.09 $0.09 (4)%
The increase in general and administrative expenses for the three months ended June 30, 2023 compared to the three months ended June 30, 2022, was primarily driven by increases in employee headcount and compensation.
Restructuring costs
During the three months ended June 30, 2023, Gulfport recognized $2.9 million in personnel-related restructuring expenses associated with changes in the organizational structure and leadership team resulting from the appointment of Gulfport's new CEO in January 2023. Of these expenses, $0.8 million resulted from accelerated vesting of share-based grants, which are non-cash charges. As of June 30, 2023, there were no remaining employee termination liabilities for the impacted employees.
Interest Expense (in thousands, except per unit)
Three Months Ended June 30, 2023Three Months Ended June 30, 2022% Change
Interest on 2026 Senior Notes$11,000 $11,052 — %
Interest expense on Credit Facility2,808 2,496 13 %
Amortization of loan costs869 668 30 %
Capitalized interest(1,015)— 100 %
Other65 18 256 %
Total interest expense$13,727 $14,234 (4)%
Interest expense per Mcfe$0.15 $0.16 (11)%
Interest expense on our Credit Facility increased 13% for the three months ended June 30, 2023 compared to the three months ended June 30, 2022, as a result of increased interest rates resulting from the current inflationary environment. Amortization of loan costs increased by 30% for the three months ended June 30, 2023 compared to the three months ended June 30, 2022, as a result of the Third Amendment to the Credit Facility which increased the commitment and redetermined its borrowing base. See Note 3 of our consolidated financial statements for further details of our Credit Facility. The Company also capitalized $1.0 million in interest expense for the three months ended June 30, 2023 and did not capitalize interest expense for the three months ended June 30, 2022.
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Other, net (in thousands)
Three Months Ended June 30, 2023Three Months Ended June 30, 2022% Change
Other, net$(4,831)$4,282 (213)%
Other, net in the Company's consolidated statements of operations for the three months ended June 30, 2023, included a $5.0 million recoupment of previously placed collateral for certain firm transportation commitments during our Chapter 11 filing.
Other, net in the Company's consolidated statements of operations for the three months ended June 30, 2022, included a $5.1 million payment to settle certain gas imbalance positions.
Income Taxes
We did not record any income tax expense for the three months ended June 30, 2023 or 2022, as a result of maintaining a full valuation allowance against our net deferred tax asset. We expect to continue a full valuation allowance on our deferred tax assets until there is sufficient evidence to support the reversal of all or a significant portion of the allowance. However, given the Company's recent history of earnings, it is reasonably possible that sufficient positive evidence may become available within the next 12 months to adjust all or a significant portion of the current valuation allowance position. Exact timing and amount of the adjustment to the valuation allowance is unknown at this time. See Note 14 of our consolidated financial statements for further details of our valuation allowance.
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Comparison of the Six Month Periods Ended June 30, 2023 and 2022
Natural Gas, Oil and Condensate and NGL Production and Pricing (sales totals in thousands)
The following table summarizes our natural gas, oil and natural gascondensate, and NGL production and related pricing for the threesix months ended SeptemberJune 30, 2017, as compared to such data for the three months ended September 30, 2016:

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

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


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Lease Operating Expenses. Lease operating expenses, or LOE, not including production taxes increased to $20.0 million for the three months ended September 30, 2017 from $17.5 million for the three months ended September 30, 2016. This $2.5 million increase was primarily the result of an increase in expenses related to ad valorem taxes, location and facility repairs and maintenance, supervision and labor expenses, chemicals, surface rentals and water hauling, partially offset by a decrease in water disposal and workover expenses. However, due to increased efficiencies and a 63% increase in our production volumes for the three months ended September 30, 20172023 as compared to the threesix months ended SeptemberJune 30, 2016, our per unit LOE decreased by 30% from $0.26 per Mcfe to $0.18 per Mcfe.

Production Taxes. Production taxes increased $1.9 million to $5.4 million for the three months ended September 30, 2017 from $3.5 million for the three months ended September 30, 2016. This increase was related to an increase in realized prices and production volumes.
Midstream Gathering and Processing Expenses. Midstream gathering and processing expenses increased $23.9 million to $69.4 million for the three months ended September 30, 2017 from $45.5 million for the same period in 2016. This increase was primarily attributable to midstream expenses related to our increased production volumes in the Utica Shale resulting from our 2016 and 2017 drilling activities, as well as production volumes resulting from our recent SCOOP acquisition.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization,2022. Some totals below may not sum or DD&A, expense increased to $106.7 million for the three months ended September 30, 2017, and consisted of $105.1 million in depletion of oil and natural gas properties and $1.6 million in depreciation of other property and equipment, as compared to total DD&A expense of $62.3 million for the three months ended September 30, 2016. This increase wasrecalculate due to an increase in our full cost pool as a result of our SCOOP acquisition and an increase in our production, partially offset by an increase in our total proved reserves volume used to calculate our total DD&A expense.rounding.
General and Administrative Expenses. Net general and administrative expenses increased to $13.1 million for the three months ended September 30, 2017 from $10.5 million for the three months ended September 30, 2016. This $2.6 million increase was due to increases in salaries and benefits, consulting fees and bank service charges, partially offset by a decrease in employee stock compensation expense and legal fees. However, during the three months ended September 30, 2017, we decreased our unit general and administrative expense by 24% to $0.12 per Mcfe from $0.15 per Mcfe during the three months ended September 30, 2016.
Accretion Expense. Accretion expense remained relatively flat at $0.5 million and $0.3 million for the three months ended September 30, 2017 and 2016, respectively.
Interest Expense. Interest expense increased to $27.1 million for the three months ended September 30, 2017 from $12.8 million for the three months ended September 30, 2016 due primarily to the issuance of $600.0 million in aggregate principal amount of our 6.375% Senior Notes due 2025, or the 2025 Notes, in December 2016. In addition, total weighted average debt outstanding under our revolving credit facility was $273.7 million for the three months ended September 30, 2017 as compared to no debt outstanding under such facility for the same period in 2016. As of September 30, 2017, amounts borrowed under our revolving credit facility bore interest at the Eurodollar rate of 3.74%. In addition, we capitalized approximately $2.1 million and $4.7 million in interest expense to undeveloped oil and natural gas properties during the three months ended September 30, 2017 and 2016, respectively. This decrease in capitalized interest in the 2017 period was primarily due to a decrease in our average undeveloped leasehold costs in the Utica, partially offset by the SCOOP Acquisition.
Income Taxes. As of September 30, 2017, we had a federal net operating loss carryforward of approximately $606.5 million, in addition to numerous temporary differences, which gave rise to a net deferred tax asset. Periodically, management performs a forecast of our taxable income to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established if, in management’s opinion, it is more likely than not that some portion will not be realized. At September 30, 2017, a valuation allowance of $548.4 million had been provided against the net deferred tax asset, with the exception of certain state NOLs and AMT credits that we expect to be able to utilize with NOL carrybacks and tax planning in the amount of $4.7 million.
Comparison of the Nine Months Ended September 30, 2017 and 2016
We reported net income of $278.6 million for the nine months ended September 30, 2017 as compared to a net loss of $739.3 million for the nine months ended September 30, 2016. This $1.0 billion period-to-period increase was due primarily to a $600.0 million increase in natural gas, oil and NGL revenues and no impairment charge for the nine months ended September 30, 2017 as compared to a $601.8 million impairment of oil and natural gas properties for the nine months ended

Six Months Ended June 30, 2023Six Months Ended June 30, 2022
Natural gas sales
Natural gas production volumes (MMcf)171,075 161,326 
Natural gas production volumes (MMcf) per day945 891 
Total sales$441,780 $944,302 
Average price without the impact of derivatives ($/Mcf)$2.58 $5.85 
Impact from settled derivatives ($/Mcf)$0.29 $(2.48)
Average price, including settled derivatives ($/Mcf)$2.87 $3.37 
Oil and condensate sales
Oil and condensate production volumes (MBbl)747 753 
Oil and condensate production volumes (MBbl) per day4 4 
Total sales$53,316 $75,248 
Average price without the impact of derivatives ($/Bbl)$71.36 $99.99 
Impact from settled derivatives ($/Bbl)$(0.10)$(29.80)
Average price, including settled derivatives ($/Bbl)$71.26 $70.19 
NGL sales
NGL production volumes (MBbl)2,364 2,027 
NGL production volumes (MBbl) per day13 11 
Total sales$65,982 $99,390 
Average price without the impact of derivatives ($/Bbl)$27.91 $49.03 
Impact from settled derivatives ($/Bbl)$1.56 $(5.40)
Average price, including settled derivatives ($/Bbl)$29.47 $43.63 
Natural gas, oil and condensate and NGL sales
Natural gas equivalents (MMcfe)189,741 178,003 
Natural gas equivalents (MMcfe) per day1,048 983 
Total sales$561,078 $1,118,940 
Average price without the impact of derivatives ($/Mcfe)$2.96 $6.29 
Impact from settled derivatives ($/Mcfe)$0.28 $(2.44)
Average price, including settled derivatives ($/Mcfe)$3.24 $3.85 
Production Costs:
Average lease operating expenses ($/Mcfe)$0.19 $0.18 
Average taxes other than income ($/Mcfe)$0.10 $0.16 
Average transportation, gathering, processing and compression ($/Mcfe)$0.91 $0.97 
Total LOE, taxes other than income and midstream costs ($/Mcfe)$1.20 $1.31 
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September 30, 2016, partially offset by a $53.8 million increase in midstream gathering and processing expenses, a $29.9 million increase in interest expense and an $11.3 million increase in lease operating expenses for the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016.
Natural Gas, Oil and Gas Revenues. For the nine months ended September 30, 2017, we reported oil and natural gas revenues of $922.5 million as compared to oil and natural gas revenues of $322.5 million during the same period in 2016. This $600.0 million, or 186%, increase in revenues was primarily attributable to the following:
A $186.0 million increase in natural gas, oilCondensate and NGL sales due to a favorable change in gains and losses from derivative instruments. Of the total change, $313.7 million was due to favorable changes in the fair value of our open derivative positions in each period, offset by $127.7 million unfavorable change in settlements related to our derivative positions.Sales (in thousands)

