# Gulfport Energy Corp: Form 10-Q for the period ended Mar 31, 2025

- Company: [Gulfport Energy Corp](/companies/gpor.md) (CIK 874499)
- Form: 10-Q
- Filed: 2025-05-07
- Accepted by EDGAR: May 7, 2025, 11:58 ET
- Period: 2025-03-31
- Accession: 0001628280-25-022951
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/874499/000162828025022951/gpor-20250331.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/874499/000162828025022951/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2025-03-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2025-01-01 to 2025-03-31 | $197.0m | us-gaap:Revenues |
| Cost of revenue | 3 months, 2025-01-01 to 2025-03-31 | $82.9m | us-gaap:CostOfRevenue |
| Operating income | 3 months, 2025-01-01 to 2025-03-31 | $12.0m | us-gaap:OperatingIncomeLoss |
| Interest expense | 3 months, 2025-01-01 to 2025-03-31 | $13.4m | us-gaap:InterestExpenseNonoperating |
| Income tax | 3 months, 2025-01-01 to 2025-03-31 | −$176.0k | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2025-01-01 to 2025-03-31 | −$464.0k | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2025-01-01 to 2025-03-31 | −$0.07 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2025-01-01 to 2025-03-31 | −$0.07 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2025-01-01 to 2025-03-31 | 17,881,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 3 months, 2025-01-01 to 2025-03-31 | $177.3m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Cash and equivalents | at 2025-03-31 | $5.3m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2025-03-31 | $205.3m | us-gaap:AssetsCurrent |
| Total assets | at 2025-03-31 | $2.95bn | us-gaap:Assets |
| Current liabilities | at 2025-03-31 | $477.5m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2025-03-31 | $1.26bn | us-gaap:Liabilities |
| Long-term debt | at 2025-03-31 | $700.4m | us-gaap:LongTermDebtNoncurrent |
| Current portion of debt | at 2025-03-31 | $0 | us-gaap:LongTermDebtCurrent |
| Shareholders' equity | at 2025-03-31 | $1.66bn | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 34,433 characters.

### Introduction

Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide the reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company's operating results. MD&A should be read in conjunction with the financial statements and related Notes included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

The following information updates the discussion of Gulfport’s financial condition provided in its Annual Report on Form 10-K for the year ended December 31, 2024 (“2024 Form 10-K”), and analyzes the changes in the results of operations between the periods of January 1, 2025 through March 31, 2025 and January 1, 2024 through March 31, 2024. For definitions of commonly used natural gas and oil terms found in this Quarterly Report on Form 10-Q, please refer to the “Definitions” provided in this report.

### 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

#### Credit Facility

On May 5, 2025, 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 $1 billion.

#### Share Repurchase Program

During the three months ended March 31, 2025, the Company repurchased 340,664 shares for $60.0 million at a weighted average price of $176.13 per share. As of March 31, 2025, the Company repurchased 5.9 million shares for $644.1 million at a weighted average price of $108.99 per share since the inception of the Repurchase Program.

#### Executive Orders

Recently announced changes under the Trump Administration, through executive orders and regulatory rollbacks, signal a shift in United States energy polices, creating a more uncertain regulatory landscape which may impact our business and operations.

#### Tariffs and Trading Relationships

In April 2025, the U.S. government announced a baseline tariff of 10% on products imported from all countries and an additional individualized reciprocal tariff on the countries with which the United States has the largest trade deficits, including China. Increased tariffs by the United States have led and may continue to lead to the imposition of retaliatory tariffs by foreign jurisdictions. Additionally, the U.S. government has announced and rescinded multiple tariffs on several foreign jurisdictions, which has increased uncertainty regarding the ultimate effect of the tariffs on economic conditions. Current uncertainties about tariffs and their effects on trading relationships may affect costs for and availability of raw materials, contribute to inflation in the markets in which we operate, delay access to capital markets and increase the likelihood of an economic downturn. Although we are continuing to monitor the economic effects of such announcements, as well as opportunities to mitigate their related impacts, costs and other effects associated with the tariffs remain uncertain.

