GULFPORT ENERGY CORP (GPOR)

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis represents management’s perspective of our business, financial condition and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future and should be read in conjunction with “Item 8. Financial Statements and Supplementary Data” of this report. The following information updates the discussion of Gulfport's financial condition provided in its 2023 Annual Report on Form 10-K filing and compares the results of operations for the year ended December 31, 2024 to the year ended December 31, 2023. Discussions of our results from 2022 to 2023 that are not included in this Form 10-K can be found in “Management's Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2023.

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Overview

Gulfport is an independent natural gas-weighted exploration and production company with assets primarily located in the Appalachia and Anadarko basins. Our principal properties are located in eastern Ohio targeting the Utica and Marcellus and in central Oklahoma targeting the SCOOP Woodford and Springer formations. Our strategy is to develop our assets in 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 generally 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

Long-Term Debt and Credit Facility

In September 2024, Gulfport Operating purchased approximately 95%, or $524.3 million of the 2026 Senior Notes in a tender offer using the net proceeds received from the issuance of $650 million of its 2029 Senior Notes. The net impact of these transactions resulted in the Company extending the maturity of substantially all of the senior notes from 2026 to 2029.

Additionally, on September 12, 2024, the Company entered into the Commitment Increase, Borrowing Base Reaffirmation Agreement, and Fourth Amendment to Credit Agreement (the “Fourth Amendment”), which amended the Company’s Third Amended and Restated Credit Agreement. The Fourth Amendment, among other things, (a) increased the aggregate elected commitment amounts under the Credit Facility to $1.0 billion, (b) reaffirmed the borrowing base under the Credit Facility at $1.1 billion, (c) extended the maturity date under the Credit Facility to September 12, 2028, and (d) reduced the pricing grid 50 bps.

Stock Repurchase Program

On November 4, 2024, the Company's Board of Directors approved an increase to the authorized Repurchase Program from $650.0 million to $1.0 billion and extended the authorization through December 31, 2025. During the year ended December 31, 2024, the Company repurchased 1.2 million shares for $184.5 million at a weighted average price of $153.35 per share. As of December 31, 2024, the Company repurchased 5.6 million shares for $584.1 million at a weighted average price of $104.88 per share since the inception of the Repurchase Program.

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2024 Operational and Financial Highlights

During 2024, we had the following notable achievements:

•Reported total net production of 1,054 MMcfe per day.

•Generated $650.0 million of operating cash flows.

•Turned to sales 19 gross operated (17.8 net) wells.

•Expanded common share repurchase program to $1.0 billion and returned $184.5 million to shareholders through the repurchase of 1.2 million shares at a weighted average price of $153.35 per share.

•Extended the maturity of substantially all long-term senior notes from 2026 to 2029.

•Extended the maturity of the Credit Facility to 2028 and increased the available commitments under the Credit Facility by $100 million.

•Exited the year with total liquidity of $899.7 million.

•Achieved MIQ certification for all Appalachian assets for the second consecutive year.

•Reported year-end estimated net proved reserves of 4.0 Tcfe.

Business and Industry Outlook

The Company's primary focus going into 2025 is its continued attention on reducing cycle times and operating costs to improve margins and ultimately support our expected free cash flow generation. We are committed to an emphasis on sustainability and we will continue to prioritize safety, environmental stewardship, and maintaining strong relationships with the communities in which we operate. Throughout the year, we plan to maintain capital discipline, prioritizing free cash flow generation and preserving our strong financial position, while returning capital to shareholders and increasing our resource depth through incremental leasehold opportunities.

In 2024, natural gas prices continued to be volatile as spot prices ranged from $1.21 to $13.20 per MMBtu. Henry Hub averaged $2.19 per MMBtu in 2024 vs $2.53 per MMBtu in 2023. As we look into 2025, we expect continued volatility in natural gas prices. To mitigate our exposure to commodity market volatility and to help provide a level of certainty around our financial strength, we have entered into a combination of natural gas swaps and collars, representing approximately 46% of our expected 2025 production, at an average floor price of $3.59 per Mcf.

Our 2025 capital expenditure program is expected to be in a range of $370 million to $395 million.

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Results of Operations

Comparison of the Year Ended December 31, 2024 and 2023

We reported net loss of $261.4 million for the year ended December 31, 2024, compared to a net income of $1.5 billion for the year ended December 31, 2023. The material changes that led to the decrease in net loss are further discussed by category on the following pages. Some totals and changes throughout the below section may not sum or recalculate due to rounding.

Natural Gas, Oil and Condensate and NGL Production and Pricing (sales totals in thousands)

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The decrease in natural gas sales without the impact of derivatives when comparing the year ended December 31, 2024, to the year ended December 31, 2023, was primarily due to a 15% decrease in realized natural gas prices, partially offset by a 1% increase in sales volumes. The realized price change was primarily driven by the decrease in the average Henry Hub gas index from $2.74 per Mcf in the year ended December 31, 2023, to $2.27 per Mcf during the year ended December 31, 2024. The 1% increase in natural gas production was primarily due to our 2023 and 2024 development programs in the Utica/Marcellus partially offset by natural declines and limited activity in the SCOOP.

The increase in oil and condensate sales without the impact of derivatives when comparing the year ended December 31, 2024, to the year ended December 31, 2023, was due to a 7% increase in sales volumes, partially offset by a 5% decrease in realized oil prices. The 7% increase in oil and condensate production was primarily due to commencement of sales on new wells targeting the Utica liquids window. The realized price change was primarily driven by the decrease in the average WTI crude index from $77.62 per barrel in the year ended December 31, 2023, to $75.72 per barrel during the year ended December 31, 2024.

The decrease in NGL sales without the impact of derivatives when comparing the year ended December 31, 2024, to the year ended December 31, 2023, was due to a 13% decrease in NGL sales volumes, partially offset by an 8% increase in realized prices. The 13% decrease in NGL production was primarily due to natural declines and limited 2023 development in the SCOOP. The realized price change was primarily driven by the increase in the average Mont Belvieu NGL index from $30.07 per barrel in the year ended December 31, 2023, to $32.73 per barrel during the year ended December 31, 2024.

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Natural Gas, Oil and NGL Derivatives (in thousands)

The total natural gas, oil and NGL volumes hedged for the year ended December 31, 2024 and 2023, represented approximately 80% and 95%, respectively, of our total sales volumes for the applicable year.

We recognize fair value changes on our natural gas, oil and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationship between contract prices and the associated forward curves. The significant change in the total gain for the year ended December 31, 2024 compared to the year ended December 31, 2023, was primarily the result of changes in futures pricing for oil, natural gas, and NGLs during each period. The fair value losses of our hedging program totaled $253.1 million for the year ended December 31, 2024 compared to gains of $588.1 million for the year ended December 31, 2023. Settlement gains (losses) in the table above represent realized cash gains or losses to the instruments described in Note 12 of our consolidated financial statements. Our hedging program generated cash receipts of $282.6 million for the year ended December 31, 2024, compared to cash receipts of $152.2 million for the year ended December 31, 2023.

Lease Operating Expenses (in thousands, except per unit)

The increase in total LOE for the year ended December 31, 2024, compared to the year ended December 31, 2023, was primarily the result of increased production in Utica/Marcellus as described above.

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Taxes Other Than Income (in thousands, except per unit)

The decrease in total and per unit taxes other than income for the year ended December 31, 2024, compared to the year ended December 31, 2023, was primarily related to a 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)

Transportation, gathering, processing and compression for the year ended December 31, 2024, compared to the year ended December 31, 2023, increased in total primarily as a result of our small increase in production.

Depreciation, Depletion and Amortization (in thousands, except per unit)

Depreciation, depletion and amortization of our oil and gas properties for the year ended December 31, 2024, compared to the year ended December 31, 2023, increased 2% primarily the result of our drilling and development activities during 2023 and 2024.

Impairment of Oil and Natural Gas Properties

At September 30, 2024, the net book value of our oil and gas properties exceeded the calculated ceiling. As a result, we recorded a non-cash ceiling test impairment of $30.5 million in the third quarter of 2024. The impairment resulted from declines in the full cost ceiling, which primarily resulted from the significant decrease in the 12-month average trailing price for natural gas. The 12-month average trailing price for natural gas in the third quarter of 2024 was $2.21 per MMBtu.

At December 31, 2024, the net book value of our oil and gas properties exceeded the calculated ceiling. As a result, we recorded a non-cash ceiling test impairment of $342.7 million in the fourth quarter of 2024. The impairment resulted from declines in the full cost ceiling, which primarily resulted from the significant decrease in the 12-month average trailing price for natural gas. The 12-month average trailing price for natural gas in the fourth quarter of 2024 was $2.13 per MMBtu.

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Lower natural gas, oil and NGL prices can reduce the value of our assets. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine the actual ceiling test calculation and impairment analysis in future periods. Given the decline of natural gas prices through December 2024, we may have additional ceiling test impairments of our oil and natural gas properties in subsequent quarters if the 12-month average trailing price does not improve from the $2.13 per MMBtu utilized in the fourth quarter 2024 ceiling test. Any such ceiling test impairment could be material to our net earnings; however, given the inter-relationship of the various judgements made to estimate proved reserves, it is impractical to estimate the potential changes in these estimates and their impact on the impairment.