Six Months Ended June 30, 2023Six Months Ended June 30, 2022% Change
Natural gas$441,780 $944,302 (53)%
Oil and condensate53,316 75,248 (29)%
NGL65,982 99,390 (34)%
Natural gas, oil and condensate and NGL sales$561,078 $1,118,940 (50)%
A $334.7 million increaseThe decrease in natural gas sales without the impact of derivatives when comparing the six months ended June 30, 2023, to the six months ended June 30, 2022 was due to a 48%56% decrease in realized prices, partially offset by a 6% increase in naturalsales volumes. The realized price change was primarily driven by the decrease in the average Henry Hub gas market prices and a 50% increaseindex from $6.06 per Mcf in natural gas sales volumes.the six months ended June 30, 2022, to $2.76 per Mcf in the six months ended June 30, 2023.

A $24.5 million increaseThe decrease in oil and condensate sales without the impact of derivatives when comparing the six months ended June 30, 2023, to the six months ended June 30, 2022, was due to a 27% increase29% decrease in oil and condensate market prices and a 10% increaserealized prices. The realized price change was driven by the decrease in oil and condensate sales volumes.the average WTI crude index from $101.35 per barrel in the six months ended June 30, 2022, to $74.95 per barrel in the six months ended June 30, 2023.

A $54.8 million increaseThe decrease in natural gas liquidNGL sales without the impact of derivatives when comparing the six months ended June 30, 2023, to the six months ended June 30, 2022, was due to a 90% increase43% decrease in natural gas liquids marketrealized prices, and a 39% increase in natural gas liquids sales volumes.


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


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Lease Operating Expenses. Lease operating expenses, or LOE, not including production taxes increased to $60.0 million for the nine months ended September 30, 2017 from $48.8 million for the nine months ended September 30, 2016. This increase was mainly the result of an increase in expenses related to supervision and labor, overhead, compressors, surface rentals, water hauling and treatment, chemicals, workover costs and road, location and equipment repairs and maintenance, partially offset by a 17% increase in NGL sales volumes. The realized price change was driven by the decrease in ad valorem taxesthe average Mont Belvieu NGL index from $52.86 per barrel in the six months ended June 30, 2022, to $30.61 per barrel in the six months ended June 30, 2023.
Natural Gas, Oil and disposal costs. However, due to increased efficienciesNGL Derivatives (in thousands)
Six Months Ended June 30, 2023Six Months Ended June 30, 2022
Natural gas derivatives - fair value gains (losses)$411,940 $(497,660)
Natural gas derivatives - settlement gains (losses)49,271 (400,093)
Total gains (losses) on natural gas derivatives461,211 (897,753)
Oil derivatives - fair value gains (losses)6,990 (25,470)
Oil derivatives - settlement gains (losses)(74)(22,425)
Total gains (losses) on oil and condensate derivatives6,916 (47,895)
NGL derivatives - fair value gains (losses)3,033 (4,827)
NGL derivatives - settlement gains (losses)3,689 (10,947)
Total gains (losses) on NGL derivatives6,722 (15,774)
Total gains (losses) on natural gas, oil and NGL derivatives$474,849 $(961,422)
We recognize fair value changes on our natural gas, oil and a 47% increaseNGL derivative instruments in our production volumeseach 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 change in the total gain (loss) for the ninesix months ended SeptemberJune 30, 2017 as2023 compared to the ninesix months ended SeptemberJune 30, 2016,2022, was primarily the result of a significant decrease in futures pricing for oil, natural gas, and NGLs. See Note 10 of our consolidated financial statements for hedged volumes and pricing.
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Lease Operating Expenses (in thousands, except per unit)
Six Months Ended June 30, 2023Six Months Ended June 30, 2022% Change
Lease operating expenses
Utica$23,011 $22,821 1 %
SCOOP13,006 9,065 43 %
Other— (3)(100)%
Total lease operating expenses$36,017 $31,883 13 %
Lease operating expenses per Mcfe
Utica$0.17 $0.18 (6)%
SCOOP0.24 0.19 26 %
Other— (0.68)(100)%
Total lease operating expenses per Mcfe$0.19 $0.18 6 %
The increase in total and per unit LOE decreased by 16% from $0.26 per Mcfe to $0.21 per Mcfe.
Production Taxes. Production taxes increased $4.9 million to $14.5 million for the ninesix months ended SeptemberJune 30, 2017 from $9.5 million2023 compared to the six months ended June 30, 2022, was primarily the result of increased water hauling, compression and labor expenses throughout our SCOOP operations and non-operated expenses in the Utica.
Taxes Other Than Income (in thousands, except per unit)
Six Months Ended June 30, 2023Six Months Ended June 30, 2022% Change
Production taxes$13,719 $23,093 (41)%
Property taxes3,639 3,785 (4)%
Other1,275 2,273 (44)%
Total taxes other than income$18,633 $29,150 (36)%
Total taxes other than income per Mcfe$0.10 $0.16 (40)%
The decrease in total and per unit taxes other than income for the same period in 2016. This increasesix months ended June 30, 2023 compared to the six months ended June 30, 2022, was primarily related to ana decrease in production taxes resulting from the decrease in our natural gas, oil and NGL revenues excluding the impact of hedges discussed above.
Transportation, Gathering, Processing and Compression (in thousands, except per unit)
Six Months Ended June 30, 2023Six Months Ended June 30, 2022% Change
Transportation, gathering, processing and compression$173,281 $172,544 — %
Transportation, gathering, processing and compression per Mcfe$0.91 $0.97 (6)%
Transportation, gathering, processing and compression for the six months ended June 30, 2023 compared to the six months ended June 30, 2022 decreased on a per unit basis primarily as a result of lower minimum volume commitments as a result of our 7% increase in realized pricesproduction.
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Depreciation, Depletion and production volumes.Amortization (in thousands, except per unit)
Midstream Gathering
Six Months Ended June 30, 2023Six Months Ended June 30, 2022% Change
Depreciation, depletion and amortization of oil and gas properties$158,707 $124,225 28 %
Depreciation, depletion and amortization of other property and equipment535 661 (19)%
Total depreciation, depletion and amortization$159,242 $124,886 28 %
Depreciation, depletion and amortization per Mcfe$0.84 $0.70 20 %
The increase in total and Processing Expenses. Midstream gatheringper unit depreciation, depletion and processing expenses increased by $53.8 million to $176.3 millionamortization of our oil and gas properties for the ninesix months ended SeptemberJune 30, 2017 from $122.5 million2023 compared to the six months ended June 30, 2022, was primarily the result of our drilling and development activities subsequent to the second quarter of 2022.
General and Administrative Expenses (in thousands, except per unit)
Six Months Ended June 30, 2023Six Months Ended June 30, 2022% Change
General and administrative expenses, gross$34,830 $31,615 10 %
Reimbursed from third parties(6,958)(6,535)6 %
Capitalized general and administrative expenses(10,528)(9,704)8 %
General and administrative expenses, net$17,344 $15,376 13 %
General and administrative expenses, net per Mcfe$0.09 $0.09 6 %
The increase in general and administrative expenses for the same period in 2016. This increasesix months ended June 30, 2023 compared to the six months ended June 30, 2022, was primarily attributable to midstreamdriven by increases in employee headcount and legal expenses related to the continued administration of our increased production volumesChapter 11 filing and settlement of firm transportation agreement as noted in Note 9 of our consolidated financial statements.
Restructuring costs
During the three months ended June 30, 2023, Gulfport recognized $4.8 million in personnel-related restructuring expenses associated with changes in the Utica Shaleorganizational structure and leadership team resulting from the appointment of Gulfport's new CEO in January 2023. Of these expenses, $1.3 million resulted from accelerated vesting of share-based grants, which are non-cash charges. As of June 30, 2023, there were no remaining employee termination liabilities for the impacted employees.
Interest Expense (in thousands, except per unit)
Six Months Ended June 30, 2023Six Months Ended June 30, 2022% Change
Interest on 2026 Senior Notes$22,000 $22,103 — %
Interest expense on Credit Facility5,833 4,764 22 %
Amortization of loan costs1,396 1,333 5 %
Capitalized interest(1,839)— 100 %
Other93 18 404 %
Total interest expense$27,483 $28,218 (3)%
Interest expense per Mcfe$0.14 $0.16 (9)%
Interest expense on our 2016 and 2017 drilling activities,Credit Facility increased 22% for the six months ended June 30, 2023 compared to the six months ended June 30, 2022, as well as production volumesa result of increased interest rates resulting from our recent SCOOP acquisition.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization, or DD&A,the current inflationary environment. The Company also capitalized $1.8 million in interest expense increased to $254.9 million for the ninesix months ended SeptemberJune 30, 2017,2023 and did not capitalize interest expense for the six months ended June 30, 2022.
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Other, net (in thousands)
Six Months Ended June 30, 2023Six Months Ended June 30, 2022% Change
Other, net$(19,054)$(10,528)81 %
Other, net in the Company's consolidated statements of operations for the six months ended June 30, 2023, included $17.8 million related to the interim TC claim distribution and a $1 million administrative payment to Rover as part of the executed settlement. The distribution and settlement is more fully described in Note 9 of our consolidated financial statements. The timing and amount of any future distributions to Gulfport are not certain, and the total amount will be impacted by the liquidating trust's distributions and resolution of other remaining bankruptcy claims. Additionally, Other, net included a $5.0 million recoupment of previously placed collateral for certain firm transportation commitments during our Chapter 11 filing.
Other, net in the Company's consolidated statements of operations for the six months ended June 30, 2022, included $11.5 million related to the initial TC claim distribution as discussed in Note 9 of our consolidated financial statements. Additionally, Other, net included a $5.1 million payment to settle certain gas imbalance positions and a $5.2 million receipt of funds from a litigation settlement.
Income Taxes
We did not record any income tax expense for the six months ended June 30, 2023 or 2022, as a result of maintaining a full valuation allowance against our net deferred tax asset. We expect to continue a full valuation allowance on our deferred tax assets until there is sufficient evidence to support the reversal of all or a significant portion of the allowance. However, given the Company's recent history of earnings, it is reasonably possible that sufficient positive evidence may become available within the next 12 months to adjust all or a significant portion of the current valuation allowance position. Exact timing and amount of the adjustment to the valuation allowance is unknown at this time. See Note 14 of our consolidated financial statements for further details of our valuation allowance.
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Liquidity and Capital Resources
Overview. We strive to maintain sufficient liquidity to ensure financial flexibility, withstand commodity price volatility, 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. We generally fund our operations, planned capital expenditures and any share repurchases with cash flow from our operating activities, cash on hand, and borrowings under our Credit Facility. Additionally, we may access debt and equity markets and sell properties to enhance our liquidity. There is no guarantee that the debt or equity capital markets will be available to us on acceptable terms or at all.
For the three and six months ended June 30, 2023, our primary sources of capital resources and liquidity have consisted of $250.5 million in depletioninternally generated cash flows from operations, and our primary uses of cash have been for development of our oil and natural gas properties and $4.4 million in depreciation of other property and equipment, as compared to total DD&A expense of $183.4 million for the nine months ended September 30, 2016. This increase was due to an increase inshare repurchases.
We believe our full cost pool as a result of our SCOOP acquisition and an increase in our production, partially offset by an increase in our total proved reserves volume used to calculate our total DD&A expense.
General and Administrative Expenses. Net general and administrative expenses increased to $37.9 million for the nine months ended September 30, 2017 from $32.9 million for the nine months ended September 30, 2016. This $5.0 million increase was due to increases in salaries and benefits, consulting fees, bank service charges, computer support and franchise taxes, partially offset by a decrease in employee stock compensation expense and legal fees. However, during the nine months ended September 30, 2017, we decreased our unit general and administrative expense by 22% to $0.13 per Mcfe from $0.17 per Mcfe during the nine months ended September 30, 2016.
Accretion Expense. Accretion expense was $1.1 million and $0.8 million for the nine months ended September 30, 2017 and 2016, respectively.
Interest Expense. Interest expense increased to $74.8 million for the nine months ended September 30, 2017 from $44.9 million for the nine months ended September 30, 2016 due primarily to the issuance of $600.0 million of the 2025 Notes in December 2016. In addition, total weighted average debt outstanding under our revolving credit facility was $146.0 million for the nine months ended September 30, 2017 as compared to no debt outstanding under such facility for the same period in 2016. Additionally, we capitalized approximately $8.8 million and $7.7 million in interest expense to undeveloped oil and natural gas properties during the nine months ended September 30, 2017 and September 30, 2016, respectively. This increase in capitalized interest in the 2017 period was primarily due to the SCOOP Acquisition.
Income Taxes. As of September 30, 2017, we had a net operating loss carryforward of approximately $606.5 million, in addition to numerous temporary differences, which gave rise to a net deferred tax asset. Periodically, management performs a forecast of our taxable income to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established if, in management’s opinion, it is more likely than not that some portion will not be realized. At September 30, 2017, a valuation allowance of $548.4 million had been provided against the net deferred tax asset, with the exception of certain state NOLs and AMT credits that we expect to be able to utilize with NOL carrybacks and tax planning in the amount of $4.7 million.
Liquidity and Capital Resources
Overview.
Historically, our primary sources of funds have beenannual free cash flow from our producing oil and natural gas properties, borrowingsgeneration, borrowing capacity under our credit facility and issuances of equity and debt securities. Our ability to access any of these sources of funds can be significantly impacted by decreases in oil and natural gas prices or oil and natural gas production.