### 2025 Operational and Financial Highlights

During the first quarter of 2025, we had the following notable achievements:

- Reported total net production of 929.3 MMcfe per day.
- Turned to sales seven gross (6.99 net) operated wells.
- Generated $177.3 million of operating cash flows.
- Reduced outstanding Credit Facility borrowings by $3.0 million as compared to December 31, 2024.
- Repurchased 340,664 shares for $60.0 million at a weighted average price of $176.13 per share.
- Exited the quarter with total liquidity of $906.5 million.

### 2025 Production and Drilling Activity

#### Production Volumes

| Natural gas (Mcf/day) | Three Months Ended March 31, 2025 | Three Months Ended March 31, 2024 |
| --- | ---: | ---: |
| Utica & Marcellus | 686,964 | 811,357 |
| SCOOP | 150,851 | 162,207 |
| Total | 837,816 | 973,564 |
| Oil and condensate (Bbl/day) |  |  |
| Utica & Marcellus | 3,861 | 1,348 |
| SCOOP | 1,420 | 1,980 |
| Total | 5,282 | 3,329 |
| NGL (Bbl/day) |  |  |
| Utica & Marcellus | 3,495 | 1,981 |
| SCOOP | 6,467 | 8,050 |
| Total | 9,962 | 10,031 |
| Combined (Mcfe/day) |  |  |
| Utica & Marcellus | 731,105 | 831,333 |
| SCOOP | 198,175 | 222,389 |
| Total | 929,280 | 1,053,722 |
| Totals may not sum or recalculate due to rounding. |  |  |

Our total net production averaged approximately 929.3 MMcfe per day during the three months ended March 31, 2025, as compared to 1,053.7 MMcfe per day during the three months ended March 31, 2024. Production per day declined primarily due to natural declines resulting from the timing of our 2024 and 2025 development programs.

*Utica/Marcellus*. We spud eight gross (7.98 net) wells targeting the Utica formation during the three months ended March 31, 2025. In addition, we commenced sales on seven gross (6.99 net) operated Utica wells in March 2025.

As of April 30, 2025, we had two operated drilling rigs running in Ohio drilling the Utica formation.

*SCOOP*. We did not spud or commence sales on any operated wells in the SCOOP during the three months ended March 31, 2025.

As of April 30, 2025, we did not have an operated drilling rig running in the SCOOP.

### RESULTS OF OPERATIONS

### Comparison of the Three Month Periods Ended March 31, 2025 and 2024

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

The following table summarizes our natural gas, oil and condensate and NGL production, and related pricing for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024. Some totals below may not sum or recalculate due to rounding.

| Natural gas sales | Three Months Ended March 31, 2025 | Three Months Ended March 31, 2024 |
| --- | ---: | ---: |
| Natural gas production volumes (MMcf) | 75,403 | 88,594 |
| Natural gas production volumes (MMcf) per day | 838 | 974 |
| Total sales | $281,506 | $188,286 |
| Average price without the impact of derivatives ($/Mcf) | $3.73 | $2.13 |
| Impact from settled derivatives ($/Mcf) | $(0.12) | $0.75 |
| **Average price, including settled derivatives ($/Mcf)** | $3.61 | $2.88 |
| **Oil and condensate sales** |  |  |
| Oil and condensate production volumes (MBbl) | 475 | 303 |
| Oil and condensate production volumes (MBbl) per day | 5 | 3 |
| Total sales | $31,259 | $21,701 |
| Average price without the impact of derivatives ($/Bbl) | $65.76 | $71.64 |
| Impact from settled derivatives ($/Bbl) | $1.06 | $0.04 |
| **Average price, including settled derivatives ($/Bbl)** | $66.82 | $71.68 |
| **NGL sales** |  |  |
| NGL production volumes (MBbl) | 897 | 913 |
| NGL production volumes (MBbl) per day | 10 | 10 |
| Total sales | $30,817 | $28,106 |
| Average price without the impact of derivatives ($/Bbl) | $34.37 | $30.79 |
| Impact from settled derivatives ($/Bbl) | $(1.53) | $(1.25) |
| **Average price, including settled derivatives ($/Bbl)** | $32.84 | $29.54 |
| **Natural gas, oil and condensate and NGL sales** |  |  |
| Natural gas equivalents (MMcfe) | 83,635 | 95,889 |
| Natural gas equivalents (MMcfe) per day | 929 | 1,054 |
| Total sales | $343,582 | $238,093 |
| Average price without the impact of derivatives ($/Mcfe) | $4.11 | $2.48 |
| Impact from settled derivatives ($/Mcfe) | $(0.12) | $0.68 |
| **Average price, including settled derivatives ($/Mcfe)** | $3.99 | $3.16 |
| **Production Costs:** |  |  |
| Average lease operating expenses ($/Mcfe) | $0.24 | $0.18 |
| Average taxes other than income ($/Mcfe) | $0.08 | $0.09 |
| Average transportation, gathering, processing and compression ($/Mcfe) | $0.99 | $0.90 |
| Total lease operating expenses, taxes other than income and midstream costs ($/Mcfe) | $1.31 | $1.16 |