We did not record an impairment during any quarter in 2023.

General and Administrative Expenses (in thousands, except per unit)

The increase in total and per unit general and administrative expenses for the year ended December 31, 2024, compared to the year ended December 31, 2023, was primarily driven by increases in employee compensation and headcount.

Restructuring Costs

During the year ended December 31, 2023, Gulfport recognized $4.8 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, $1.3 million resulted from accelerated vesting of share-based grants, which are non-cash charges. The organizational changes were completed in the second quarter of 2023 and there are no remaining employee termination liabilities associated with these changes.

Interest Expense (in thousands, except per unit)

Due to the tender offer for the 2026 Senior Notes in the third quarter of 2024 described below, interest paid on the 2026 Senior Notes decreased 29% for the year ended December 31, 2024, compared to the year ended December 31, 2023. The Company also paid $13.2 million of interest on the 2029 Senior Notes for the year ended December 31, 2024. Interest expense on our Credit Facility increased 2% for the year ended December 31, 2024, compared to the year ended December 31, 2023, as a result of a higher average balance outstanding. Amortization of loan costs increased 29% for the year ended December 31, 2024, compared to the year ended December 31, 2023, as a result of the Third Amendment to the Credit Facility which increased the elected commitments and borrowing base and the Fourth Amendment to the Credit Facility which increased the elected commitments. The Company also capitalized $4.8 million and $4.1 million in interest expense for the years ended December 31, 2024 and 2023, respectively.

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Loss on Debt Extinguishment

In September 2024, Gulfport Operating purchased and retired $524.3 million of the 2026 Senior Notes in a tender offer using net proceeds from the 2029 Senior Notes offering. The 2026 Senior Notes were tendered at an average price equal to 102.3% of the principal amount. The retirement of the 2026 Senior Notes resulted in a loss on debt extinguishment of $13.4 million, which included cash costs of $12.9 million.

Other, net (in thousands)

Other, net in the Company's consolidated statements of operations for the year ended December 31, 2024, included approximately $4.9 million related to changes in the Company's legal reserves for certain litigation and regulatory proceedings. Additionally, Other, net included approximately $1.9 million write-down of certain of its pipe inventory that the Company does not expect to utilize in its drilling and completion activities.

As part of its Chapter 11 Cases and restructuring efforts, the Company filed motions to reject certain firm transportation agreements between the Company and affiliates of TC Energy Corporation (“TC”) and Rover Pipeline LLC (“Rover”). 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. As part of the settlement, Gulfport paid a $1.0 million administrative claim, which is included in Other, net. On February 24, 2023, Gulfport received an additional $17.8 million interim distribution for its TC claim, which is also included in Other, net. Other, net in the second quarter of 2023 included a $5.0 million recoupment of previously placed collateral for certain firm transportation commitments during the Company's Chapter 11 Cases. Additionally, in the fourth quarter of 2023, Gulfport received an additional $8.3 million distribution related to its TC claim.

Income Taxes (in thousands)

For the year ended December 31, 2024, we had an effective tax rate of 18% and an income tax benefit of $56.1 million. For the year ended December 31, 2023, the Company's effective tax rate was (56)% and an income tax benefit of $525.2 million. The higher effective tax rate for the year ended December 31, 2024 is primarily related to the valuation allowance the Company released during the third quarter of 2023. See Note 10 of our consolidated financial statements for further discussion of our income tax benefit.

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 year ended December 31, 2024, our primary sources of capital resources and liquidity have consisted of internally generated cash flows from operations and access to the debt markets, and our primary uses of cash have been for development of our oil and natural gas properties, share repurchases, dividend payments on our preferred stock and discretionary acreage acquisitions.

We believe our annual free cash flow generation, borrowing capacity under the Credit Facility and cash on hand will provide sufficient liquidity to fund our operations, capital expenditures, interest expense and share repurchases during the next 12 months and the foreseeable future.

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To the extent actual operating results, realized commodity prices or uses of cash differ from our assumptions, our liquidity could be adversely affected. See Note 4 of our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our senior notes.

As of December 31, 2024, we had $1.5 million of cash and cash equivalents compared to $1.9 million as of December 31, 2023, and a net working capital deficit of $114.2 million as of December 31, 2024, compared to net working capital of $52.4 million as of December 31, 2023. As of December 31, 2024, our net working capital deficit includes no debt due in the next 12 months. Our total principal amount of funded debt as of December 31, 2024, was $713.7 million compared to $668.0 million as of December 31, 2023. See Note 4 of our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our notes.

As of February 20, 2025, we had $3.1 million of cash and cash equivalents, $10.0 million borrowings under our Credit Facility, $63.9 million of letters of credit outstanding, $25.7 million of outstanding 2026 Senior Notes and $650.0 million of outstanding 2029 Senior Notes.

Debt. In May 2021, we issued 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. In September 2024, Gulfport Operating purchased approximately 95%, or $524.3 million, of the 2026 Senior Notes in a tender offer using net proceeds received from the private placement of the 2029 Senior Notes. This resulted in extending the maturity of substantially all of our senior notes from 2026 to 2029.

Additionally, 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 Credit Facility. The Third Amendment, among other things, (a) increased the aggregate elected commitment amounts under the Credit Facility to $900 million, (b) increased the borrowing base under the Credit Facility to $1.1 billion, (c) increased the excess cash threshold under the Credit Facility 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 been refinanced, redeemed or repaid in full on or prior to such 91st day. On April 18, 2024, Gulfport completed its semi-annual borrowing base redetermination under its Credit Facility during which the borrowing base was reaffirmed at $1.1 billion with elected commitments remaining at $900 million.

On September 12, 2024, the Company entered into the Commitment Increase, Borrowing Base Reaffirmation Agreement, and Fourth Amendment to Credit Agreement (the “Fourth Amendment”), which amended the Company’s Third Amended and Restated Credit Agreement. The Fourth Amendment, among other things, (a) increased the aggregate elected commitment amounts under the Credit Facility to $1.0 billion, (b) reaffirmed the borrowing base under the Credit Facility at $1.1 billion, (c) extended the maturity date under the Credit Facility to September 12, 2028, and (d) reduced the pricing grid 50 bps.

We may continue to use a combination of cash, borrowings and issuances of our common stock or other securities to retire our outstanding debt and preferred stock through privately negotiated transactions, open market repurchases, redemptions, tender offers or otherwise, but we are under no obligation to do so.

See Note 4 of our consolidated financial statements for additional discussion of our outstanding debt.

Dividends on Preferred Stock. As discussed in Note 5 of our consolidated financial statements, holders of preferred stock are entitled to receive cumulative quarterly dividends at a rate of 10% per annum of the Liquidation Preference with respect to cash dividends and 15% per annum of the Liquidation Preference with respect to dividends paid in kind as additional shares of preferred stock (“PIK Dividends”). We currently have the option to pay either cash dividends or PIK Dividends on a quarterly basis.

During the years ended December 31, 2024 and 2023, the Company paid $4.2 million and $4.8 million, respectively, of cash dividends to holders of our preferred stock.

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Supplemental Guarantor Financial Information. The 2026 Senior Notes are guaranteed on a senior unsecured basis by all existing consolidated subsidiaries that guarantee our Credit Facility or certain other debt (the “2026 Senior Notes Guarantors”). The 2026 Senior Notes are not guaranteed by Grizzly Holdings or Mule Sky, LLC. The 2026 Senior Notes Guarantors are 100% owned by the Parent, and the guarantees are full, unconditional, joint and several. There are no significant restrictions on the ability of the Parent or the 2026 Senior Notes 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 2026 Senior Notes and the guarantees are effectively subordinated to all of our and the subsidiary guarantors' secured indebtedness (including all borrowings and other obligations under our amended and restated credit agreement) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated to all indebtedness and other liabilities of any of our subsidiaries that do not guarantee the 2026 Senior Notes.

The 2029 Senior Notes are guaranteed on a senior unsecured basis by Gulfport and certain of Gulfport’s wholly owned subsidiaries (collectively, the “2029 Senior Notes Guarantors” and, together with the 2026 Senior Notes Guarantors, the “Guarantors”) and certain future subsidiaries of Gulfport that become borrowers or guarantors under any credit agreement with an aggregate principal amount outstanding or commitment amount in excess of $15 million. The 2029 Senior Notes Guarantors are 100% owned by the Parent, and the guarantees are full, unconditional, joint and several. There are no significant restrictions on the ability of the Parent or the 2029 Senior Notes Guarantors to obtain funds from each other in the form of a dividend or loan. The guarantees rank (i) senior in right of payment to any future subordinated indebtedness of Gulfport Operating or the 2029 Senior Notes Guarantors, (ii) pari passu in right of payment with all existing and future unsecured senior indebtedness of Gulfport Operating or the 2029 Senior Notes Guarantors, (iii) effectively junior to any secured indebtedness of Gulfport Operating or the 2029 Senior Notes Guarantors, including indebtedness under the credit agreement, to the extent of the value of the collateral securing such indebtedness, and (iv) structurally subordinated in right of payment to all indebtedness and other liabilities of Gulfport Operating’s subsidiaries that are not 2029 Senior Notes Guarantors.