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Net cash flow provided by operating activities was $491.7 million for the nine months ended September 30, 2017 as compared to net cash flow provided by operating activities of $245.3 million for the same period in 2016. This increase was primarily the result of an increase in cash receipts from our oil and natural gas purchasers due to a 57% increase in net revenues after giving effect to settled derivative instruments, partially offset by an increase in our operating expenses.
Net cash used in investing activities for the nine months ended September 30, 2017 was $2.0 billion as compared to $420.3 million for the same period in 2016. During the nine months ended September 30, 2017, we spent $789.7 million in additions to oil and natural gas properties, of which $528.2 million was spent on our 2017 drilling, completion and recompletion activities, $86.3 million was spent on expenses attributable to wells spud, completed and recompleted during 2016, $1.9 million was spent on facility enhancements, $96.5 million was spent on lease related costs, primarily the acquisition of leases in the Utica Shale and $7.2 million was spent on seismic, with the remainder attributable mainly to future location development and capitalized general and administrative expenses. We also spent $1.3 billion to fund the cash portion of the purchase price for our SCOOP acquisition. In addition, $1.8 million was invested in Grizzly and $39.4 million was invested in Strike Force, net of distributions, during the nine months ended September 30, 2017. We did not make any investments in our other equity investments during the nine months ended September 30, 2017.
Net cash provided by financing activities for the nine months ended September 30, 2017 was $354.1 million as compared to $426.3 million for the same period in 2016. The 2017 amount provided by financing activities is primarily attributable to borrowings under our revolving credit facility. The 2016 amount provided by financing activities is primarily attributable to the net proceeds of approximately $411.7 million from our March 2016 equity offering.
Credit Facility.
We have entered into a senior secured revolving credit facility, as amended, with The Bank of Nova Scotia, as the lead arranger and administrative agent and certain lenders from time to time party thereto. The credit agreement provides for a maximum facility amount of $1.5 billion and matures on December 13, 2021. As of September 30, 2017, we had a borrowing base of $1.0 billion and $365.0 million in borrowings outstanding, and total funds available for borrowing under our revolving credit facility, after giving effect to an aggregate of $237.5 million of outstanding letters of credit, were $397.5 million. This facility is secured by substantially all of our assets. Our wholly-owned subsidiaries guarantee our obligations under our revolving credit facility.
In connection with our fall redetermination under our revolving credit facility, the lead lenders have proposed to increase our borrowing base from $1.0 million to $1.2 billion, with an elected commitment of $1.0 billion, and decrease the interest rate by 50 basis points, subject to the approval of the additional banks within the syndicate.
Advances under our revolving credit facility may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate, which ranges from 1.00% to 2.00%, plus (2) the highest of: (a) the federal funds rate plus 0.50%, (b) the rate of interest in effect for such day as publicly announced from time to time by agent as its “prime rate,” and (c) the eurodollar rate for an interest period of one month plus 1.00%. The interest rate for eurodollar loans is equal to (1) the applicable rate, which ranges from 2.00% to 3.00%, plus (2) the London interbank offered rate that appears on pages LIBOR01 or LIBOR02 of the Reuters screen that displays such rate for deposits in U.S. dollars, or, if such rate is not available, the rate as administered by ICE Benchmark Administration (or any other person that takes over administration of such rate) per annum equal to the offered rate on such other page or other service that displays an average London interbank offered rate as administered by ICE Benchmark Administration (or any other person that takes over the administration of such rate) for deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major New York money center banks of whom the agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. As of September 30, 2017, amounts borrowed under our revolving credit facility bore interest at the Eurodollar rate of 3.74%.
Our revolving credit facility contains customary negative covenants including, but not limited to, restrictions on our and our subsidiaries’ ability to: incur indebtedness; grant liens; pay dividends and make other restricted payments; make investments; make fundamental changes; enter into swap contracts and forward sales contracts; dispose of assets; change the nature of their business; and enter into transactions with their affiliates. The negative covenants are subject to certain exceptions as specified in our revolving credit facility. Our revolving credit facility also contains certain affirmative covenants, including, but not limited to the following financial covenants: (1) the ratio of net funded debt to EBITDAX (net income, excluding (i) any non-cash revenue or expense associated with swap contracts resulting from ASC 815 and (ii) any cash or non-cash revenue or expense attributable to minority investment plus without duplication and, in the case of expenses, to the extent deducted from revenues in determining net income, the sum of (a) the aggregate amount of consolidated interest expense for