29

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

|  | Three Months Ended March 31, 2025 | Three Months Ended March 31, 2024 | % Change |
| --- | ---: | ---: | ---: |
| Natural gas | $281,506 | $188,286 | 50% |
| Oil and condensate | 31,259 | 21,701 | 44% |
| NGL | 30,817 | 28,106 | 10% |
| Natural gas, oil and condensate and NGL sales | $343,582 | $238,093 | 44% |

The increase in natural gas sales without the impact of derivatives when comparing the three months ended March 31, 2025, to the three months ended March 31, 2024 was due to a 76% increase in realized natural gas prices, partially offset by a 15% decrease in sales volumes. The realized price change was primarily driven by the increase in the average Henry Hub gas index from $2.24 per Mcf in the three months ended March 31, 2024, to $3.65 per Mcf during the three months ended March 31, 2025. The 15% decrease in natural gas production was primarily due to natural declines partially offset by our 2024 and 2025 development programs.

The increase in oil and condensate sales without the impact of derivatives when comparing the three months ended March 31, 2025, to the three months ended March 31, 2024, was due to a 57% increase in sales volumes, partially offset by an 8% decrease in realized prices. The 57% 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 $76.96 per barrel in the three months ended March 31, 2024, to $71.42 per barrel during the three months ended March 31, 2025.

The increase in NGL sales without the impact of derivatives when comparing the three months ended March 31, 2025, to the three months ended March 31, 2024, was due to a 12% increase in realized prices, partially offset by a 2% decrease in NGL sales volumes. The realized price change was driven by the increase in the average Mont Belvieu NGL index from $30.46 per barrel in the three months ended March 31, 2024, to $34.42 per barrel during the three months ended March 31, 2025. The 2% decrease in NGL production was primarily due to natural declines partially offset by our 2024 and 2025 development programs.

#### Natural Gas, Oil and NGL Derivatives (in thousands)

|  | Three Months Ended March 31, 2025 | Three Months Ended March 31, 2024 |
| --- | ---: | ---: |
| Natural gas derivatives - fair value losses | $(133,664) | $(11,479) |
| Natural gas derivatives - settlement (losses) gains | (9,025) | 66,451 |
| Total (losses) gains on natural gas derivatives | (142,689) | 54,972 |
| Oil and condensate derivatives - fair value losses | (6) | (2,460) |
| Oil and condensate derivatives - settlement gains | 504 | 12 |
| Total gains (losses) on oil and condensate derivatives | 498 | (2,448) |
| NGL derivatives - fair value losses | (2,988) | (6,247) |
| NGL derivatives - settlement losses | (1,369) | (1,141) |
| Total losses on NGL derivatives | (4,357) | (7,388) |
| Total (losses) gains on natural gas, oil and NGL derivatives | $(146,548) | $45,136 |

We recognize fair value changes on our natural gas, oil and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationship between contract prices and the associated forward curves. The change in the total gain (loss) for the three months ended March 31, 2025 compared to the three months ended March 31, 2024, was primarily the result of changes in futures pricing for oil, natural gas, and NGLs during each period. See Note 10 of our consolidated financial statements for hedged volumes and pricing.