SEC Regulation S-X Rule 13-01 requires the presentation of “Summarized Financial Information” to replace the “Condensed Consolidating Financial Information” required under Rule 3-10. Rule 13-01 allows the omission of Summarized Financial Information if assets, liabilities and results of operations of the Guarantors are not materially different than the corresponding amounts presented in our consolidated financial statements. The Parent and Guarantor subsidiaries comprise our material operations. Therefore, we concluded that the presentation of the Summarized Financial Information is not required as our Summarized Financial Information of the Guarantors is not materially different from our consolidated financial statements.

Derivatives and Hedging Activities. Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. Our natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to predict with greater certainty the total revenue we will receive. See Item 7A. “Quantitative and Qualitative Disclosures About Market Risk” for further discussion on the impact of commodity price risk on our financial position. Additionally, see Note 12 of our consolidated financial statements for further discussion of derivatives and hedging activities.

Subsequent to December 31, 2024 and as of February 20, 2025, we entered into the following natural gas, oil, and NGL derivative contracts:

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Contractual and Commercial Obligations. The following table sets forth our contractual and commercial obligations at December 31, 2024 (in thousands):

_____________________

(1)    The maturities of our debt obligations and associated interest reflect their original expiration dates and do not reflect any acceleration due to any events of default pertaining to these obligations. See Note 4 of our consolidated financial statements for a description of our long-term debt.

(2)    See Note 17 of our consolidated financial statements for further discussion of our firm transportation and gathering commitments.

(3)    See Note 17 of our consolidated financial statements for a description of our other operational commitments.

(4)    See Note 9 of our consolidated financial statements for a description of our operating lease liabilities.

(5)    This table does not include derivative liabilities or the estimated discounted cost for future abandonment of oil and natural gas properties. See Notes 12 and 3 of our consolidated financial statements, respectively.

Off-balance Sheet Arrangements. We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2024, our material off-balance sheet arrangements and transactions include $63.8 million in letters of credit outstanding against our Credit Facility and $44.9 million in surety bonds issued. Both the letters of credit and surety bonds are being used as financial assurance, primarily for certain firm transportation agreements. Additionally, the Company entered into various contractual commitments to purchase inventory and other material to be used in future activities. The Company's commitment to purchase these materials exists through 2025, with approximately $13.8 million remaining. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources. See Note 17 of our consolidated financial statements for further discussion of the various financial guarantees we have issued.

Capital Expenditures. Our capital expenditures have historically been related to the execution of our drilling and completion activities in addition to certain lease acquisition activities. Our capital investment strategy is focused on prudently developing our existing properties to generate sustainable cash flow considering current and forecasted commodity prices. For the year ended December 31, 2024, the Company's incurred capital expenditures totaled $430.1 million, of which $327.4 million related to drilling and completion activities, $57.9 million related to maintenance leasehold and land investment and $44.8 million related to discretionary acreage acquisitions.

Our drilling and completion capital expenditures for 2025 are currently estimated to be in the range of $335 million to $355 million. Also, we currently expect to spend approximately $35 million to $40 million in 2025 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 2025, 2026 and 2027. We expect this capital program to result in approximately 1,040 to 1,065 MMcfe per day of production in 2025.

Commodity Price Risk. The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty. During 2024, WTI prices ranged from $66.73 to $87.69 per barrel and the Henry Hub spot market price of natural gas ranged from $1.21 to $13.20 per MMBtu. During 2023, WTI prices ranged from $66.61 to $93.67 per barrel and the Henry Hub spot market price of natural gas ranged from $1.74 to $3.78 per MMBtu. If the prices of oil and natural gas decline further, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected. In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to write-down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Reductions in commodity prices and/or our reserves could also negatively impact the borrowing base under our revolving credit facility, which could limit our liquidity and ability to fund development activities.

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See Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” for further information regarding our open derivative instruments at December 31, 2024.

Sources and Uses of Cash

The following table presents the major changes in cash and cash equivalents for the year ended December 31, 2024 and 2023 (in thousands):

Net cash provided by operating activities. Net cash provided by operating activities was $650.0 million for the year ended December 31, 2024, compared to $723.2 million for the year ended December 31, 2023. The decrease was primarily the result of a decrease in our natural gas revenues.

Additions to oil and natural gas properties. During the year ended December 31, 2024, we spud 20 gross (19.7 net) operated wells and commenced sales from 16 gross (15.4 net) operated wells targeting the Utica formation for a total cost incurred of approximately $259.8 million. During the year ended December 31, 2024, we spud 2 gross (1.8 net) operated wells and commenced sales from 3 gross (2.4 net) operated wells in the SCOOP for a total incurred cost of approximately $63.8 million. Additionally, the Company incurred $57.9 million related to maintenance leasehold and land investment and $44.8 million related to discretionary acreage acquisitions.

Drilling and completion 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 and cash capital expenditures may vary from period to period due to the cash payment cycle. Cash capital expenditures for the year ended December 31, 2024 and 2023, were as follows (in thousands):

Debt activity, net. During the year ended December 31, 2024, the Company had $956.0 million and $1.0 billion in borrowings and repayments, respectively, on its Credit Facility. In September 2024, the Company purchased $524.3 million of the 2026 Senior Notes in a tender offer. The retirement of the 2026 Senior Notes resulted in a loss on debt extinguishment of $13.4 million, which included cash costs of $12.9 million. The Company also issued $650.0 million aggregate principal amount of its 6.750% senior notes due 2029. As of February 20, 2025, the Company had $10.0 million in borrowings outstanding on its Credit Facility.

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Debt issuance and loan commitment fees. During the year ended December 31, 2024, the Company incurred debt issuance and loan commitment fees of $14.9 million, as compared to $7.1 million during the year ended December 31, 2023. The increase was primarily related to the issuance of the 2029 Senior Notes and the Fourth Amendment to the Credit Facility. See Note 4 of our consolidated financial statements for further discussion of the long-term debt activity.

Repurchases of common stock. During the year ended December 31, 2024, the Company repurchased 1.2 million shares for approximately $184.5 million under the Repurchase Program at a weighted average price of $153.35 per share. For the same period in 2023, the Company repurchased 1.5 million shares for $148.9 million at a weighted average price of $101.53 per share. As of February 20, 2025, we repurchased 5.6 million shares for approximately $593.2 million under the Repurchase Program at a weighted average price of $105.57 per share.

Dividends on preferred stock. During the year ended December 31, 2024, the Company paid $4.2 million of cash dividends to holders of our preferred stock compared to $4.8 million in the year ended December 31, 2023.

Shares exchanged for tax withholdings. During the year ended December 31, 2024, the Company paid $23.6 million of shares exchanged for tax withholdings compared to $3.2 million in the year ended December 31, 2023. The increase in shares traded for taxes was primarily due to the vesting of certain PSU awards as discussed in Note 7 of our consolidated financial statements.

Other. During the year ended December 31, 2024, the Company incurred other expenses of $1.9 million, as compared to other income of $0.1 million paid during the year ended December 31, 2023. The change was primarily related to proceeds from sales of oil and gas properties of $2.6 million during the year ended December 31, 2023.

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States require us to make estimates and assumptions. The accounting estimates and assumptions we consider to be most significant to our financial statements are discussed below. Our management has discussed each critical accounting estimate with the Audit Committee of our Board of Directors.

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.

Under the full cost method, capitalized costs are amortized on a composite unit-of-production method based on proved oil and natural gas reserves. If we maintain the same level of production year over year, the depreciation, depletion and amortization expense may be significantly different if our estimate of remaining reserves or future development costs changes significantly.

We review the carrying value of our oil and natural gas properties under the full cost method of accounting prescribed by the SEC on a quarterly basis. This quarterly review is referred to as a ceiling test.

Two primary factors impacting this test are reserve estimates and the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, 2024. Downward revisions to estimates of oil and natural gas reserves and/or unfavorable prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes, is generally written off as an expense. During 2024, the Company recognized ceiling test impairments of $373.2 million and did not record an impairment of its oil and natural gas properties for the year ended December 31, 2023. See Oil and Natural Gas Properties in Note 1 of our consolidated financial statements for further information on the full cost method of accounting.

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Oil, Natural Gas and NGL Reserves. Estimates of oil and natural gas reserves and their values, future production rates, future development costs and commodity pricing differentials are the most significant of our estimates. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These revisions could materially affect our financial statements. The volatility of commodity prices results in increased uncertainty inherent in these estimates and assumptions. Changes in natural gas, oil or NGL prices could result in actual results differing significantly from our estimates. See Note 20 of our consolidated financial statements for further information.

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 income during the period the rate change is enacted. Deferred tax assets are recognized in the year in which realization becomes determinable. At each reporting period, the Company weighs all available positive and negative evidence to determine whether its deferred tax assets are more likely than not to be realized. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. To assess that likelihood, the Company uses estimates and judgment regarding future taxable income and considers the tax laws in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities and tax planning strategies as well as the current and forecasted business economics of the oil and gas industry. Based upon the Company’s analysis, the Company currently believes that it is more likely than not that a portion of the Company's federal and state deferred tax assets will be utilized.

Revenue Recognition. We derive almost all of our revenue from the sale of natural gas, crude oil and NGL 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 the actual amounts for product sales is recorded in the month that payment is received from the purchaser. Historically, our actual payments received have not significantly deviated from our accruals.