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such period, (b) the aggregate amount of income, franchise, capital or similar tax expense (other than ad valorem taxes) for such period, (c) all amounts attributable to depletion, depreciation, amortization and asset or goodwill impairment or writedown for such period, (d) all other non-cash charges, (e) exploration costs deducted in determining net income under successful efforts accounting, (f) actual cash distributions received from minority investments, (g) to the extent actually reimbursed by insurance, expenses with respect to liability on casualty events or business interruption, and (h) all reasonable transaction expenses related to dispositions and acquisitions of assets, investments and debt and equity offerings (provided that expenses related to any unsuccessful dispositions will be limited to $3.0 million in the aggregate) for a twelve-month period may not be greater than 4.00 to 1.00; and (2) the ratio of EBITDAX to interest expense for a twelve-month period may not be less than 3.00 to 1.00. We were in compliance with these financial covenants at September 30, 2017.
Senior Notes.
In October 2012, December 2012 and August 2014, we issued an aggregate of $600.0 million in principal amount of our 7.75% Senior Notes due 2020 which were issued under an indenture among us, our subsidiary guarantors and Wells Fargo Bank, National Association, as the trustee, and are referred to collectively as the 2020 Notes. In October 2016, we repurchased (in a cash tender offer) or redeemed all of the 2020 Notes, of which $600.0 million in aggregate principal amount was then outstanding, with the net proceeds from the issuance of our 6.000% Senior Notes due 2024, which are discussed below and are referred to herein as the 2024 Notes,Facility and cash on hand will provide sufficient liquidity to fund our operations, capital expenditures, interest expense and share repurchases during the indenture governingnext 12 months.
To the 2020 Notes was fully satisfiedextent actual operating results, realized commodity prices or uses of cash differ from our assumptions, our liquidity could be adversely affected. See Note 3 of our consolidated financial statements for further discussion of our debt obligations, including the principal and discharged.carrying amounts of our senior notes.
In April 2015,As of June 30, 2023, we issued an aggregatehad $5.3 million of $350.0cash and cash equivalents, $99.0 million inof borrowings under our Credit Facility, $74.4 million of letters of credit outstanding, and $550 million of outstanding 2026 Senior Notes. Our total principal amount of funded debt as of June 30, 2023 was $649.0 million.
As of July 27, 2023 we had $6.7 million of cash and cash equivalents, $92.0 million in borrowings under our 6.625%Credit Facility, $71.8 million of letters of credit outstanding, and $550 million of outstanding 2026 Senior Notes.
Debt. On October 14, 2021, we entered into the Third Amended and Restated Credit Agreement JPMorgan Chase Bank, N.A., as administrative agent, and various lender parties. The Existing Credit Facility provides for an aggregate maximum principal amount of up to $1.5 billion. 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.
On May 2, 2022, the Company completed its semi-annual borrowing base redetermination and entered into the Amendment to Borrowing Base Redetermination Agreement and First Amendment to our Credit Agreement, which amended the Existing Credit Facility. The amendment, among other things, (a) increased the borrowing base under the Credit Facility from $850 million to $1.0 billion with elected commitments remaining at $700 million, (b) amended certain covenants related to hedging to ease certain requirements and limitations and (c) amended the covenants governing restricted payments to (i) increase the Net Leverage Ratio allowing unlimited restricted payments from 1.00 to 1.00 to 1.25 to 1.00 and (ii) permit additional restricted payments to redeem preferred equity until December 31, 2022 provided certain leverage, no event of default or borrowing base deficiency and availability tests are met and (d) provided for the transition from a LIBOR to a SOFR benchmark, with a 10 basis point credit spread adjustment for all tenors.
On October 31, 2022, the Company completed its semi-annual borrowing base redetermination and entered into the Borrowing Base Reaffirmation Agreement and Second Amendment to our Credit Agreement, which amended the Existing Credit Facility. The amendment, among other things, reconfirmed the borrowing base under the Credit Facility at $1.0 billion and the elected commitments at $700 million.
On May 1, 2023, the Company entered into that certain Joinder, Commitment Increase and Borrowing Base Redetermination Agreement, and Third Amendment to Credit Agreement (the “Third Amendment”) which amended the Company’s Existing Credit Facility (as amended, the “Credit Facility”). The Third Amendment, among other things, (a) increased the aggregate elected commitment amounts under the Credit Facility from $700 million to $900 million, (b) increased the borrowing base under the Credit Facility from $1 billion to $1.1 billion, (c) increased the excess cash threshold under the Credit Facility from $45 million to $75 million, and (d) extended the maturity date under the Credit Facility from October 14, 2025 to the earlier of (i) May 1, 2027 and (ii) the 91st day prior to the maturity date of the 2026 Senior Notes due 2023. Interest on theseor any other permitted senior notes whichor any permitted refinancing debt under the Credit Facility having an aggregate outstanding principal amount equal to or exceeding $100 million; provided that such notes have not be refinanced, redeemed or repaid in full on or prior to such 91st day.
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Additionally, on the Emergence Date, pursuant to the terms of the Plan, we referissued our 2026 Senior Notes. The 2026 Senior Notes are guaranteed on a senior unsecured basis by each of the Company's subsidiaries that guarantee the Credit Facility.
See Note 3 of our consolidated financial statements for additional discussion of our outstanding debt.
Preferred Dividends. As discussed in Note 4 of our consolidated financial statements, holders of preferred stock are entitled to as the 2023 Notes, accruesreceive cumulative quarterly dividends at a rate of 6.625%10% per annum on the outstanding principal amount thereof from April 21, 2015, payable semi-annually on May 1 and November 1 of each year, commencing on November 1, 2015. The 2023 Notes will mature on May 1, 2023.
On October 14, 2016, we issued the 2024 Notes in aggregate principal amount of $650.0 million. Interest on the 2024 Notes accrues at a rate of 6.000% per annum on the outstanding principal amount thereof from October 14, 2016, payable semi-annually on April 15 and October 15 of each year, commencing on April 15, 2017. The 2024 Notes will mature on October 15, 2024. We received approximately $638.9 million in net proceeds from the offering of the 2024 Notes, which was used, together with cash on hand, to purchase the outstanding 2020 Notes in a concurrent cash tender offer, to pay fees and expenses thereof, and to redeem any of the 2020 Notes that remained outstanding after the completion of the tender offer.
On December 21, 2016, we issued $600.0 million in aggregate principal amount of 2025 Notes. Interest on the 2025 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof from December 21, 2016, payable semi-annually on May 15 and November 15 of each year, commencing on May 15, 2017. The 2025 Notes will mature on May 15, 2025. We received approximately $584.7 million in net proceeds from the offering of the 2025 Notes, which we used, together with the net proceeds from our December 2016 offering of common stock and cash on hand, to fund the cash portion of the purchase price for the SCOOP acquisition.
In connection with the issuance of the 2024 Notes and the 2025 Notes, we and our subsidiary guarantors entered into two registration rights agreements, pursuant to which we agreed to file a registration statementLiquidation Preference with respect to offerscash dividends and 15% per annum of the Liquidation Preference with respect to exchangedividends paid in kind as additional shares of preferred stock (“PIK Dividends”). We currently have the 2024 Notesoption to pay either cash dividends or PIK Dividends on a quarterly basis.
During the three and six months ended June 30, 2023, the 2025 Notes for new issuesCompany paid $1.3 million and $2.6 million, respectively, of substantially identical debt securities registered under the Securities Act. The exchange offers for the 2024 Notescash dividends to holders of our preferred stock compared to $1.4 million and the 2025 Notes were completed on September 13, 2017.
On October 11, 2017, we issued $450.0$2.8 million in aggregate principal amount of our 2026 Notes. Interest on the 2026 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof from October 11, 2017, payable semi-annually on January 15three and July 15 of each year, commencing on January 15, 2018.six months ended June 30, 2022, respectively.
Supplemental Guarantor Financial Information. The 2026 Senior Notes will matureare guaranteed on January 15, 2026. A portion of the net proceeds from the issuance of the 2026 Notes was used to repaya senior unsecured basis by all of our outstanding borrowings under our secured revolving credit facility on October 11, 2017 and the balance will be used to fund the remaining anticipated outspend related to our 2017 capital development plans.
All of our existing and future restrictedconsolidated subsidiaries that guarantee our secured revolving credit facilityCredit Facility or certain other debt guarantee the 2023 Notes, 2024 Notes and 2025 Notes; provided, however, that the 2023 Notes, 2024 Notes and 2025(the “Guarantors”). The 2026 Senior Notes are not guaranteed by Grizzly Holdings Inc.or Mule Sky, LLC (the “Non-Guarantors”). The Guarantors are 100% owned by the Parent, and will not be guaranteed by anythe guarantees are full, unconditional, joint and several. There are no significant restrictions on the ability of our future unrestricted subsidiaries.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 2023 Notes, 2024 Notes and 20252026 Senior Notes and the guarantees are effectively subordinated to all of our and the subsidiary guarantors’guarantors' secured indebtedness (including all borrowings and other obligations under our amended and restated credit agreement) to the extent of the value of