#### Lease Operating Expenses (in thousands, except per unit)

| Lease operating expenses | Three Months Ended March 31, 2025 | Three Months Ended March 31, 2024 | % Change |
| --- | ---: | ---: | ---: |
| Utica & Marcellus | $13,592 | $10,764 | 26% |
| SCOOP | 6,691 | 6,044 | 11% |
| Total lease operating expenses | $20,283 | $16,808 | 21% |
| **Lease operating expenses per Mcfe** |  |  |  |
| Utica & Marcellus | $0.21 | $0.14 | 45% |
| SCOOP | 0.38 | 0.30 | 26% |
| Total lease operating expenses per Mcfe | $0.24 | $0.18 | 38% |

The increase in our total and per unit LOE for the three months ended March 31, 2025 compared to the three months ended March 31, 2024, was primarily the result of an increase in water hauling, labor and costs associated with winter weather operations.

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

|  | Three Months Ended March 31, 2025 | Three Months Ended March 31, 2024 | % Change |
| --- | ---: | ---: | ---: |
| Production taxes | $5,438 | $5,047 | 8% |
| Property taxes | 428 | 2,609 | (84)% |
| Other | 760 | 604 | 26% |
| Total taxes other than income | $6,626 | $8,260 | (20)% |
| Total taxes other than income per Mcfe | $0.08 | $0.09 | (8)% |

The decrease in total and per unit taxes other than income for the three months ended March 31, 2025 compared to the three months ended March 31, 2024, was primarily related to a decrease in property taxes.

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

|  | Three Months Ended March 31, 2025 | Three Months Ended March 31, 2024 | % Change |
| --- | ---: | ---: | ---: |
| Transportation, gathering, processing and compression | $82,870 | $86,619 | (4)% |
| Transportation, gathering, processing and compression per Mcfe | $0.99 | $0.90 | 10% |

Transportation, gathering, processing and compression for the three months ended March 31, 2025 compared to the three months ended March 31, 2024, increased on a per unit basis primarily as a result of an increase in the proportion of natural gas liquids and oil and condensate sales and a 12% decrease in total production volumes due to natural declines and the timing of our 2024 and 2025 development programs during the three months ended March 31, 2025.

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

|  | Three Months Ended March 31, 2025 | Three Months Ended March 31, 2024 | % Change |
| --- | ---: | ---: | ---: |
| Depreciation, depletion and amortization of oil and gas properties | $65,090 | $79,681 | (18)% |
| Depreciation, depletion and amortization of other property and equipment | 532 | 342 | 55% |
| Total depreciation, depletion and amortization | $65,622 | $80,023 | (18)% |
| Depreciation, depletion and amortization per Mcfe | $0.78 | $0.83 | (6)% |

The total and per unit depreciation, depletion and amortization of our oil and gas properties for the three months ended March 31, 2025 compared to the three months ended March 31, 2024, decreased primarily due to a lower depletion rate resulting from a decline in our amortization base from the full cost ceiling test impairments recorded during 2024, combined with a decrease in our production as noted above.

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

|  | Three Months Ended March 31, 2025 | Three Months Ended March 31, 2024 | % Change |
| --- | ---: | ---: | ---: |
| General and administrative expenses, gross | $19,199 | $18,442 | 4% |
| Reimbursed from third parties | (3,966) | (3,538) | 12% |
| Capitalized general and administrative expenses | (6,232) | (5,706) | 9% |
| General and administrative expenses, net | $9,001 | $9,198 | (2)% |
| General and administrative expenses, net per Mcfe | $0.11 | $0.10 | 12% |

The decrease in general and administrative expenses for the three months ended March 31, 2025 compared to March 31, 2024, was primarily driven by lower legal expenses partially offset by increased headcount and compensation expenses.