Derivative Instruments. We seek to reduce our exposure to unfavorable changes in natural gas, oil and NGL prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps, costless collars and various types of option contracts. All derivative instruments are 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, 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. 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.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis represents management’s perspective of our business, financial condition and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future and should be read in conjunction with “Item 8. Financial Statements and Supplementary Data” of this report. The following information updates the discussion of Gulfport's financial condition provided in its 2022 Annual Report on Form 10-K filing and compares the results of operations for the year ended December 31, 2023 to the period ended December 31, 2022. Discussions of 2021 items and comparisons between 2022, Prior Successor Period and Prior Predecessor Period that are not included in this Form 10-K can be found in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2022.

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Overview

Gulfport is an independent natural gas-weighted exploration and production company with assets primarily located in the Appalachia and Anadarko basins. Our principal properties are located in eastern Ohio targeting the Utica and Marcellus and in central Oklahoma targeting the SCOOP Woodford and Springer formations. Our strategy is to develop our assets in 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 President and 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.

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.

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 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. See Note 5 of our consolidated financial statements for additional discussion of the Credit Facility.

On October 27, 2023, Gulfport completed its semi-annual borrowing base redetermination during which the borrowing base was reaffirmed at $1.1 billion with elected commitments remaining at $900 million.

Common Stock Offering

On June 26, 2023, Gulfport completed an underwritten public offering of 1.5 million shares of its common stock by 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 the closing of the offering, Gulfport purchased 263,158 shares of its common stock at $95.00 per share. The repurchase was part of the Company's existing Repurchase Program discussed below.

On December 14, 2023, Gulfport completed an underwritten public offering of 653,464 shares of its common stock by certain stockholders at a price to the public of $128.21 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.

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Stock Repurchase Program

On September 20, 2023, the Company's Board of Directors approved an increase to the authorized common stock Repurchase Program from $400 million to $650 million, extending the Repurchase Program through December 31, 2024. During the year ended December 31, 2023, the Company repurchased 1.5 million shares for $148.9 million at a weighted average price of $101.53 per share. As of December 31, 2023, the Company repurchased 4.4 million shares for $399.6 million at a weighted average price of $91.53 per share since the inception of the Repurchase Program.

Inflation, Rising Interest Rates and Changes in Commodity Prices

During 2023, the Federal Reserve has continued to tighten monetary policy by approving a series of increases to the Federal Funds Rate to combat the current inflationary environment. 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 2023. Interest rates on our Credit Facility borrowings have increased from a weighted average of 5.19% for the year ended December 31, 2022, to 8.15% for the year ended December 31, 2023. Additional increases in interest 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 capital 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 2024 to continue to be a function of supply and demand; however, we do not expect inflation to significantly impact cash flow in 2024 as a result of commitments that were entered into during 2023.

Impact of the War in Ukraine and the Israel-Hamas War

The invasion of Ukraine by Russia and the sanctions imposed in response to the crisis have increased volatility in the global 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. Other armed conflicts, including the ongoing Israel-Hamas war, may result in further disruptions in the global economic environment. The ultimate impact of the war in Ukraine and the Israel-Hamas war will depend on future developments and the timing and extent to which normal economic and operating conditions resume.

2023 Operational and Financial Highlights

During 2023, we had the following notable achievements:

•Reported total net production of 1,054 MMcfe per day.

•Generated $723.2 million of operating cash flows.

•Turned to sales 24 gross (21.9 net) wells, which included our first two operated Marcellus wells.

•Total lease operating expenses, midstream costs and taxes other than income per Mcfe decreased 13%.

•Expanded common share repurchase program to $650 million and returned $148.9 million to shareholders through the repurchase of 1.5 million shares at a weighted average price of $101.53 per share.

•Reduced total debt by $27 million.

•Achieved MIQ certification for all Appalachian assets.

•Reported year-end estimated net proved reserves of 4.2 Tcfe.

Business and Industry Outlook

The Company's primary focus going into 2024 is its continued attention on reducing cycle times and operating costs to improve margins and ultimately support our expected free cash flow generation. We are committed to an emphasis on sustainability and we will continue to prioritize safety, environmental stewardship, and maintaining strong relationships with the communities in which we operate. Throughout the year, we plan to maintain capital discipline, prioritizing free cash flow generation and preserving our strong financial position, while returning capital to shareholders and increasing our resource depth through incremental leasehold opportunities.

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In 2023, natural gas prices continued to be volatile as spot prices ranged from $1.74 to $3.78 per MMBtu. Henry Hub averaged $2.53 per MMBtu in 2023 vs $6.44 per MMBtu in 2022. As we look into 2024, we expect continued volatility in natural gas prices. To mitigate our exposure to commodity market volatility and to help provide a level of certainty around our financial strength, we have entered into a combination of natural gas swaps and collars, representing approximately 54% of our expected 2024 production, at an average floor price of $3.70 per Mcf.

Our 2024 capital expenditure program is expected to be in a range of $380 million to $420 million. With the weakening in commodity prices, we could begin to see additional deflationary pressures during 2024 as well as less frequent supply chain constraints.

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Results of Operations

Comparison of the Year Ended December 31, 2023 and 2022

We reported net income of $1.5 billion for the year ended December 31, 2023, compared to a net income of 494.7 million for the year ended December 31, 2022. The material changes that lead to the increase in net income are further discussed by category on the following pages. Some totals and changes throughout the below section may not sum or recalculate due to rounding.

Natural Gas, Oil and Condensate and NGL Production and Pricing (sales totals in thousands)

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The decrease in natural gas sales without the impact of derivatives when comparing the year ended December 31, 2023, to the year ended December 31, 2022, was due to a 62% decrease in realized natural gas prices, partially offset by a 9% increase in sales volumes. The realized price change was primarily driven by the decrease in the average Henry Hub gas index from $6.64 per Mcf in the year ended December 31, 2022, to $2.74 per Mcf during the year ended December 31, 2023. The 9% increase in natural gas production was due to our 2022 and 2023 development programs in the Utica/Marcellus partially offset by natural declines and limited activity in the SCOOP.

The decrease in oil and condensate sales without the impact of derivatives when comparing the year ended December 31, 2023, to the year ended December 31, 2022, was due to a 20% decrease in realized oil prices and a 15% decrease in sales volumes. The realized price change was primarily driven by the decrease in the average WTI crude index from $94.23 per barrel in the year ended December 31, 2022, to $77.62 per barrel during the year ended December 31, 2023. The 15% decrease in oil and condensate production was due to natural declines and limited activity in the SCOOP.

The decrease in NGL sales without the impact of derivatives when comparing the year ended December 31, 2023, to the year ended December 31, 2022, was due to a 34% decrease in realized prices, partially offset by a 2% decrease in NGL sales volumes. The realized price change was primarily driven by the decrease in the average Mont Belvieu NGL index from $45.39 per barrel in the year ended December 31, 2022, to $30.07 per barrel during the year ended December 31, 2023. The NGL production remained consistent when comparing the year ended December 31, 2023 to the year ended December 31, 2022.

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Natural Gas, Oil and NGL Derivatives (in thousands)

The total natural gas, oil and NGL volumes hedged for the year ended December 31, 2023 and 2022, represented approximately 95% and 86%, respectively, of our total sales volumes for the applicable year.

We recognize fair value changes on our natural gas, oil and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationship between contract prices and the associated forward curves. The significant change in the total gain (loss) for the year ended December 31, 2023 compared to the year ended December 31, 2022, was primarily the result of a significant decrease in futures pricing for oil, natural gas, and NGLs. The fair value gains of our hedging program totaled $588.1 million for the year ended December 31, 2023 compared to $54.1 million for the year ended December 31, 2022. Settlement gains (losses) in the table above represent realized cash gains or losses to the instruments described in Note 13 of our consolidated financial statements. Our hedging program generated cash receipts of $152.2 million for the year ended December 31, 2023, compared to cash settlements of $1,053.8 million for the year ended December 31, 2022.

Lease Operating Expenses (in thousands, except per unit)

The increase in total LOE for the year ended December 31, 2023, compared to the year ended December 31, 2022, was primarily the result of a 7% increase in production. LOE per unit for the year ended December 31, 2023 was consistent with the year ended December 31, 2022.

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Taxes Other Than Income (in thousands, except per unit)

The decrease in total and per unit taxes other than income for the year ended December 31, 2023, compared to the year ended December 31, 2022, was primarily related to a 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)

Transportation, gathering, processing and compression for the year ended December 31, 2023, compared to the year ended December 31, 2022, decreased on a per unit basis primarily as a result of lower minimum volume commitments as a result of our 7% increase in production.

Depreciation, Depletion and Amortization (in thousands, except per unit)

The increase in total and per unit depreciation, depletion and amortization of our oil and gas properties for the year ended December 31, 2023, compared to the year ended December 31, 2022, was primarily the result of our drilling and development activities subsequent to 2022.

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General and Administrative Expenses (in thousands, except per unit)

The increase in total general and administrative expenses for the year ended December 31, 2023, compared to the year ended December 31, 2022, was primarily driven by increases in employee headcount and compensation as well as legal expenses related to the continued administration of our Chapter 11 filing and settlement of a firm transportation agreement as noted in Note 19 of our consolidated financial statements.