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the collateral securing such indebtedness, and structurally subordinated to all indebtedness and other liabilities of any of our subsidiaries that do not guarantee the 2023 Notes, 2024 Notes2026 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 2025 Notes.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.
IfDerivatives 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 experience a changehave entered into various derivative instruments. Our natural gas, oil and NGL derivative activities, when combined with our sales of control (as defined innatural gas, oil and NGL, allow us to predict with greater certainty the senior note indentures relating to the 2023 Notes, 2024 Notes and 2025 Notes),total revenue we will be required to make an offer to repurchasereceive. See Item 3 Quantitative and Qualitative Disclosures About Market Risk for further discussion on the 2023 Notes, 2024 Notes and 2025 Notes and at aimpact of commodity price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase. If we sell certain assets and fail to use the proceeds in a manner specified inrisk on our senior note indentures, we will be required to use the remaining proceeds to make an offer to repurchase the 2023 Notes, 2024 Notes and 2025 Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase. The senior note indentures relating to the 2023 Notes, 2024 Notes and 2025 Notes contain certain covenants that, subject to certain exceptions and qualifications, among other things, limit our ability and the abilityfinancial position. Additionally, see Note 10 of our restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make distributions on capital stock, prepay subordinated indebtedness, sell assets including capital stockconsolidated financial statements for further discussion of restricted subsidiaries, agree to payment restrictions affecting our restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of our assets, enter into transactions with affiliates, incur liens, engage in business other than the oilderivatives and gas business and designate certain of our subsidiaries as unrestricted subsidiaries. Under the indenture relating to the 2023 Notes, 2024 Notes and 2025 Notes, certain of these covenants are subject to termination upon the occurrence of certain events, including in the event the 2023 Notes, 2024 Notes and 2025 Notes are ranked as “investment grade.”hedging activities.
Construction Loan.
On June 4, 2015, we entered into a construction loan agreement, or the construction loan, with InterBank for the construction of our new corporate headquarters in Oklahoma City, which was substantially completed in December 2016. The construction loan allows for maximum principal borrowings of $24.5 million and required us to fund 30% of the cost of the construction before any funds could be drawn, which occurred in January 2016. Interest accrues daily on the outstanding principal balance at a fixed rate of 4.50% per annum and was payable on the last day of the month through May 31, 2017. Monthly interest and principal payments are due beginning June 30, 2017, with the final payment due June 4, 2025. As of September 30, 2017, the total borrowings under the construction loan were approximately $23.8 million.
Capital Expenditures.
Our recent capital commitmentsexpenditures have historically been primarily forrelated to the execution of our drilling programs, for acquisitionsand completion activities in the Utica Shale and our recent SCOOPaddition to certain lease acquisition and for investments in entities that may provide services to facilitate the development of our acreage.activities. Our capital investment strategy is to continue to (1) increase cash flow generated from our operations by undertaking new drilling, workover, sidetrack and recompletion projects to exploitfocused on prudently developing our existing properties subject to economicgenerate sustainable cash flow considering current and industry conditions, (2) pursue acquisition and disposition opportunities and (3) pursue business integration opportunities.
Of our net reserves at December 31, 2016, 63.0% were categorized as proved undeveloped. Our proved reserves will generally decline as reserves are depleted, except toforecasted commodity prices. For the extent that we conduct successful exploration or development activities or acquire properties containing proved developed reserves, or both. To realize reserves and increase production, we must continue our exploratory drilling, undertake other replacement activities or use third parties to accomplish those activities.
From January 1, 2017 through November 1, 2017, we spud 89 gross (84.1 net) wells insix months ended June 30, 2023, the Utica Shale. We currently expect to spud 96 gross (91 net) horizontal wells and commence sales from 68 gross (61 net) wells on our Utica Shale acreage during 2017. As of November 1, 2017, we had four operated horizontal rigs drilling in the play. We also anticipate an additional 24 gross (eight net) horizontal wells will be drilled, and sales commenced from 45 gross (nine net) horizontal wells, on our Utica Shale acreage by other operators during 2017. We currently anticipate our 2017Company's incurred capital expenditures to be approximately $735.0totaled $276.2 million, of which $237.7 million related to our operated and non-operated Utica Shale drilling and completion activity.
From January 1, 2017 through November 1, 2017, 16 gross (13.6 net) wells were spud in the SCOOP. We currently anticipate our 2017 capital expenditures to be approximately $215.0activity and $38.5 million related to our operatedleasehold and non-operated SCOOP drilling and completion activity. We currently expect to spud 22 gross (18 net) wells and commence sales from 18 gross (16 net) wells on the SCOOP acreage during 2017. As of November 1, 2017, we had four operated horizontal rigs drilling in the play. We also anticipate 30 gross (one net) wells will be drilled, and sales commenced from 11 gross (one net) wells on this SCOOP acreage by other operators during 2017.
In addition, we currently expect to spend an aggregate of approximately $130.0 million in 2017 for acreage expenses, primarily lease extensions, in the Utica Shale and SCOOP.

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From January 1, 2017 through November 1, 2017, we spud ten new wells and recompleted 59 existing wells at our WCBB field. In our Hackberry fields, from January 1, 2017 through November 1, 2017, we spud five new wells and recompleted 20 existing wells. We currently expect to spend approximately $35.0 million in 2017 to drill 15 gross and net wells and perform recompletion activities in Southern Louisiana.
From January 1, 2017 through November 1, 2017, no new wells were spud on our Niobrara Formation acreage. We do not currently anticipate any capital expenditures in the Niobrara Formation in 2017.
As of September 30, 2017, our net investment in Grizzly was approximately $58.7 million. We do not currently anticipate any material capital expenditures in 2017 related to Grizzly’s activities.
We had no capital expenditures during the nine months ended September 30, 2017 related to our interests in Thailand. We do not currently anticipate any capital expenditures in Thailand in 2017.
In an effort to facilitate the development of our Utica Shale and other domestic acreage, we have invested in entities that can provide services that are required to support our operations. See Note 3 to our consolidated financial statements included elsewhere in this report for additional information regarding these other investments. During the nine months ended September 30, 2017, we paid $39.4 million in net cash calls related to Strike Force. We currently anticipate that we will make approximately $45.0 million in cash contributions to Strike Force in 2017. We did not make any investments in any other of these entities during the nine months ended September 30, 2017, and we do not currently anticipate any capital expenditures related to these entities in 2017.
During 2015 and 2016, we continued to focus on operational efficiencies in an effort to reduce our overall well costs and deliver better results in a more economical manner, particularly in light of the continued downturn in commodity prices. We have successfully leveraged the lower commodity price environment to gain access to higher-quality equipment and superior services for reduced costs, which has contributed to increased productivity. We have also renegotiated the contracts for our horizontal drilling rigs and locked in approximately 85% of our currently anticipated Utica Shale drilling and completion costs for 2017. This has allowed us to secure a base level of activity for 2017, hedge against expected increases in service costs and ensure access to quality equipment and experienced crews, all of which we expect to contribute to further efficiency gains.
In 2017, we focused our leasehold efforts on adding acreage organically within units scheduled in our near-term development plan. This strategy has allowed us to focus our leasehold spend on the highest return potential for deployed capital, resulting in the acquisition of additional core acreage in the dry gas window of the Utica play. These efforts, coupled with our active leasehold trading efforts, have led to a significant increase in our working interests on wells spud in the Utica Shale during 2017, equating to an incremental 22.0 net wells spud, thereby resulting in an increase in our anticipated capital expenditures this year.land investment.
Our total capital expenditures for 20172023 are currently estimated to be $985.0in the range of $375 million to $400 million for drilling and completion expenditures, of which $846.0 million was spent as of September 30, 2017. In addition,expenditures. Also, we currently expect to spend approximately $130.0$50 million to $75 million in 20172023 for maintenance leasehold and land investment, which is focused on near-term drilling programs and facilitating increases in our working interests and lateral footage in units we plan to drill in 2023 and 2024. We expect this capital program to result in approximately 1,035 to 1,055 MMcfe per day of production in 2023.
Additionally, we are pursuing accretive acreage expenses,opportunities that expand our resource depth and provide optionality to our near term development plans and intend to allocate approximately $40 million in discretionary acreage acquisitions.
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Sources and Uses of Cash
The following table presents the major changes in cash and cash equivalents for the six months ended June 30, 2023 and 2022 (in thousands):
Six Months Ended June 30, 2023Six Months Ended June 30, 2022
Net cash provided by operating activities$411,406 $383,200 
Additions to oil and natural gas properties(283,406)(181,787)
Debt activity, net(46,000)(40,000)
Repurchases of common stock(74,516)(155,212)
Preferred stock dividends(2,587)(2,828)
Other(6,887)(52)
Net change in cash, cash equivalents and restricted cash$(1,990)$3,321 
Cash, cash equivalents and restricted cash at end of period$5,269 $6,581 
Net cash provided by operating activities. Net cash flow provided by operating activities was $411.4 million for the six months ended June 30, 2023, as compared to $383.2 million for the six months ended June 30, 2022. The increase was primarily lease extensionsthe result of a decrease in cash payments from settled derivative instruments due to decreased realized commodities pricing.
Additions to oil and natural gas properties. During the six months ended June 30, 2023, we spud eight gross (7.0 net) operated wells and completed and commenced sales from 11 gross (10.2 net) operated wells in the Utica Shale,for a total incurred cost of which $98.0 million was spent asapproximately $205.8 million. During the six months ended June 30, 2023, we spud and commenced sales from two gross (1.7 net) operated wells in the SCOOP for a total incurred cost of September 30, 2017,approximately $28.6 million.
Drilling and approximately $45.0 million to fund our investment in Strike Force, of which $39.4 million was spent as of September 30, 2017. Approximately 75% and 22% of our 2017 estimatedcompletion costs discussed above reflect incurred costs while drilling and completion costs presented in the table below reflect cash payments for drilling and completions. Incurred capital expenditures are currently expected to be spent in the Utica Shale and in the SCOOP play in Oklahoma, respectively. The 2017 range ofcash capital expenditures is higher than the $549.5 million spent in 2016, primarilymay vary from period to period due to the increasecash payment cycle. Cash capital expenditures for the six months ended June 30, 2023 and 2022, were as follows (in thousands):
Six Months Ended June 30, 2023Six Months Ended June 30, 2022
Oil and Natural Gas Property Cash Expenditures:
Drilling and completion costs$234,720 $156,732 
Leasehold acquisitions38,322 16,194 
Other10,364 8,861 
Total oil and natural gas property expenditures$283,406 $181,787 
Debt activity, net. In the six months ended June 30, 2023, the Company had $472.0 million and $518.0 million in current commodity pricesborrowings and repayments, respectively, on its Credit Facility. As of July 27, 2023 the Company had $92.0 million in borrowings outstanding on its Credit Facility.
Repurchases of common stock. During the six months ended June 30, 2023, the Company repurchased 900,599 shares for approximately $74.2 million under the Repurchase Program at a weighted average price of $82.42 per share. For the same period in 2022, the Company repurchased 1,853,985 shares for $163.0 million at a weighted average price of $87.93 per share. As of July 27, 2023, we repurchased 3.8 million shares for approximately $325.0 million under the Repurchase Program at a weighted average price of $85.51 per share.
Preferred stock dividends. During the six months ended June 30, 2023, the Company paid $2.6 million of cash dividends to holders of our expansion into and exploratory activitiespreferred stock compared to $2.8 million in the SCOOP play in Oklahoma.
We continually monitor market conditions and are prepared to adjust our drilling program if commodity prices dictate. Currently, we believe that our cash flow from operations, cash on hand and borrowings under our loan agreements will be sufficient to meet our normal recurring operating needs and capital requirements for the next twelve months. We believe that our strong liquidity position, hedge portfolio and conservative balance sheet position us well to react quickly to changing commodity prices and accelerate our activity within our Utica Basin and Mid-Continent operating areas, or to scale back our activity, as the market conditions warrant. Notwithstanding the foregoing, in the event commodity prices decline from current levels, our capital or other costs increase, our equity investments require additional contributions and/or we pursue additional equity method investments or acquisitions, we may be required to obtain additional funds which we would seek to do through traditional borrowings, offerings of debt or equity securities or other means, including the sale of assets. We regularly evaluate new acquisition opportunities. Needed capital may not be available to us on acceptable terms or at all. Further, if we are unable to obtain funds when needed or on acceptable terms, we may be required to delay or curtail implementation of our business plan or not be able to complete acquisitions that may be favorable to us. If the current low commodity price