#### Interest Expense (in thousands, except per unit)

|  | Three Months Ended March 31, 2025 | Three Months Ended March 31, 2024 | % Change |
| --- | ---: | ---: | ---: |
| Interest on 2026 Senior Notes | $514 | $11,000 | (95)% |
| Interest on 2029 Senior Notes | 10,969 | — | 100% |
| Interest expense on Credit Facility | 1,685 | 3,721 | (55)% |
| Amortization of loan costs | 1,300 | 945 | 38% |
| Capitalized interest | (1,430) | (1,131) | 26% |
| Other | 318 | 468 | (32)% |
| Total interest expense | $13,356 | $15,003 | (11)% |
| Interest expense per Mcfe | $0.16 | $0.16 | 2% |

Due to the tender offer for the 2026 Senior Notes in the third quarter of 2024, interest paid on the 2026 Senior Notes decreased 95% for the three months ended March 31, 2025 compared to the three months ended March 31, 2024. The Company also incurred $11.0 million of interest on the 2029 Senior Notes for the three months ended March 31, 2025. Interest expense on our Credit Facility decreased 55% for the three months ended March 31, 2025 compared to the three months ended March 31, 2024, as a result of a lower average interest rate and balance outstanding. Amortization of loan costs increased 38% for the three months ended March 31, 2025 compared to the three months ended March 31, 2024, as a result of the Fourth Amendment to the Credit Facility which increased the elected commitments. See Note 4 of our consolidated financial statements for further details of our Credit Facility. The Company also capitalized $1.4 million and $1.1 million in interest expense for the three months ended March 31, 2025 and 2024, respectively.

#### Income Taxes

We recorded an income tax benefit of $0.2 million for the three months ended March 31, 2025 compared to income tax expense of $14.9 million for the three months ended March 31, 2024. See Note 14 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 three months ended March 31, 2025, 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 and dividend payments on our preferred stock.

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 4 of our consolidated financial statements for further discussion of our debt obligations, including the principal and carrying amounts of our senior notes.

As of March 31, 2025, we had $5.3 million of cash and cash equivalents, $35.0 million outstanding 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. Our total principal amount of funded debt as of March 31, 2025 was $710.7 million.

As of April 30, 2025 we had $3.1 million of cash and cash equivalents, $5.0 million in 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 by 50 bps.

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 three months ended March 31, 2025, the Company paid $0.9 million of cash dividends to holders of our preferred stock compared to $1.1 million during the three months ended March 31, 2024.

*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 3 Quantitative and Qualitative Disclosures About Market Risk for further discussion on the impact of commodity price risk on our financial position. Additionally, see Note 10 of our consolidated financial statements for further discussion of derivatives and hedging activities.

*Capital Expenditures*. Our capital expenditures have historically been related to the execution of our drilling and completion activities in addition to certain lease acquisition activities. Our capital investment strategy is focused on prudently developing our existing properties to generate sustainable cash flow considering current and forecasted commodity prices. For the three months ended March 31, 2025, the Company incurred capital expenditures of $159.8 million related to operated activities, of which $148.6 million related to drilling and completion activities and $11.2 million related to maintenance leasehold and land investment.

Our operated 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.

### Sources and Uses of Cash

The following table presents the major changes in cash and cash equivalents for the three months ended March 31, 2025 and 2024 (in thousands):

|  | Three Months Ended March 31, 2025 | Three Months Ended March 31, 2024 |
| --- | ---: | ---: |
| Net cash provided by operating activities | $177,280 | $188,022 |
| Additions to oil and natural gas properties | (108,231) | (118,146) |
| Debt activity, net | (3,000) | (31,000) |
| Repurchases of common stock | (57,809) | (29,493) |
| Dividends on preferred stock | (862) | (1,105) |
| Shares exchanged for tax withholdings | (2,962) | (1,085) |
| Other | (547) | (913) |
| Net change in cash and cash equivalents | $3,869 | $6,280 |
| Cash and cash equivalents at end of period | $5,342 | $8,209 |

*Net cash provided by operating activities.* Net cash flow provided by operating activities was $177.3 million for the three months ended March 31, 2025, as compared to $188.0 million for the three months ended March 31, 2024.