Restructuring Costs

During the year ended December 31, 2023, Gulfport recognized $4.8 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, $1.3 million resulted from accelerated vesting of share-based grants, which are non-cash charges. The organizational changes were completed in the second quarter of 2023 and there are no remaining employee termination liabilities associated with these changes.

Interest Expense (in thousands, except per unit)

Interest expense on our Credit Facility increased 8% for the year ended December 31, 2023, compared to the year ended December 31, 2022, as a result of increased interest rates resulting from the current inflationary environment. The Company also capitalized $4.1 million in interest expense for the year ended December 31, 2023, and did not capitalize interest expense for the year ended December 31, 2022.

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Other, net (in thousands)

Other, net in the Company's consolidated statements of operations for the year ended December 31, 2023, included $17.8 million receipt of funds related to the interim TC claim distribution and a $1 million administrative payment to Rover as part of the executed settlement that occurred in the first quarter of 2023. Additionally, in the fourth quarter of 2023, Gulfport received an additional $8.3 million distribution related to its TC claim. Gulfport does not expect to receive additional distributions from the liquidating trust for its TC claim. The distributions and settlement is more fully described in Note 19 of our consolidated financial statements. 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 year ended December 31, 2022, included $11.5 million related to the initial TC claim distribution as discussed in Note 19 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 (in thousands)

For the year ended December 31, 2023, we had an effective tax rate of (56)% and an income tax benefit of $525.2 million. The income tax benefit primarily related to the partial release of the valuation allowance maintained against our net deferred tax asset position. For the year ended December 31, 2022, the Company's effective tax rate was 0% and we did not record any income tax expense, as a result of maintaining a full valuation allowance against our net deferred tax asset. See Note 11 of our consolidated financial statements for further discussion of our income tax benefit.

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 year ended December 31, 2023, our primary sources of capital resources and liquidity have consisted of internally generated cash flows from operations, and our primary uses of cash have been for development of our oil and natural gas properties, share repurchases and discretionary acreage acquisitions.

We believe our annual free cash flow generation, borrowing capacity under the Credit Facility and cash on hand will provide sufficient liquidity to fund our operations, capital expenditures, interest expense and share repurchases during the next 12 months and the foreseeable future.

To the extent actual operating results, realized commodity prices or uses of cash differ from our assumptions, our liquidity could be adversely affected. See Note 5 of our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our senior notes.

As of December 31, 2023, we had $1.9 million of cash and cash equivalents compared to $7.3 million as of December 31, 2022, and a net working capital of $52.4 million as of December 31, 2023, compared to a net working capital deficit of $391.1 million as of December 31, 2022. As of December 31, 2023, our net working capital includes no debt due in the next 12 months. Our total principal amount of funded debt as of December 31, 2023, was $668.0 million compared to $695.0 million as of December 31, 2022. See Note 5 of our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our notes.

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As of February 26, 2024, we had $7.1 million of cash and cash equivalents, $51.0 million borrowings under our Credit Facility, $63.8 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 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.

On October 27, 2023, Gulfport completed its semi-annual borrowing base redetermination during which the borrowing base was reaffirmed at $1.1 billion with elected commitments remaining at $900 million.

Additionally, on the Emergence Date, pursuant to the terms of the Plan, we issued 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.

We may continue to use a combination of cash, borrowings and issuances of our Common Stock or other securities to retire our outstanding debt and Preferred Stock through privately negotiated transactions, open market repurchases, redemptions, tender offers or otherwise, but we are under no obligation to do so.

See Note 5 of our consolidated financial statements for additional discussion of our outstanding debt.

Preferred Stock Dividends. As discussed in Note 6 of our consolidated financial statements, holders of Preferred Stock are entitled to receive cumulative quarterly dividends at a rate of 10% per annum of the Liquidation Preference with respect to cash dividends and 15% per annum of the Liquidation Preference with respect to dividends paid in kind as additional shares of Preferred Stock (“PIK Dividends”). We currently have the option to pay either cash dividends or PIK dividends on a quarterly basis.

During the year ended December 31, 2023, and the year ended December 31, 2022, the Company paid $4.8 million and $5.4 million, respectively, of cash dividends to holders of our Preferred Stock.

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Supplemental Guarantor Financial Information. The 2026 Senior Notes are guaranteed on a senior unsecured basis by all existing consolidated subsidiaries that guarantee our Credit Facility or certain other debt (the “Guarantors”). The 2026 Senior Notes are not guaranteed by Grizzly Holdings or Mule Sky, LLC (the “Non-Guarantors”). The Guarantors are 100% owned by the Parent, and the guarantees are full, unconditional, joint and several. There are no significant restrictions on the ability of the Parent or the Guarantors to obtain funds from each other in the form of a dividend or loan. The guarantees rank equally in the right of payment with all of the senior indebtedness of the subsidiary guarantors and senior in the right of payment to any future subordinated indebtedness of the subsidiary guarantors. The 2026 Senior Notes and the guarantees are effectively subordinated to all of our and the subsidiary guarantors' secured indebtedness (including all borrowings and other obligations under our amended and restated credit agreement) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated to all indebtedness and other liabilities of any of our subsidiaries that do not guarantee the 2026 Senior Notes.

SEC Regulation S-X Rule 13-01 requires the presentation of "Summarized Financial Information" to replace the "Condensed Consolidating Financial Information" required under Rule 3-10. Rule 13-01 allows the omission of Summarized Financial Information if assets, liabilities and results of operations of the Guarantors are not materially different than the corresponding amounts presented in our consolidated financial statements. The Parent and Guarantor subsidiaries comprise our material operations. Therefore, we concluded that the presentation of the Summarized Financial Information is not required as our Summarized Financial Information of the Guarantors is not materially different from our consolidated financial statements.

Derivatives and Hedging Activities. Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. Our natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to predict with greater certainty the total revenue we will receive. See Item 7A Quantitative and Qualitative Disclosures About Market Risk for further discussion on the impact of commodity price risk on our financial position. Additionally, see Note 13 of our consolidated financial statements for further discussion of derivatives and hedging activities.

Subsequent to December 31, 2023 and as of February 26, 2024, we entered into the following natural gas, oil, and NGL derivative contracts:

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Contractual and Commercial Obligations. The following table sets forth our contractual and commercial obligations at December 31, 2023 (in thousands):

_____________________

(1)    The maturities of our debt obligations and associated interest reflect their original expiration dates and do not reflect any acceleration due to any events of default pertaining to these obligations. See Note 5 of our consolidated financial statements for a description of our long-term debt.

(2)    See Note 18 of our consolidated financial statements for further discussion of our firm transportation and gathering commitments.

(3)    See Note 18 of our consolidated financial statements for a description of our other operational commitments.

(4)    See Note 10 of our consolidated financial statements for a description of our operating lease liabilities.

(5)    This table does not include derivative liabilities or the estimated discounted cost for future abandonment of oil and natural gas properties. See Notes 13 and 4 of our consolidated financial statements, respectively.

Off-balance Sheet Arrangements. We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2023, our material off-balance sheet arrangements and transactions include $63.8 million in letters of credit outstanding against our Credit Facility and $43.3 million in surety bonds issued. Both the letters of credit and surety bonds are being used as financial assurance, primarily for certain firm transportation agreements. Additionally, the Company entered 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 2024, with approximately $28.9 million remaining. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources. See Note 18 of our consolidated financial statements for further discussion of the various financial guarantees we have issued.

Capital Expenditures. Our capital expenditures have historically been related to the execution of our drilling and completion activities in addition to certain lease acquisition activities. Our capital investment strategy is focused on prudently developing our existing properties to generate sustainable cash flow considering current and forecasted commodity prices. For the year ended December 31, 2023, the Company's incurred capital expenditures totaled $491.5 million, of which $388.6 million related to drilling and completion activities, $54.8 million related to maintenance leasehold and land investment and $48.0 million related to discretionary acreage acquisitions.

Our drilling and completion capital expenditures for 2024 are currently estimated to be in the range of $330 million to $360 million. Also, we currently expect to spend approximately $50 million to $60 million in 2024 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 2024 and 2025. We expect this capital program to result in approximately 1,045 to 1,080 MMcfe per day of production in 2024.

Additionally, we are pursuing accretive acreage opportunities that expand our resource depth and provide additional optionality to our near term development plans and intend to allocate approximately $40 million for discretionary acreage acquisitions.

Commodity Price Risk. The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty. During 2023, WTI prices ranged from $66.61 to $93.67 per barrel and the Henry Hub spot market price of natural gas ranged from $1.74 to $3.78 per MMBtu. During 2022, WTI prices ranged from $71.05 to $123.64 per barrel and the Henry Hub spot market price of natural gas ranged from $3.46 to $9.85 per MMBtu. If the prices of oil and natural gas decline further, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected. In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or

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development activities are curtailed, full cost accounting rules may require us to write-down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Reductions in commodity prices and/or our reserves could also negatively impact the borrowing base under our revolving credit facility, which could limit our liquidity and ability to fund development activities.

See Item 7A. "Quantitative and Qualitative Disclosures about Market Risk" for further information regarding our open derivative instruments at December 31, 2023.