six months ended June 30, 2022.
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environment worsens, our revenues, cash flows, resultsOther. During the six months ended June 30, 2023, the Company paid other expenses of operations, liquidity and reserves may be materially and adversely affected.
Commodity Price Risk
See Item 3. “Quantitative and Qualitative Disclosures about Market Risk” for information regarding our open fixed price swaps at September$6.9 million, as compared to other expenses of $0.1 million paid during the six months ended June 30, 2017.
Commitments
In connection with our acquisition2022. The increase was primarily related to a $6.8 million increase in 1997debt issuance costs as a result of the remaining 50% interestThird Amendment to the Credit Facility which increased the commitment and redetermined its borrowing base, as discussed in the WCBB properties, we assumed the seller’s (Chevron) obligation to contribute approximately $18,000 per month through March 2004, to a plugging and abandonment trust and the obligation to plug a minimumNote 3 of 20 wells per year for 20 years commencing March 11, 1997. Chevron retained a security interest in production from these properties until our abandonment obligations to Chevron have been fulfilled. Beginning in 2009, we can access the trust for use in plugging and abandonment charges associated with the property. As of September 30, 2017, the plugging and abandonment trust totaled approximately $3.1 million. At September 30, 2017, we have plugged 551 wells at WCBB since we began our plugging program in 1997, which management believes fulfills our minimum plugging obligation.consolidated financial statements.
Contractual and Commercial Obligations
We have various contractual obligations in the normal course of our operations and financing activities.activities, as discussed in Note 9 of our consolidated financial statements. There have been no other material changes to our contractual obligations from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2016.    2022.    
Off-balance Sheet Arrangements
We had nomay enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of June 30, 2023, our material off-balance sheet arrangements and transactions include $74.4 million in letters of credit outstanding against our Credit Facility and $37.8 million in surety bonds issued. Both the letters of credit and surety bonds are being used as of September 30, 2017.
New Accounting Pronouncements
In May 2014,financial assurance, primarily on certain firm transportation agreements. Additionally, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers, which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition,Company entered into various contractual commitments to purchase inventory and most industry-specific guidance. The core principle of the new standard is for the recognition of revenue to depict the transfer of goods or services to customers in amounts that reflect the payment to which we expectother material to be entitledused in exchangefuture activities. The Company's commitment to purchase these materials spans 2023 and 2024, with approximately $39.6 million remaining in 2023 and $31.2 million for those goods2024. There are no other transactions, arrangements or services. The new standard will also result in enhanced revenue disclosures, provide guidance for transactionsother relationships with unconsolidated entities or other persons that were not previously addressed comprehensively and improve guidance for multiple-element arrangements. The ASU is effective for annual periods beginning after December 15, 2016, and interim periods within those years. The new standard permits retrospective application using eitherare reasonably likely to materially affect our liquidity or availability of the following methodologies: (i) restatementour capital resources. See Note 9 of each prior reporting period presented (full retrospective method) or (ii) recognition of a cumulative-effect adjustment as of the date of initial application (modified retrospective method). In July 2015, the FASB decided to defer the effective date by one year (until 2018). We are evaluating the impact of this ASU on our consolidated financial statements and working to identify any potential differences that would result from applying the requirementsfor further discussion of the ASU to existing contractsvarious financial guarantees we have issued.
Critical Accounting Policies and currentEstimates
As of June 30, 2023, there have been no significant changes in our critical accounting policies and practices. This evaluation requires, among other things, a review of the contracts we have with customers within each of three revenue streams identified withinfrom those disclosed in our business. including natural gas sales, oil and condensate sales and natural gas liquid sales. We do not believe further disaggregation of revenue will be required under the new standard. Substantially all of our revenue is earned pursuant to agreements under which we have currently interpreted one performance obligation, which is satisfied at a point-in-time. As part of the evaluation work to-date, we have substantially completed our contract reviews and documentation. Due to industry-wide ongoing discussions2022 Annual Report on certain application issues, we cannot reasonably estimate the expected financial statement impact; however, we do not expect the impact of the application of the new standard to be material on net income or cash flows based on the reviews performed to-date. We are currently assessing the requirements of additional disclosures and documentation of new policies, procedures, system, control and data requirements. Our expectation is to adopt the standard on January 1, 2018, using the modified retrospective method. Based on the analysis to-date, we have not identified any material impact on our consolidated financial statements other than additional disclosures requirements.
In February 2016, the FASB issued ASU No. 2016-02, Leases. The guidance requires the lessee to recognize most leases on the balance sheet thereby resulting in the recognition of lease assets and liability for those leases currently classified as operating leases. The accounting for lessors is largely unchanged. The guidance is effective for periods after December 15,

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

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

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

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Instruments. This ASU amends guidance on reporting credit losses for assets held at amortized cost basis and available for sale debt securities. For assets held at amortized cost basis, this ASU eliminates the probable initial recognition threshold in current GAAP and instead, requires an entity to reflect its current estimate of all expected credit losses. The amendments affect loans, debt securities, trade receivables, net investments in leases, off balance sheet credit exposure, reinsurance receivables and any other financial assets not excluded from the scope that have the contractual right to receive cash. We are currently evaluating the impact this standard will have on our financial statements and related disclosures and do not anticipate it to have a material affect.