*Additions to oil and natural gas properties.* During the three months ended March 31, 2025, we spud eight gross (7.98 net) operated wells and commenced sales from seven gross (6.99 net) operated wells targeting the Utica formation for a total incurred cost of approximately $129.8 million. During the three months ended March 31, 2025, we did not spud or commence sales on any operated wells in the SCOOP and had one operated drilling rig running for a total incurred cost of approximately $18.8 million.

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 three months ended March 31, 2025 and 2024, were as follows (in thousands):

| Oil and Natural Gas Property Cash Expenditures: | Three Months Ended March 31, 2025 | Three Months Ended March 31, 2024 |
| --- | ---: | ---: |
| Drilling and completion costs | $90,859 | $93,685 |
| Leasehold acquisitions | 11,207 | 18,360 |
| Other | 6,165 | 6,101 |
| Total oil and natural gas property expenditures | $108,231 | $118,146 |

*Debt activity, net.* In the three months ended March 31, 2025, the Company had $125.0 million and $128.0 million in borrowings and repayments, respectively, on its Credit Facility. As of April 30, 2025 the Company had $5.0 million in borrowings outstanding on its Credit Facility.

*Repurchases of common stock.* During the three months ended March 31, 2025, the Company repurchased 340,664 shares for approximately $60.0 million under the Repurchase Program at a weighted average price of $176.13 per share. For the same period in 2024, the Company repurchased 210,075 shares for $29.5 million at a weighted average price of $140.39 per share. As of April 30, 2025, we repurchased 5,954,014 shares for approximately $651.6 million under the Repurchase Program at a weighted average price of $109.44 per share.

*Dividends on preferred stock.* During the three months ended March 31, 2025, the Company paid $0.9 million of cash dividends to holders of our preferred stock compared to $1.1 million in the three months ended March 31, 2024.

*Shares exchanged for tax withholdings.* During the three months ended March 31, 2025, the Company paid $3.0 million of shares exchanged for tax withholdings compared to $1.1 million in the three months ended March 31, 2024.

### Contractual and Commercial Obligations

We have various contractual obligations in the normal course of our operations and financing activities, as discussed in Note 9 of our consolidated financial statements. There have been no other material changes to our contractual obligations from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2024.

### Off-balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of March 31, 2025, our material off-balance sheet arrangements and transactions include $63.9 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 on 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 continues through 2025, with approximately $4.1 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 9 of our consolidated financial statements for further discussion of the various financial guarantees we have issued.

### Critical Accounting Policies and Estimates

As of March 31, 2025, there have been no significant changes in our critical accounting policies from those disclosed in our 2024 Annual Report on Form 10-K.

## Market risk

As filed, 6,983 characters.

*Natural Gas, Oil and Natural Gas Liquids Derivative Instruments.* Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL. To mitigate a portion of our exposure to adverse price changes, we have entered into various derivative instruments. Our natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to predict with greater certainty the revenue we will receive. We believe our derivative instruments continue to be highly effective in achieving our risk management objectives.

Our general strategy for protecting short-term cash flow and attempting to mitigate exposure to adverse natural gas, oil and NGL price changes is to hedge into strengthening natural gas, oil and NGL futures markets when prices reach levels that management believes provide reasonable rates of return on our invested capital. Information we consider in forming an opinion about future prices includes general economic conditions, industrial output levels and expectations, producer breakeven cost structures, liquefied natural gas trends, oil and natural gas storage inventory levels, industry decline rates for base production and weather trends. Executive management is involved in all risk management activities and the board of directors reviews our derivative program at its quarterly board meetings.

We use derivative instruments to achieve our risk management objectives, including swaps, options and costless collars. All of these are described in more detail below. We typically use swaps for a large portion of the oil and natural gas price risk we hedge. We have also sold calls in the past to take advantage of premiums associated with market price volatility.