Sources and Uses of Cash

The following table presents the major changes in cash and cash equivalents for the year ended December 31, 2023 and December 31, 2022 (in thousands):

Net cash provided by operating activities. Net cash provided by operating activities was $723.2 million for the year ended December 31, 2023, compared to $739.1 million for the year ended December 31, 2022. The decrease was primarily the result of a decrease in revenue due to a decline in commodity prices partially offset by an increase of cash receipts from settled derivative instruments.

Additions to oil and natural gas properties. During the year ended December 31, 2023, we spud 20 gross (17.9 net) wells and commenced sales from 22 gross (20.2 net) wells in the Utica/Marcellus for a total cost of approximately $344.4 million and we spud 5 gross (3.2 net) and commenced sales from 2 gross (1.7 net) wells in the SCOOP for a total cost of approximately $37.3 million. Additionally, the Company incurred $54.8 million related to maintenance leasehold and land investment and $48.0 million related to discretionary acreage acquisitions.

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Drilling and completion 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 and cash capital expenditures may vary from period to period due to the cash payment cycle. Cash capital expenditures for the year ended December 31, 2023 and December 31, 2022, were as follows (in thousands):

Debt activity, net. During the year ended December 31, 2023, the Company had $971.0 million and $998.0 million in borrowings and repayments, respectively, on its Credit Facility. As of February 26, 2024, the Company had $51.0 million in borrowings outstanding on its Credit Facility.

Repurchases of Common Stock. During the year ended December 31, 2023, the Company repurchased 1.5 million shares for approximately $148.9 million under the Repurchase Program at a weighted average price of $101.53 per share. For the same period in 2022, the Company repurchased 2.9 million shares for $250.8 million at a weighted average price of $86.47 per share. As of February 26, 2024, we repurchased 4.5 million shares for approximately $413.6 million under the Repurchase Program at a weighted average price of $92.41 per share.

Preferred Stock Dividends. During the year ended December 31, 2023, the Company paid $4.8 million of cash dividends to holders of our Preferred Stock compared to $5.4 million in the year ended December 31, 2022.

Other. During the year ended December 31, 2023, the Company paid other expenses of $10.1 million, as compared to other expenses of $0.6 million paid during the year ended December 31, 2022. The increase was primarily related to a $6.8 million increase in debt issuance costs as a result of the Third Amendment to the Credit Facility which increased the commitment and redetermined its borrowing base, as discussed in Note 5 of our consolidated financial statements.

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States require us to make estimates and assumptions. The accounting estimates and assumptions we consider to be most significant to our financial statements are discussed below. Our management has discussed each critical accounting estimate with the Audit Committee of our Board of Directors.

Reorganization and Fresh Start Accounting. The Company applied FASB ASC Topic 852 - Reorganizations ("ASC 852") in preparing the consolidated financial statements, which specifies the accounting and financial reporting requirements for entities reorganizing through Chapter 11 bankruptcy proceedings. These requirements included distinguishing transactions associated with the reorganization separate from activities related to the ongoing operations of the business. Accordingly, pre-petition liabilities that may be impacted by the Chapter 11 proceedings were classified as liabilities subject to compromise on the consolidated balance sheet as of December 31, 2020. Additionally, certain expenses, realized gains and losses and provisions for losses that were realized or incurred during the Chapter 11 Cases, including adjustments to the carrying value of certain indebtedness were recorded as reorganization items, net in the consolidated statements of operations for the year ended December 31, 2020 and the Predecessor Period.

Upon emergence from the Chapter 11 Cases, ASC 852 required us to allocate our reorganization value to our individual assets based on their estimated fair values, resulting in a new entity for financial reporting purposes. After the Effective Date, the accounting and reporting requirements of ASC 852 are no longer applicable and have no impact on the Successor periods. Refer to Note 2 and Note 3 of our consolidated financial statements for more information on the events of the bankruptcy proceedings as well as the accounting and reporting impacts of the reorganization.

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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.

Under the full cost method, capitalized costs are amortized on a composite unit-of-production method based on proved oil and natural gas reserves. If we maintain the same level of production year over year, the depreciation, depletion and amortization expense may be significantly different if our estimate of remaining reserves or future development costs changes significantly.

We review the carrying value of our oil and natural gas properties under the full cost method of accounting prescribed by the SEC on a quarterly basis. This quarterly review is referred to as a ceiling test.

Two primary factors impacting this test are reserve estimates and the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, 2023. Downward revisions to estimates of oil and natural gas reserves and/or unfavorable prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes, is generally written off as an expense. The Company did not record an impairment of its oil and natural gas properties for the year ended December 31, 2023 or December 31, 2022. See Oil and Natural Gas Properties in Note 1 of our consolidated financial statements for further information on the full cost method of accounting.

Oil, Natural Gas and NGL Reserves. Estimates of oil and natural gas reserves and their values, future production rates, future development costs and commodity pricing differentials are the most significant of our estimates. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These revisions could materially affect our financial statements. The volatility of commodity prices results in increased uncertainty inherent in these estimates and assumptions. Changes in natural gas, oil or NGL prices could result in actual results differing significantly from our estimates. See Note 20 of our consolidated financial statements for further information.

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 income during the period the rate change is enacted. Deferred tax assets are recognized in the year in which realization becomes determinable. At each reporting period, the Company weighs all available positive and negative evidence to determine whether its deferred tax assets are more likely than not to be realized. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. To assess that likelihood, the Company uses estimates and judgment regarding future taxable income and considers the tax laws in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities and tax planning strategies as well as the current and forecasted business economics of the oil and gas industry. Based upon the Company’s analysis, the Company currently believes that it is more likely than not that a portion of the Company's federal and state deferred tax assets will be utilized.

Revenue Recognition. We derive almost all of our revenue from the sale of natural gas, crude oil and NGL 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 the actual amounts for product sales is recorded in the month that payment is received from the purchaser. Historically, our actual payments received have not significantly deviated from our accruals.

Derivative Instruments. We seek to reduce our exposure to unfavorable changes in natural gas, oil and NGL prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps, costless collars and various types of option contracts. All derivative instruments are 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

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that considered 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.

The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. 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.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis represents management’s perspective of our business, financial condition and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future and should be read in conjunction with “Item 8. Financial Statements and Supplementary Data” of this report. The following information updates the discussion of Gulfport's financial condition provided in its 2021 Annual Report on Form 10-K filing and compares the results of operations for the year ended December 31, 2022 to the period from May 18, 2021 through December 31, 2021 ("Prior Successor Period") and the period from January 1, 2021 through May 17, 2021 ("Prior Predecessor Period"). Discussions of 2020 items and year-to-year comparisons between 2021 and 2020 that are not included in this Form 10-K can be found in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2021.

Overview

Gulfport is an independent natural gas-weighted exploration and production company with assets primarily located in the Appalachia and Anadarko basins. Our principal properties are located in eastern Ohio targeting the Utica and in central Oklahoma targeting the SCOOP Woodford and SCOOP Springer formations. Our strategy is to develop our assets in 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.

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Recent Developments

Credit Facility

On May 2, 2022, the Company entered into the Borrowing Base Redetermination Agreement and First Amendment to the Credit Agreement (the "Amendment"), which amended the Company's Existing Credit Facility (as amended, the "Credit Facility"). The Amendment, among other things, increased the borrowing base under the Credit Facility from $850 million to $1.0 billion, with the elected commitments remaining at $700 million. On October 31, 2022, the Company completed its semi-annual borrowing base redetermination, during which the borrowing base was reconfirmed at $1.0 billion, with the elected commitments remaining at $700 million. See Note 5 of our consolidated financial statements for additional discussion of the Credit Facility.

Stock 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 from $100 million to $200 million in April 2022 and then from $200 million to $300 million in July 2022. 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 under the Repurchase Program with available funds while maintaining sufficient liquidity to fund its capital development program. The Repurchase Program is authorized to extend through June 30, 2023, and may be suspended from time to time, or modified, extended or discontinued by the Board of Directors at any time. As of December 31, 2022, the Company repurchased 2.9 million shares for $250.8 million at a weighted average price of $86.47 per share.

Inflation, Rising Interest Rates and Changes in Commodity Prices

The annual rate of inflation in the United States was measured at 6.5% in December 2022 by the Consumer Price Index, representing a significant increase to the historical inflation observed in recent years. Inflation and increased commodity prices have caused drilling and completion costs to increase from the prior year. In addition, 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, including continued rate increases. The inflationary environment has impacted interest rates on our Credit Facility borrowings throughout 2022. Interest rates on our Credit Facility borrowings have increased from 3.19% at December 31, 2021, to 7.39% at December 31, 2022. Additional increases in interest 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 capital 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.

Impact of the War in Ukraine

The invasion of Ukraine by Russia and the sanctions imposed in response to the crisis have increased volatility in the global financial markets and are expected to have further global economic consequences, including disruptions of global energy markets and the amplification of inflation and supply chain constraints. The ultimate impact of the war in Ukraine will depend on future developments and the timing and extent to which normal economic and operating conditions resume.

2022 Operational and Financial Highlights

During 2022, we had the following notable achievements:

•Reported total net production of 983.4 MMcfe per day.

•Generated $739.1 million of operating cash flows.