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

In December 2016, the FASB issued ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers. This guidance updates narrow aspects of the guidance issued in Update 2014-09. This amendment is effective for periods after December 15, 2017, with early adoption permitted. We in the process of evaluating the impact of this ASU on our consolidated financial statements.
In January 2017, the FASB issued ASU No. 2017-01, Clarifying the Definition of a Business. Under the current business combination guidance, there are three elements of a business: inputs, processes and outputs. The revised guidance adds an initial screen test to determine if substantially all of the fair value of the gross assets acquired is concentrated in a single asset or group of similar assets. If that screen is met, the set of assets is not a business. The new framework also specifies the minimum required inputs and processes necessary to be a business. This amendment is effective for periods after December 15, 2017, with early adoption permitted. We are in the process of evaluating the impact of this ASU on our consolidated financial statements.
ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Natural Gas, Oil and Natural Gas Liquids Derivative Instruments. Our revenues, operating results profitability, future rate of growthoperations and the carrying valuecash flows are impacted by changes in market prices for natural gas, oil and NGL. To mitigate a portion of our exposure to adverse price changes, we have entered into various derivative instruments. Our natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to predict with greater certainty the revenue we will receive. We believe our derivative instruments continue to be highly effective in achieving our risk management objectives.
Our general strategy for protecting short-term cash flow and attempting to mitigate exposure to adverse natural gas, oil and NGL price changes is to hedge into strengthening natural gas, oil and NGL futures markets when prices reach levels that management believes provide reasonable rates of return on our invested capital. Information we consider in forming an opinion about future prices includes general economic conditions, industrial output levels and expectations, producer breakeven cost structures, liquefied natural gas trends, oil and natural gas properties depend primarily upon the prevailing pricesstorage inventory levels, industry decline rates for oilbase production and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuationsweather trends. Executive management is involved in response to changes in supply and demand, market uncertainty and a variety of additional factors, including: worldwide and domestic supplies of oil and natural gas; the level of prices, and expectations about future prices, of oil and natural gas; the cost of exploring for, developing, producing and delivering oil and natural gas; the expected rates of declining current production; weather conditions, including hurricanes, that can affect oil and natural gas

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operations over a wide area; the level of consumer demand; the price and availability of alternative fuels; technical advances affecting energy consumption; risks associated with operating drilling rigs; the availability of pipeline capacity; the price and level of foreign imports; domestic and foreign governmental regulations and taxes; the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; political instability or armed conflict in oil and natural gas producing regions;all risk management activities and the overall economic environment.board of directors reviews our derivative program at its quarterly board meetings.
These factorsWe use derivative instruments to achieve our risk management objectives, including swaps, options and the volatilitycostless collars. All of these are described in more detail below. We typically use swaps for a large portion of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. Duringrisk we hedge. We have also sold calls in the past seven years, the posted price for WTI, has ranged from a lowto take advantage of $26.05 per barrel, or Bbl, in February 2016 to a high of $113.39 per Bbl in April 2011. The Henry Hub spotpremiums 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 natural gas has rangedexisting producing reserve estimates and estimates of estimated production from a lownew drilling. Production forecasts are updated at least monthly and adjusted if necessary to actual results and activity levels. We do not enter into derivative contracts for volumes in excess of $1.61 per MMBtuour share of forecasted production, and if production estimates were lowered for future periods and derivative instruments are already executed for some volume above the new production forecasts, the positions are typically reversed. The actual fixed prices on our derivative instruments is derived from the reference prices from third-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 March 2016 to a high of $7.51 per MMBtu in January 2010. On October 27, 2017, the WTI posted price for crude oil was $53.90 per Bblcontract and the Henry Hub spotfloating-price, resulting in a net amount due to or from the counterparty.
We review our derivative positions continuously and if future market priceconditions change and prices are at levels we believe could jeopardize the effectiveness of natural gas was $2.78 per MMBtu. Ifa position, we will mitigate this risk by either negotiating a cash settlement with our counterparty, restructuring the prices of oil and natural gas decline fromposition or entering a new trade that effectively reverses the current levels, our operations, financial condition and level of expenditures forposition. The factors we consider in closing or restructuring a position before the development of our oil and natural gas reserves may be materially and adversely affected. In addition, lower oil and natural gas prices may reducesettlement date are identical to those we review when deciding to enter the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to write down, as a non-cash charge to earnings,original derivative position.
We have determined the carryingfair 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. 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 11 of our consolidated financial statements for further discussion of the fair value measurements associated with our derivatives.
As of June 30, 2023, our natural gas, oil and natural gas properties. Reductions in our reserves could also negatively impact the borrowing base under our revolving credit facility, which could further limit our liquidity and ability to conduct additional exploration and development activities.
To mitigate the effectsNGL derivative instruments consisted of commodity price fluctuations on our oil and natural gas production, we had the following opentypes 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 positions at September 30, 2017: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.
•Costless Collars: 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 counterparty.
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 LocationDaily Volume (MMBtu/day) Weighted
Average Price
Remaining 2017NYMEX Henry Hub765,000
 $3.19
2018NYMEX Henry Hub898,000
 $3.06
2019NYMEX Henry Hub112,000
 $3.01
 LocationDaily Volume
(Bbls/day)		 Weighted
Average Price
Remaining 2017ARGUS LLS1,500
 $53.12
2018ARGUS LLS1,000
 $53.91
Remaining 2017NYMEX WTI4,500
 $54.89
2018NYMEX WTI3,000
 $52.24

 LocationDaily Volume
(Bbls/day)		 Weighted
Average Price
Remaining 2017Mont Belvieu C33,000
 $26.63
2018Mont Belvieu C33,500
 $28.03
Remaining 2017Mont Belvieu C5250
 $49.14
2018Mont Belvieu C5500
 $46.62
•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 usedwe would receive the associated premiums to enhanceexcess on bought call options. If the market price settles below the fixed price for a portion of the fixed price natural gas swaps listed above. Each short call option, has an established ceiling price. When the referenced settlement priceno payment is above the price ceiling established by these short call options, we pay our counterparty an amount equal to the difference between the referenced settlement price and the price ceiling multiplied by the hedged contract volume.due from either party.

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 LocationDaily Volume (MMBtu/day) Weighted Average Price
Remaining 2017NYMEX Henry Hub65,000
 $3.11
2018NYMEX Henry Hub103,000
 $3.25
2019NYMEX Henry Hub135,000
 $3.07
For a portion of the combined natural gas derivative instruments containing fixed price swaps and sold call options, the counterparty has an option to extend the original terms an additional twelve months for the period January 2018 through December 2018. The option to extend the terms expires in December 2017. If extended, we would have additional fixed price swaps for 30,000 MMBtu per day at a weighted average price of $3.36 per MMBtu and additional short call options for 30,000 MMBtu per day at a weighted average ceiling price of $3.36 per MMBtu.
For a portion of the natural gas fixed price swaps listed above, the counterparty has an option to extend the original terms an additional twelve months for the period January 2019 through December 2019. The option to extend the terms expires in December 2018. If executed, we would have additional fixed price swaps for 100,000 MMBtu per day at a weighted average price of $3.05 per MMBtu.
In addition, we have entered into natural gas basis swap positions, which settle on the pricing index to basis differential of NGPL Mid-Continent to NYMEX Henry Hub natural gas price. As of September 30, 2017, we had the following natural gas basis swap positions for NGPL Mid-Continent.
 LocationDaily Volume (MMBtu/day) Hedged Differential
Remaining 2017NGPL Mid-Continent50,000
 $(0.26)
2018NGPL Mid-Continent12,000
 $(0.26)
Under our 2017 contracts, we have hedged approximately 62% to 64% of our estimated 2017 production. SuchOur hedge arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oilcommodity prices increase. At SeptemberJune 30, 2017,2023, we had a net liabilityasset derivative position of $7.1$74.1 million as compared to a net liability derivative position of $2.5$347.9 million as of September 30, 2016, related to our fixed price swaps.December 31, 2022. 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 $147.9$119.5 million, while a 10% decrease in underlying commodity prices would have increased the fair value of these instrumentsdecreased our liability by approximately $147.9$115.6 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 agreementCredit Facility is structured under floating rate terms, as advances under this facilitythese facilities may be in the form of either base rate loans or eurodollarterm benchmark loans. As such, our interest expense is sensitive to fluctuations in the prime rates in the U.S.United States, or, if the eurodollarterm benchmark rates are elected, the eurodollarterm benchmark rates. At SeptemberJune 30, 2017,2023, we had $365.0$99.0 million inoutstanding borrowings outstanding under our credit facilityCredit Facility which bore interest at the eurodollara weighted average rate of 3.74%. A 1.0% increase in the average interest rate7.85% for the ninesix months ended SeptemberJune 30, 2017 would have resulted in an estimated $0.8 million increase in interest expense.2023. As of SeptemberJune 30, 2017,2023, we did not have any interest rate swaps to hedge our interest rate risks.
ITEM 4.CONTROLS AND PROCEDURES
Evaluation of Disclosure Control and Procedures. Under the directionsupervision of our Chief Executive Officer and President and our Chief Financial Officer, and with participation of management, we have established disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and President and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.
As of SeptemberJune 30, 2017,2023, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and President and our Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our

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evaluation, our Chief Executive Officer and President and our Chief Financial Officer have concluded that, as of SeptemberJune 30, 2017,2023, 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
In two separate complaints, one filed by the State of Louisiana and the Parish of CameronThe information with respect to this Item 1. Legal Proceedings is set forth in the 38th Judicial District Court for the Parish of Cameron on FebruaryNote 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 Vermillion on July 29, 2016, we were named as a defendant, among 26 oil and gas companies, in the Cameron Parish complaint and among more than 40 oil and gas companies in the Vermillion Parish complaint, or the Complaints. The Complaints were filed under the State and Local Coastal Resources Management Act of 1978, as amended, and the rules, regulations, orders and ordinances adopted thereunder, which we referred to collectively as the CZM Laws, and allege that certain of the defendants’ oil and gas exploration, production and transportation operations associated with the development of the East Hackberry and West Hackberry oil and gas fields, in the case of the Cameron Parish complaint, and the Tigre Lagoon and Lac Blanc oil and gas fields, in the case of the Vermillion Parish complaint, were conducted in violation of the CZM Laws. The Complaints allege that such activities caused substantial damage to land and waterbodies located in the coastal zone of the relevant Parish, including due to defendants’ design, construction and use of waste pits and the alleged failure to properly close the waste pits and to clear, re-vegetate, detoxify and return the property affected to its original condition, as well as the defendants’ alleged discharge of waste into the coastal zone. The Complaints also allege that the defendants’ oil and gas activities have resulted in the dredging of numerous canals, which had a direct and significant impact on the state coastal waters within the relevant Parish and that the defendants, among other things, failed to design, construct and maintain these canals using the best practical techniques to prevent bank slumping, erosion and saltwater intrusion and to minimize the potential for inland movement of storm-generated surges, which activities allegedly have resulted in the erosion of marshes and the degradation of terrestrial and aquatic life therein. The Complaints also allege that the defendants failed to re-vegetate, refill, clean, detoxify and otherwise restore these canals to their original condition. In these two petitions, the plaintiffs seek damages and other appropriate relief under the CZM Laws, including the payment of costs necessary to clear, re-vegetate, detoxify and otherwise restore the affected coastal zone of the relevant Parish to its original condition, actual restoration of such coastal zone to its original condition, and the payment of reasonable attorney fees and legal expenses and pre-judgment and post judgment interest.
We were served with the Cameron complaint in early May 2016 and with the Vermillion complaint in early September 2016.  The Louisiana Attorney General and the Louisiana Department of Natural Resources intervened in both the Cameron Parish suit and the Vermillion Parish suit.  Shortly after the Complaints were filed, certain defendants removed the cases to the lawsuit to the United States District Court for the Western District of Louisiana.  In both cases, the plaintiffs filed a motion to remand, and the plaintiffs agreed to an extension of time for all defendants to file responsive pleadings until the District Courts ruled on the motions to remand.  In the Vermilion Parish case, the District Court entered an order on September 26, 2017 remanding the lawsuit to the 15th Judicial District Court, State of Louisiana, Parish of Vermilion.  Pursuant to an agreement with plaintiffs’ counsel, all defendants have an extension of time through November 27, 2017 to file responsive pleadings to plaintiffs’ petitions in the Vermilion Parish lawsuit.  In the Cameron Parish lawsuit, the District Court has not ruled on plaintiffs’ motion to remand.  Briefing on the motion to remand has been completed; however, no hearing has been set for the motion to remand, and the District Court has not given the parties any indication regarding when a ruling should be expected. Due the procedural posture of lawsuits, the fact that responsive pleadings have not been filed and the fact that the parties have not begun discovery, we have not had the opportunity to evaluate the applicability of the allegations made in plaintiffs' complaints to our operations and management cannot determine the amount of loss, if any, that may result.
In addition, due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment related disputes. In the opinion of our management, none of the pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on ourconsolidated financial condition, cash flows or results of operations.statements.
ITEM 1A.RISK FACTORS
See risk factors previously disclosedOur business has many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our common stock or senior notes are described below and under "Risk Factors" in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2016.2022.
ITEM 2.UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Unregistered Sales of Equity Securities
None.

Issuer Repurchases of Equity Securities
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Our common stock repurchase activity for the three months ended June 30, 2023 was as follows:
Period
Total Number of Shares Purchased(1)
Average Price Paid per Share
Total number of shares purchased as part of publicly announced plans or programs(2)
Approximate maximum dollar value of shares that may yet be purchased under the plans or programs(2)
April 1 - April 3062,209 $81.26 60,423 $111,445,000 
May 1 - May 3189,709 $95.01 75,088 $104,272,000 
June 1 - June 30306,001 $95.66 306,001 $75,000,000 
Total457,919 $93.58 441,512 
_____________________
Table(1)    We repurchased and canceled 1,786 and 14,621 shares of Contentsour common stock at a weighted average price of $80.00 and $92.33 to satisfy tax withholding requirements incurred upon the vesting of restricted stock unit awards during April and May 2023, respectively.

(2)    In February 2023 our Board of Directors approved an increase to the authorized stock repurchase program from $300 million to $400 million. The stock repurchase program extends through March 31, 2024. At June 30, 2023, there was approximately $75 million that may yet be repurchased under the $400.0 million approved amount.

ITEM 3.DEFAULTS UPON SENIOR SECURITIES
Not applicable.None.
ITEM 4.MINE SAFETY DISCLOSURES
Not applicable.
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ITEM 5.OTHER INFORMATION
None.Trading Arrangements
During the three months ended June 30, 2023, none of our officers or directors adopted or terminated any contract, instruction or written plan for the purchase or sale of our securities that was intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) or any "non-Rule 10b5-1 trading arrangement".
Guillermo (Bill) Martinez Resignation
On July 31, 2023, Guillermo (Bill) Martinez resigned as a member of the Board of Directors (the “Board) of the Company, effective as of July 31, 2023 (the “Effective Date”). Mr. Martinez was a member of the Board’s Audit Committee and the chair of the Board’s Nominating, Environmental, Social & Governance Committee. Mr. Martinez’s resignation was not the result of any disagreement with the Company.
On the Effective Date, the Board appointed Jeannie Powers, age 38, to serve as a member of the Board until the Company’s 2024 Annual Meeting. Ms. Powers will serve on the Board’s Audit Committee and Nominating, Environmental, Social and Governance Committee.
Ms. Powers is a Managing Director and Co-Head of Domestic Upstream at EIG Global Energy Partners, where she also serves on the ESG Committee. In her previous role at EIG, she led the North America Engineering Team which focused on all technical aspects of EIG’s North American portfolio and new business opportunities. Before joining EIG in 2017, Ms. Powers worked in a senior technical role at Wells Fargo Securities A&D where she spent three years evaluating and marketing upstream and midstream assets. Prior to Wells, Ms. Powers spent seven years at Chevron, working both asset development and operations across the Lower 48. Ms. Powers holds a degree in Petroleum Engineering from the University of Texas and a Master of Business Administration degree from Texas Tech University.
Ms. Powers is entitled to participate in the Company’s non-employee director compensation program, as described under “2022 Director Compensation” in the Company’s proxy statement filed with the Securities and Exchange Commission on April 10, 2023.
There are no family relationships between Ms. Powers and any director or executive officer of the Company that are required to be disclosed pursuant to Item 401(d) of Regulation S-K, there are no undertakings between Ms. Powers and any other person pursuant to which she was selected to serve as a Director of the Company, and there are no transactions between the Company and Ms. Powers that would require disclosure under Item 404(a) of Regulation S-K.
Chief Accounting Officer
Effective, August 2, 2023, Matthew B. Willrath was promoted to Vice President and Chief Accounting Officer. Prior to the promotion, Mr. Willrath served as our Vice President and Controller and has been with Gulfport Energy since February 2020.
Mr. Willrath has over 20 years experience in the oil and gas industry. Prior to joining Gulfport, Mr. Willrath held accounting positions of increasing responsibility during his 16-year tenure at Devon Energy Corporation, including Director of Financial Accounting and Reporting.
Mr. Willrath is a Certified Public Accountant and holds a Bachelor of Science in Accounting and Master of Science in Accounting from Oklahoma State University.
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ITEM 6.EXHIBITS
Exhibit
Number
ITEM 6.		Description
3.1
Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006).
3.2
Certificate of Amendment No. 1 to Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.2 to Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 6, 2009).
3.3
Certificate of Amendment No. 2 to Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 23, 2013).
3.4
Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 12, 2006).
3.5
First Amendment to the Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 23, 2013).
3.6
Second Amendment to the Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company on May 2, 2014).
4.1
Form of Common Stock certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the Company with the SEC on July 22, 2004).
4.5
Indenture, dated as of April 21, 2015, among the Company, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of the Company’s 6.625% Senior Notes due 2023) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 21, 2015).
4.6
Indenture, dated as of October 14, 2016, among Gulfport Energy Corporation, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of Gulfport Energy Corporation’s 6.000% Senior Notes due 2024) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File. No. 000-19514, filed by the Company with the SEC on October 19, 2016).
4.7
Indenture, dated as of December 21, 2016, among Gulfport Energy Corporation, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of Gulfport Energy Corporation’s 6.375% Senior Notes due 2025) (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 21, 2016).
4.8
Indenture, dated as of October 11, 2017, among Gulfport Energy Corporation, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of Gulfport Energy Corporation’s 6.375% Senior Notes due 2026) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 11, 2017).
4.9
Registration Rights Agreement, dated as of October 11, 2017, among Gulfport Energy Corporation, the subsidiary guarantors party and J.P. Morgan Securities LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 4.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 11, 2017).
EXHIBITS

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
10.110-Q001-1951410.35/3/2023
10.2X
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
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4.10104
Registration Rights Agreement, dated as of February 17, 2017, by and between Gulfport Energy Corporation and Vitruvian II Woodford, LLC (incorporated by reference to Exhibit 4.1 toCover Page Interactive Data File - the Current Report on Form 8-K,cover page interactive data file does not appear in the Interactive Data File No. 000-19514, filed bybecause its XBRL tags are embedded within the Company with the SEC on February 24, 2017).
Inline XBRL document.
10.1
Tenth Amendment to Amended and Restated Credit Agreement, dated as of October 4, 2017, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 5, 2017).
31.1*
Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
31.2*
Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
32.1*
Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
32.2*
Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
101.INS*XBRL Instance Document.
101.SCH*XBRL Taxonomy Extension Schema Document.
101.CAL*XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE*XBRL Taxonomy Extension Presentation Linkbase Document.X
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*Filed herewith.


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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: NovemberAugust 2, 20172023
 
GULFPORT ENERGY CORPORATION
By:/s/    Keri CrowellMichael Hodges
Keri Crowell
Michael Hodges
Chief Financial Officer



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