We determine the notional volume potentially subject to derivative contracts by reviewing our overall estimated future production levels, which are derived from extensive examination of existing producing reserve estimates and estimates of estimated production from new drilling. Production forecasts are updated at least monthly and adjusted if necessary to actual results and activity levels. We do not enter into derivative contracts for volumes in excess of our share of forecasted production, and if production estimates were lowered for future periods and derivative instruments are already executed for some volume above the new production forecasts, the positions are typically reversed. The actual fixed prices on our derivative instruments is derived from the reference prices from third-party indices such as NYMEX. All of our commodity derivative instruments are net settled based on the difference between the fixed price as stated in the contract and the floating-price, resulting in a net amount due to or from the counterparty.

We review our derivative positions continuously and if future market conditions change and prices are at levels we believe could jeopardize the effectiveness of a position, we will mitigate this risk by either negotiating a cash settlement with our counterparty, restructuring the position or entering a new trade that effectively reverses the current position. The factors we consider in closing or restructuring a position before the settlement date are identical to those we review when deciding to enter the original derivative position.

We have determined the fair value of our derivative instruments utilizing established index prices, volatility curves, discount factors and option pricing models. These estimates are compared to counterparty valuations for reasonableness. Derivative transactions are also subject to the risk that counterparties will be unable to meet their obligations. This non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. See Note 11 of our consolidated financial statements for further discussion of the fair value measurements associated with our derivatives.

As of March 31, 2025, our natural gas, oil and NGL derivative instruments consisted of the following types of instruments:

- *Swaps*: We receive a fixed price and pay a floating market price to the counterparty for the hedged commodity. In exchange for higher fixed prices on certain of our swap trades, we may sell call options.
- *Basis Swaps*: These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point. We receive the fixed price differential and pay the floating market price differential to the counterparty for the hedged commodity.
- *Costless Collars*: Each two-way collar has a set floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, the Company will cash-settle the difference with the counterparty.
- *Call Options*: We sell, and occasionally buy, call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, we pay the counterparty the excess on sold call options, and we would receive the excess on bought call options. If the market price settles below the fixed price of the call option, no payment is due from either party.

Our hedge arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or commodity prices increase. At March 31, 2025, we had a net liability derivative position of $149.5 million as compared to a net liability derivative position of $12.9 million as of December 31, 2024. Utilizing actual derivative contractual volumes, a 10% increase in underlying commodity prices would have increased our liability by approximately $97.2 million, while a 10% decrease in underlying commodity prices would have decreased our liability by approximately $93.8 million. However, any realized derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument.

*Interest Rate Risk.* Our Credit Facility is structured under floating rate terms, as advances under these facilities may be in the form of either base rate loans or term benchmark loans. As such, our interest expense is sensitive to fluctuations in the prime rates in the United States, or, if the term benchmark rates are elected, the term benchmark rates. At March 31, 2025, we had $35.0 million outstanding borrowings under our Credit Facility which bore interest at a weighted average rate of 6.79% for the three months ended March 31, 2025. As of March 31, 2025, we did not have any interest rate swaps to hedge interest rate risks.

## Controls and procedures

As filed, 2,309 characters.

*Evaluation of Disclosure Control and Procedures*. Under the direction of our Chief Executive Officer and our Chief Financial Officer, and with participation of management, we have established disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.

As of March 31, 2025, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and our Chief Financial Officer have concluded that, as of March 31, 2025, our disclosure controls and procedures are effective.

In designing and evaluating the Company's disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that the Company's controls will succeed in achieving their goals under all potential future conditions.

*Changes in Internal Control over Financial Reporting*. There have not been any changes in our internal control over financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

## Risk factors

As filed, 327 characters.

Our business has many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our common stock or senior notes are described below and under "Risk Factors" in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2024.

Filed May 7, 2025.
Source: SEC EDGAR, the filing index for accession 0001628280-25-022951. Last ingested by Listed: Nov 5, 2026, 16:36 ET. No prices; not investment advice.