•Turned to sales 28 gross (23.6 net) wells; including the Extreme pad in the Utica, which was brought online at a combined gross peak production rate of approximately 140 MMcfe per day.

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•Returned $250.8 million to shareholders through the repurchase of 2.9 million shares at a weighted average price of $86.47 per share.

•Increased the borrowing base under the Credit Facility from $850 million to $1.0 billion.

•Reduced total debt by $19 million.

•Reported year-end estimated net proved reserves of 4.0 Tcfe.

Business and Industry Outlook

The Company's primary focus going into 2023 is its continued attention on reducing cycle times and operating costs to improve margins and ultimately support our expected free cash flow generation. We are committed to an emphasis on sustainability and we will continue to prioritize safety, environmental stewardship, and maintaining strong relationships with the communities in which we operate. Throughout the year, we plan to maintain capital discipline, prioritizing free cash flow generation and preserving our strong financial position, while returning capital to shareholders and increasing our resource depth through incremental leasehold opportunities.

In 2022, natural gas prices improved significantly, but continue to be volatile as spot prices ranged from $3.46 to $9.85 per MMBtu. Henry Hub averaged $6.44 per MMBtu in 2022 vs $3.89 per MMBtu in 2021. As we look into 2023, we expect continued volatility in natural gas prices. To mitigate our exposure to commodity market volatility and to help provide a level of certainty around our financial strength, we have entered into a combination of natural gas swaps and collars, representing approximately 58% of our expected 2023 production, at an average floor price of $3.58 per Mcf.

Our 2023 capital expenditure program is expected to be in a range of $425 million to $475 million. Prior to 2022, general inflation was moderate; however, during 2022 our capital and operating costs were negatively impacted by the volatility in commodity prices, a significant rise in inflation and a lack of long-term contracts entering the year. With the recent weakening in commodity prices, we could begin to see deflationary pressures during 2023 as well as less frequent supply chain constraints. We will continue to monitor and manage inflationary and supply chain pressures caused by increased activities in the field and any future increases in commodity prices.

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Results of Operations

Comparison of the Year Ended December 31, 2022, Prior Successor Period and Prior Predecessor Period

We reported net income of $494.7 million for the year ended December 31, 2022, compared to a net loss of $112.8 million for the Prior Successor Period and a net income of $251.0 million for the Prior Predecessor Period. The material changes that lead to the increase in net income are further discussed by category on the following pages. Some totals and changes throughout the below section may not sum or recalculate due to rounding.

Natural Gas, Oil and Condensate and NGL Sales (sales totals in thousands)

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For the year ended December 31, 2022, our total unhedged natural gas, oil and condensate and NGL revenues increased approximately $1.2 billion, or 113%, compared to the Prior Successor Period. The increase was primarily driven by the timing of our emergence from bankruptcy. The Prior Successor Period only includes production from May 18, 2021, through December 31, 2021, compared to a full year of production in 2022. Additionally, as noted in the table above, significant increases in oil, natural gas and NGL indexes increased per unit realizations. Most notably, the Henry Hub index increased from $4.28 per MMBtu in the Prior Successor Period to $6.44 per MMBtu in 2022.

For the year ended December 31, 2022, our total unhedged natural gas, oil and condensate and NGL revenues increased approximately $1.9 billion, or 468%, compared to the Prior Predecessor Period. The increase was primarily driven by the timing of our emergence from bankruptcy. The Prior Predecessor Period only includes production from January 1, 2021, through May 17, 2021, compared to a full year of production in 2022. Additionally, there were significant increases in oil, natural gas and NGL indexes. Most notably, the Henry Hub index increased from $3.25 per MMBtu in the Prior Successor Period to $6.44 per MMBtu in 2022.

The total natural gas, oil and NGL volumes hedged for the year ended December 31, 2022, the Prior Successor Period and the Prior Predecessor Period represented approximately 86%, 88% and 86%, respectively, of our total sales volumes for the applicable year or period.

Natural Gas, Oil and NGL Derivatives (in thousands)

Settlement gains (losses) in the table above represent realized cash gains or losses to the instruments described in Note 13 of our consolidated financial statements. Our hedging program incurred cash settlements of $1,053.8 million for the year ended December 31, 2022, compared to $322.9 million for the Prior Successor Period and $3.4 million for the Prior Predecessor Period.

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Lease Operating Expenses (in thousands, except per unit)

The increase in total LOE when comparing the year ended December 31, 2022, to the Prior Successor Period, was primarily driven by the timing of our emergence from bankruptcy. The Prior Successor Period only includes production and LOE from May 18, 2021 through December 31, 2021, compared to a full year of production and LOE in 2022. The increase in LOE on a per unit basis in 2022 compared to the Prior Successor Period, was primarily due to additional water disposal costs, additional workover costs and an increase in contract labor.

The increase in total LOE when comparing the year ended December 31, 2022, to the Prior Predecessor Period, was primarily driven by the timing of our emergence from bankruptcy. The Prior Predecessor Period only includes production and LOE from January 1, 2021 through May 17, 2021, compared to a full year of production and LOE in 2022. The increase in LOE on a per unit basis in 2022 compared to the Prior Predecessor Period, was primarily due to additional water disposal costs, additional workover costs and an increase in contract labor.

Taxes Other Than Income (in thousands, except per unit)

The increase in taxes other than income when comparing the year ended December 31, 2022, to both the Prior Successor Period and Prior Predecessor Period, was primarily related to the timing of our emergence from bankruptcy. The Prior Successor Period only includes activity from May 18, 2021 through December 31, 2021, and Prior Predecessor Period only includes activity from January 1, 2021 through May 17, 2021, compared to a full year in 2022.

The increase in per unit taxes other than income when comparing the year ended December 31, 2022, to both the Prior Successor Period and Prior Predecessor Period, was primarily related to an increase in production taxes resulting from the significant increase in our natural gas, oil and condensate and NGL revenues excluding the impact of hedges discussed above.

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Transportation, Gathering, Processing and Compression (in thousands, except per unit)

The increase in transportation, gathering, processing and compression when comparing the year ended December 31, 2022, to both the Prior Successor Period and Prior Predecessor Period, was primarily related to the timing of our emergence from bankruptcy. The Prior Successor Period only includes activity from May 18, 2021 through December 31, 2021, and Prior Predecessor Period only includes activity from January 1, 2021 through May 17, 2021, compared to a full year in 2022.

The increase on a per unit basis when comparing the year ended December 31, 2022, to the Prior Successor Period, was primarily due to an increase in minimum volume commitments, combined with an increase in rates on certain gathering and transportation systems.

The decrease on a per unit basis when comparing the year ended December 31, 2022, to the Prior Predecessor Period, was primarily related to savings associated with midstream contract rejections and renegotiations through the bankruptcy process.

Depreciation, Depletion and Amortization (in thousands, except per unit)

The increase in depreciation, depletion and amortization of our oil and gas properties when comparing the year ended December 31, 2022, to both the Prior Successor Period and Prior Predecessor Period, was primarily driven by the timing of our emergence from bankruptcy. The Prior Successor Period only includes activity from May 18, 2021 through December 31, 2021, and Prior Predecessor Period only includes activity from January 1, 2021 through May 17, 2021, compared to a full year in 2022.

The increase in per unit depreciation, depletion, and amortization when comparing the year ended December 31, 2022, to the Prior Successor Period, was primarily due to due to additional drilling and development activities in 2022.

The increase in per unit depreciation, depletion, and amortization when comparing the year ended December 31, 2022, to the Prior Predecessor Period, was primarily the result of fresh start valuations on our oil and gas properties. See Note 3 of our consolidated financial statements for more information on fresh start adjustments.

Impairment of Oil and Gas Properties

As a result of the ceiling test performed at June 30, 2021, we incurred a $117.8 million impairment charge of oil and gas properties during the Prior Successor Period. Upon the application of fresh start accounting, the value of our oil and natural gas properties was determined using forward strip oil and natural gas prices as of the Emergence Date. These prices were higher than the 12-month weighted average prices used in the full cost ceiling limitation at June 30, 2021, which led to the Prior Successor Period impairment charge.

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Impairment of Other Property and Equipment

We recognized a $14.6 million impairment charge on the Company's corporate headquarters during the Prior Predecessor Period as a result in a change in expected future use.

General and Administrative Expenses (in thousands, except per unit)

The increase in total general and administrative expenses when comparing the year ended December 31, 2022, to both the Prior Successor Period and the Prior Predecessor Period, was primarily related to the timing of our emergence from bankruptcy.

The decrease in per unit general and administrative expense when comparing the year ended December 31, 2022, to both the Prior Successor Period and the Prior Predecessor Period, was primarily driven by a significant decrease in legal and professional fees associated with our restructuring. Prior to our emergence from bankruptcy, legal and professional fees associated with our Chapter 11 filing were presented as Reorganization Items, net. Subsequent to our Emergence Date, any legal and professional fees related to the administration of our Chapter 11 filing were presented as general and administrative expenses.

Restructuring and Liability Management

During the Prior Successor Period, we incurred $2.8 million in restructuring charges related to reductions in workforce as we continued to align our workforce and leadership structure to our current operating environment.

Accretion Expense

Accretion expense increased to $2.7 million for the year ended December 31, 2022, compared to $1.2 million in the Prior Successor Period. The increase is primarily related to the timing of our emergence from bankruptcy. Accretion expense increased from $1.2 million in the Prior Predecessor Period, primarily due to the timing of our emergence from bankruptcy and was partially offset by a decrease in our asset retirement obligation as a result of fresh start adjustments upon emergence from bankruptcy. See Note 3 of our consolidated financial statements for more information on fresh start adjustments.

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Interest Expense (in thousands, except per unit)

The increase in interest expense during the year ended December 31, 2022, compared to both the Prior Successor Period and the Prior Predecessor Period, was primarily related to the timing of our emergence from bankruptcy. Interest expense per unit was comparable between the year ended December 31, 2022, and the Prior Successor Period, while there was a significant increase in interest expense when comparing the year ended December 31, 2022 with the Prior Predecessor Period, primarily due to the changes in our debt structure upon emergence from bankruptcy.

Loss (Gain) on Debt Extinguishment

During the Prior Successor Period, the Company recognized a loss of $3.0 million associated with the extinguishment of capitalized commitment fees related to the Exit Credit Facility as discussed in Note 5 of our consolidated financial statements.

Loss from Equity Investments, net (in thousands)

Through our wholly owned subsidiary Grizzly Holdings, we own an approximate 24.5% interest in Grizzly, a Canadian unlimited liability company. Effective as of the Emergence Date, we evaluated our investment in Grizzly and determined that we no longer have the ability to exercise significant influence over operating and financial policies of Grizzly Holdings. As such, we discontinued the equity method of accounting for our investment in Grizzly and we will use our previous carrying value of zero as our initial basis and will subsequently measure at fair value while recording any changes in fair value in earnings.

During the year ended December 31, 2020, our share of net loss from Mammoth Energy Services, Inc. was in excess of the carrying value of our investment, which reduced our investment to zero. Our carrying value remained at zero through the Prior Predecessor Period until the use of Mammoth Shares to settle Class 4A claims at the Emergence Date. See Note 15 of our consolidated financial statements for further discussion on our equity investments.

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Reorganization Items, net

The following table summarizes the components in reorganization items, net included in our consolidated statements of operations for the year ended December 31, 2022, Prior Successor Period and Prior Predecessor Period (in thousands):

Other, net (in thousands)

The increase in other income when comparing the year ended December 31, 2022, to both the Prior Successor Period and the Prior Predecessor Period, was primarily the result of settlement payment receipts received in 2022 as discussed in Note 19 of our consolidated financial statements.

Income Taxes (in thousands)

For the year ended December 31, 2022 the Company's effective tax rate was 0%. For the Prior Predecessor Period, we had an effective tax rate of (3.3)% and an income tax benefit of $8.0 million. The tax benefit is entirely attributable to an Oklahoma refund claim associated with an examination relating to historical tax returns. The effective tax rate differs from the statutory tax rate due to the Company’s valuation allowance position and the permanent adjustments relating to the Chapter 11 Emergence. For the Prior Successor Period, we had an effective tax rate of 0.03% and tax benefit of $39 thousand. The tax expense is entirely attributable to the Oklahoma refund claim that was filed during the third quarter, resulting in an adjustment to the benefit recorded during the Prior Predecessor Period. We did not record any additional income tax expense for the Prior Successor Period as a result of maintaining a full valuation allowance against our net deferred tax asset.

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. Historically, we have generally funded our operations, planned capital expenditures, acquisitions of additional oil and

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natural gas properties and any debt or share repurchases with cash flow from our operating activities, cash on hand, borrowings under our revolving credit facility and issuances of equity and debt securities.

For the year ended December 31, 2022, our primary sources of capital resources and liquidity have consisted of internally generated cash flows from operations, and our primary uses of cash have been share repurchases pursuant to the Repurchase Program, repayments under the Credit Facility, dividend payments on our Preferred Stock and the development of our oil and natural gas properties.

We believe our annual free cash flow generation, cash on hand, and borrowing capacity under the Credit Facility will provide sufficient liquidity to fund our operations, capital expenditures, interest expense, debt repayments and any return of capital to shareholders authorized by the Board, during the next 12 months and the foreseeable future.

To the extent actual operating results, realized commodity prices or uses of cash differ from our assumptions, our liquidity could be adversely affected. See Note 5 of our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our notes.

As of December 31, 2022, we had $7.3 million of cash and cash equivalents compared to $3.3 million as of December 31, 2021, and a net working capital deficit of $391.1 million as of December 31, 2022, compared to a net working capital deficit of $361.4 million as of December 31, 2021. As of December 31, 2022, our working capital deficit includes no debt due in the next 12 months. Our total principal amount of funded debt as of December 31, 2022, was $695.0 million compared to $714.0 million as of December 31, 2021. See Note 5 of our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our notes.

As of February 23, 2023, we had $25.6 million of cash and cash equivalents, $79.0 million borrowings under our Credit Facility, $113.4 million of letters of credit outstanding, and $550 million of outstanding 2026 Senior Notes.

As discussed in Note 5 of our consolidated financial statements, when we entered into the Existing Credit Facility on October 14, 2021, it provided for an aggregate maximum principal amount of up to $1.5 billion, an initial borrowing base of $850.0 million and an initial aggregate elected commitment amount of $700.0 million. The Existing Credit Facility 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, we entered into the Amendment to Borrowing Base Redetermination Agreement and First Amendment to our Credit Agreement (“Amendment”), which amended the Existing Credit Facility (as amended, the "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) increased the Net Leverage Ratio allowing unlimited restricted payments from 1.00 to 1.00 to 1.25 to 1.00 and (ii) permitted 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 during which the borrowing base under the Credit Facility was reconfirmed at $1.0 billion with the elected commitments remaining at $700 million.

Additionally, on the Emergence Date, pursuant to the terms of the Plan, we issued 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.

We may continue to use a combination of cash, borrowings and issuances of our Common Stock or other securities to retire our outstanding debt and Preferred Stock through privately negotiated transactions, open market repurchases, redemptions, tender offers or otherwise, but we are under no obligation to do so.

See Note 5 of our consolidated financial statements for additional discussion of our outstanding post-emergence debt.

Preferred Stock Dividends. As discussed in Note 6 of our consolidated financial statements, holders of Preferred Stock are entitled to receive cumulative quarterly dividends at a rate of 10% per annum of the Liquidation Preference (as defined below) with respect to cash dividends and 15% per annum of the Liquidation Preference with respect to dividends paid in kind as additional shares of Preferred Stock (“PIK Dividends”). We currently have the option to pay either a cash or PIK dividend on a

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quarterly basis. Each share of Preferred Stock has a liquidation preference of $1,000 (the "Liquidation Preference"). The Preferred Stock has no stated maturity and will remain outstanding indefinitely unless repurchased or redeemed by the Company or converted into Common Stock.

During the year ended December 31, 2022, and Prior Successor Period, the Company paid $5.4 million and $1.5 million, respectively, of cash dividends to holders of our Preferred Stock.

Supplemental Guarantor Financial Information. The 2026 Senior Notes are guaranteed on a senior unsecured basis by all existing consolidated subsidiaries that guarantee our Credit Facility or certain other debt (collectively the “Guarantors”). The 2026 Senior Notes are not guaranteed by Grizzly Holdings or Mule Sky, LLC (the “Non-Guarantors”). The Guarantors are 100% owned by the Parent, and the guarantees are full, unconditional, joint and several. There are no significant restrictions on the ability of the Parent or the Guarantors to obtain funds from each other in the form of a dividend or loan. The guarantees rank equally in the right of payment with all of the senior indebtedness of the subsidiary guarantors and senior in the right of payment to any future subordinated indebtedness of the subsidiary guarantors. The 2026 Senior Notes and the guarantees are effectively subordinated to all of our and the subsidiary guarantors' secured indebtedness (including all borrowings and other obligations under the Credit Facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated to all indebtedness and other liabilities of any of our subsidiaries that do not guarantee the 2026 Senior Notes.

SEC Regulation S-X Rule 13-01 requires the presentation of "Summarized Financial Information" to replace the "Condensed Consolidating Financial Information" required under Rule 3-10. Rule 13-01 allows the omission of Summarized Financial Information if assets, liabilities and results of operations of the Guarantors are not materially different than the corresponding amounts presented in our consolidated financial statements. The Parent and Guarantor subsidiaries comprise our material operations. Therefore, we concluded that the presentation of the Summarized Financial Information is not required as our Summarized Financial Information of the Guarantors is not materially different from our consolidated financial statements.

Derivatives and Hedging Activities. Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. Our natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to predict with greater certainty the total revenue we will receive. See Item 7A Quantitative and Qualitative Disclosures About Market Risk for further discussion on the impact of commodity price risk on our financial position. Additionally, see Note 13 of our consolidated financial statements for further discussion of derivatives and hedging activities. Subsequent to December 31, 2022 and as of February 23, 2023, we entered into the following natural gas, oil, and NGL derivative contracts:

Additionally, subsequent to year end, the Company restructured a portion of its natural gas sold call position, by buying back a portion of its 2023 natural gas sold call position, and selling additional natural gas calls for 2023 and 2025. The following table summarizes these transactions: