# Gulfport Energy Corp: Form 10-Q for the period ended Sep 30, 2024

- Company: [Gulfport Energy Corp](/companies/gpor.md) (CIK 874499)
- Form: 10-Q
- Filed: 2024-11-06
- Accepted by EDGAR: Nov 6, 2024, 10:42 ET
- Period: 2024-09-30
- Accession: 0001628280-24-045496
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/874499/000162828024045496/gpor-20240930.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/874499/000162828024045496/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2024-09-30.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2024-07-01 to 2024-09-30 | $253.9m | us-gaap:Revenues |
| Revenue | 9 months, 2024-01-01 to 2024-09-30 | $718.3m | us-gaap:Revenues |
| Cost of revenue | 3 months, 2024-07-01 to 2024-09-30 | $89.9m | us-gaap:CostOfRevenue |
| Cost of revenue | 9 months, 2024-01-01 to 2024-09-30 | $263.0m | us-gaap:CostOfRevenue |
| Operating income | 3 months, 2024-07-01 to 2024-09-30 | $14.6m | us-gaap:OperatingIncomeLoss |
| Operating income | 9 months, 2024-01-01 to 2024-09-30 | $78.2m | us-gaap:OperatingIncomeLoss |
| Interest expense | 3 months, 2024-07-01 to 2024-09-30 | $15.9m | us-gaap:InterestExpenseNonoperating |
| Interest expense | 9 months, 2024-01-01 to 2024-09-30 | $46.0m | us-gaap:InterestExpenseNonoperating |
| Income tax | 3 months, 2024-07-01 to 2024-09-30 | −$3.8m | us-gaap:IncomeTaxExpenseBenefit |
| Income tax | 9 months, 2024-01-01 to 2024-09-30 | $3.4m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2024-07-01 to 2024-09-30 | −$14.0m | us-gaap:NetIncomeLoss |
| Net income | 9 months, 2024-01-01 to 2024-09-30 | $11.9m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2024-07-01 to 2024-09-30 | −$0.83 | us-gaap:EarningsPerShareDiluted |
| Diluted EPS | 9 months, 2024-01-01 to 2024-09-30 | $0.40 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2024-07-01 to 2024-09-30 | −$0.83 | us-gaap:EarningsPerShareBasic |
| Basic EPS | 9 months, 2024-01-01 to 2024-09-30 | $0.40 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2024-07-01 to 2024-09-30 | 18,062,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Diluted shares (weighted) | 9 months, 2024-01-01 to 2024-09-30 | 18,463,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 9 months, 2024-01-01 to 2024-09-30 | $501.2m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Cash and equivalents | at 2024-09-30 | $3.2m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2024-09-30 | $223.4m | us-gaap:AssetsCurrent |
| Total assets | at 2024-09-30 | $3.18bn | us-gaap:Assets |
| Current liabilities | at 2024-09-30 | $327.1m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2024-09-30 | $1.08bn | us-gaap:Liabilities |
| Long-term debt | at 2024-09-30 | $694.4m | us-gaap:LongTermDebtNoncurrent |
| Current portion of debt | at 2024-09-30 | $0 | us-gaap:LongTermDebtCurrent |
| Shareholders' equity | at 2024-09-30 | $2.06bn | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 52,904 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, 2023 (“2023 Form 10-K”) and analyzes the changes in the results of operations between the periods of July 1, 2024 through September 30, 2024, January 1, 2024 through September 30, 2024, July 1, 2023 through September 30, 2023 and January 1, 2023 through September 30, 2023. 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

#### 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 the 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.

#### Share Repurchase Program

During the three months ended September 30, 2024, the Company repurchased 341,132 shares for $49.9 million at a weighted average price of $146.17 per share. As of September 30, 2024, the Company repurchased 5.1 million shares for $504.0 million at a weighted average price of $99.25 per share since the inception of the Repurchase Program.

#### Impact of the War in Ukraine and the conflict in the Middle East

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 conflict in the Middle East, may result in further disruptions in the global economic environment. The ultimate impact of the war in Ukraine and the conflict in the Middle East will depend on future developments and the timing and extent to which normal economic and operating conditions resume.

### 2024 Operational and Financial Highlights

During the third quarter of 2024, we had the following notable achievements:

- Reported total net production of 1,057.2 MMcfe per day.
- Turned to sales 10 gross (9.0 net) operated wells.
- Generated $189.7 million of operating cash flows.
- Repurchased 341,132 shares for $49.9 million at a weighted average price of $146.17 per share.
- Exited the quarter with total liquidity of $909.4 million.
- Extended the maturity of substantially all long-term Senior Notes from 2026 to 2029.
- Extended the maturity of the Credit Facility to 2028.

### 2024 Production and Drilling Activity

#### Production Volumes

| Natural gas (Mcf/day) | Three Months Ended September 30, 2024 | Three Months Ended September 30, 2023 |
| --- | ---: | ---: |
| Utica & Marcellus | 822,015 | 795,191 |
| SCOOP | 144,507 | 176,161 |
| Total | 966,522 | 971,352 |
| Oil and condensate (Bbl/day) |  |  |
| Utica & Marcellus | 3,105 | 528 |
| SCOOP | 1,513 | 2,667 |
| Total | 4,618 | 3,195 |
| NGL (Bbl/day) |  |  |
| Utica & Marcellus | 3,491 | 2,271 |
| SCOOP | 6,998 | 8,790 |
| Total | 10,489 | 11,061 |
| Combined (Mcfe/day) |  |  |
| Utica & Marcellus | 861,592 | 811,985 |
| SCOOP | 195,572 | 244,902 |
| Total | 1,057,164 | 1,056,887 |
| Totals may not sum or recalculate due to rounding. |  |  |

Our total net production averaged approximately 1,057.2 MMcfe per day during the three months ended September 30, 2024, as compared to 1,056.9 MMcfe per day during the three months ended September 30, 2023. Production per day remained consistent largely as a result of our 2023 and 2024 development programs.

| Natural gas (Mcf/day) | Nine Months Ended September 30, 2024 | Nine Months Ended September 30, 2023 |
| --- | ---: | ---: |
| Utica & Marcellus | 816,788 | 755,372 |
| SCOOP | 154,054 | 198,616 |
| Total | 970,842 | 953,989 |
| Oil and condensate (Bbl/day) |  |  |
| Utica & Marcellus | 1,815 | 558 |
| SCOOP | 1,754 | 3,256 |
| Total | 3,569 | 3,813 |
| NGL (Bbl/day) |  |  |
| Utica & Marcellus | 2,610 | 2,466 |
| SCOOP | 7,629 | 9,921 |
| Total | 10,239 | 12,387 |
| Combined (Mcfe/day) |  |  |
| Utica & Marcellus | 843,339 | 773,512 |
| SCOOP | 210,348 | 277,676 |
| Total | 1,053,687 | 1,051,188 |
| Totals may not sum or recalculate due to rounding. |  |  |

Our total net production averaged approximately 1,053.7 MMcfe per day during the nine months ended September 30, 2024, as compared to 1,051.2 MMcfe per day during the nine months ended September 30, 2023. Production per day remained consistent largely as a result of our 2023 and 2024 development programs.

*Utica/Marcellus*. We spud three gross (3.0 net) operated wells targeting the Utica formation during the three months ended September 30, 2024. In addition, we commenced sales on seven gross (6.6 net) operated Utica wells.

As of October 28, 2024, we had one operated drilling rig running in Ohio drilling the Utica formation.

*SCOOP*. We did not spud any operated wells in the SCOOP during the three months ended September 30, 2024. We commenced sales on three gross (2.4 net) operated wells.

As of October 28, 2024, we had one operated drilling rig running in the SCOOP.

### RESULTS OF OPERATIONS

### Comparison of the Three Month Periods Ended September 30, 2024 and 2023

#### 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 September 30, 2024 as compared to the three months ended September 30, 2023. Some totals below may not sum or recalculate due to rounding.

| Natural gas sales | Three Months Ended September 30, 2024 | Three Months Ended September 30, 2023 |
| --- | ---: | ---: |
| Natural gas production volumes (MMcf) | 88,920 | 89,364 |
| Natural gas production volumes (MMcf) per day | 967 | 971 |
| Total sales | $159,862 | $177,401 |
| Average price without the impact of derivatives ($/Mcf) | $1.80 | $1.99 |
| Impact from settled derivatives ($/Mcf) | $0.95 | $0.54 |
| **Average price, including settled derivatives ($/Mcf)** | $2.75 | $2.53 |
| **Oil and condensate sales** |  |  |
| Oil and condensate production volumes (MBbl) | 425 | 294 |
| Oil and condensate production volumes (MBbl) per day | 5 | 3 |
| Total sales | $29,467 | $22,896 |
| Average price without the impact of derivatives ($/Bbl) | $69.35 | $77.90 |
| Impact from settled derivatives ($/Bbl) | $0.22 | $(7.25) |
| **Average price, including settled derivatives ($/Bbl)** | $69.57 | $70.65 |
| **NGL sales** |  |  |
| NGL production volumes (MBbl) | 965 | 1,018 |
| NGL production volumes (MBbl) per day | 10 | 11 |
| Total sales | $26,617 | $26,953 |
| Average price without the impact of derivatives ($/Bbl) | $27.58 | $26.49 |
| Impact from settled derivatives ($/Bbl) | $(0.16) | $2.62 |
| **Average price, including settled derivatives ($/Bbl)** | $27.42 | $29.11 |
| **Natural gas, oil and condensate and NGL sales** |  |  |
| Natural gas equivalents (MMcfe) | 97,259 | 97,234 |
| Natural gas equivalents (MMcfe) per day | 1,057 | 1,057 |
| Total sales | $215,946 | $227,250 |
| Average price without the impact of derivatives ($/Mcfe) | $2.22 | $2.34 |
| Impact from settled derivatives ($/Mcfe) | $0.87 | $0.50 |
| **Average price, including settled derivatives ($/Mcfe)** | $3.09 | $2.84 |
| **Production Costs:** |  |  |
| Average lease operating expenses ($/Mcfe) | $0.19 | $0.16 |
| Average taxes other than income ($/Mcfe) | $0.07 | $0.07 |
| Average transportation, gathering, processing and compression ($/Mcfe) | $0.92 | $0.89 |
| Total lease operating expenses, taxes other than income and midstream costs ($/Mcfe) | $1.18 | $1.12 |

37

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

|  | Three Months Ended September 30, 2024 | Three Months Ended September 30, 2023 | % Change |
| --- | ---: | ---: | ---: |
| Natural gas | $159,862 | $177,401 | (10)% |
| Oil and condensate | 29,467 | 22,896 | 29% |
| NGL | 26,617 | 26,953 | (1)% |
| Natural gas, oil and condensate and NGL sales | $215,946 | $227,250 | (5)% |

The decrease in natural gas sales without the impact of derivatives when comparing the three months ended September 30, 2024, to the three months ended September 30, 2023 was due to a 10% decrease in realized prices. The realized price change was primarily driven by the decrease in the average Henry Hub gas index from $2.55 per Mcf in the three months ended September 30, 2023, to $2.16 per Mcf during the three months ended September 30, 2024.

The increase in oil and condensate sales without the impact of derivatives when comparing the three months ended September 30, 2024, to the three months ended September 30, 2023, was due to a 45% increase in sales volumes, partially offset by a 11% decrease in realized prices. The 45% increase in oil and condensate production was primarily due to commencement of sales on new wells targeting the Utica liquids window, partially offset by lower SCOOP production as a result of limited 2023 development activity. The realized price change was primarily driven by the decrease in the average WTI crude index from $82.26 per barrel in the three months ended September 30, 2023, to $75.09 per barrel during the three months ended September 30, 2024.

The decrease in NGL sales without the impact of derivatives when comparing the three months ended September 30, 2024, to the three months ended September 30, 2023, was due to a 5% decrease in NGL sales volumes, partially offset by a 4% increase in realized prices. The 5% decrease in NGL production was primarily due to natural declines and limited 2023 development activity in the SCOOP. The realized price change was primarily driven by the increase in the average Mont Belvieu NGL index from $28.27 per barrel in the three months ended September 30, 2023, to $30.22 per barrel during the three months ended September 30, 2024.

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

|  | Three Months Ended September 30, 2024 | Three Months Ended September 30, 2023 |
| --- | ---: | ---: |
| Natural gas derivatives - fair value (losses) gains | $(57,168) | $4,534 |
| Natural gas derivatives - settlement gains | 84,943 | 48,522 |
| Total gains on natural gas derivatives | 27,775 | 53,056 |
| Oil derivatives - fair value gains (losses) | 6,698 | (8,414) |
| Oil derivatives - settlement gains (losses) | 93 | (2,130) |
| Total gains (losses) on oil and condensate derivatives | 6,791 | (10,544) |
| NGL derivatives - fair value gains (losses) | 3,559 | (5,763) |
| NGL derivatives - settlement (losses) gains | (159) | 2,668 |
| Total gains (losses) on NGL derivatives | 3,400 | (3,095) |
| Total gains on natural gas, oil and NGL derivatives | $37,966 | $39,417 |

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 for the three months ended September 30, 2024 compared to the three months ended September 30, 2023, 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 September 30, 2024 | Three Months Ended September 30, 2023 | % Change |
| --- | ---: | ---: | ---: |
| Utica & Marcellus | $13,080 | $10,343 | 26% |
| SCOOP | 5,138 | 5,284 | (3)% |
| Total lease operating expenses | $18,218 | $15,627 | 17% |
| **Lease operating expenses per Mcfe** |  |  |  |
| Utica & Marcellus | $0.17 | $0.14 | 21% |
| SCOOP | 0.29 | 0.23 | 26% |
| Total lease operating expenses per Mcfe | $0.19 | $0.16 | 17% |

The increase in our total and per unit LOE for the three months ended September 30, 2024 compared to the three months ended September 30, 2023, was primarily the result of an increase in water disposal activities in the Utica/Marcellus and an increase in repairs, maintenance and compression activities in the SCOOP.

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

|  | Three Months Ended September 30, 2024 | Three Months Ended September 30, 2023 | % Change |
| --- | ---: | ---: | ---: |
| Production taxes | $4,528 | $5,897 | (23)% |
| Property taxes | 1,797 | 1,163 | 55% |
| Other | 508 | 156 | 226% |
| Total taxes other than income | $6,833 | $7,216 | (5)% |
| Total taxes other than income per Mcfe | $0.07 | $0.07 | —% |

The decrease in total taxes other than income for the three months ended September 30, 2024 compared to the three months ended September 30, 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)

|  | Three Months Ended September 30, 2024 | Three Months Ended September 30, 2023 | % Change |
| --- | ---: | ---: | ---: |
| Transportation, gathering, processing and compression | $89,900 | $86,602 | 4% |
| Transportation, gathering, processing and compression per Mcfe | $0.92 | $0.89 | 4% |

Transportation, gathering, processing and compression for the three months ended September 30, 2024 compared to the three months ended September 30, 2023, increased primarily as a result of the increase in our production as noted above.

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

|  | Three Months Ended September 30, 2024 | Three Months Ended September 30, 2023 | % Change |
| --- | ---: | ---: | ---: |
| Depreciation, depletion and amortization of oil and gas properties | $82,368 | $79,166 | 4% |
| Depreciation, depletion and amortization of other property and equipment | 457 | 339 | 35% |
| Total depreciation, depletion and amortization | $82,825 | $79,505 | 4% |
| Depreciation, depletion and amortization per Mcfe | $0.85 | $0.82 | 4% |

The total and per unit depreciation, depletion and amortization of our oil and gas properties for the three months ended September 30, 2024 compared to the three months ended September 30, 2023, increased 4% primarily as a 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 for the three months ended September 30, 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. We did not record an impairment during the three months ended September 30, 2023.

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

|  | Three Months Ended September 30, 2024 | Three Months Ended September 30, 2023 | % Change |
| --- | ---: | ---: | ---: |
| General and administrative expenses, gross | $20,694 | $18,983 | 9% |
| Reimbursed from third parties | (3,720) | (3,431) | 8% |
| Capitalized general and administrative expenses | (6,495) | (5,658) | 15% |
| General and administrative expenses, net | $10,479 | $9,894 | 6% |
| General and administrative expenses, net per Mcfe | $0.11 | $0.10 | 6% |

The increase in total and per unit general and administrative expenses for the three months ended September 30, 2024 compared to the three months ended September 30, 2023, was primarily driven by increases in employee compensation.

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

|  | Three Months Ended September 30, 2024 | Three Months Ended September 30, 2023 | % Change |
| --- | ---: | ---: | ---: |
| Interest on 2026 Senior Notes | $9,014 | $11,000 | (18)% |
| Interest on 2029 Senior Notes | 2,194 | — | 100% |
| Interest expense on Credit Facility | 4,423 | 4,088 | 8% |
| Amortization of loan costs | 1,016 | 927 | 10% |
| Capitalized interest | (1,230) | (1,115) | 10% |
| Other | 449 | 19 | 2263% |
| Total interest expense | $15,866 | $14,919 | 6% |
| Interest expense per Mcfe | $0.16 | $0.15 | 6% |

Due to the tender of the 2026 Senior Notes, interest paid on the 2026 Senior Notes decreased 18% for the three months ended September 30, 2024 compared to the three months September 30, 2023. The Company also paid $2.2 million of interest on the 2029 Senior Notes for the three months ended September 30, 2024. Interest expense on our Credit Facility increased 8% for the three months ended September 30, 2024 compared to the three months ended September 30, 2023, as a result of a higher average balance outstanding. Amortization of loan costs increased 10% for the three months ended September 30, 2024 compared to the three months ended September 30, 2023, as a result of the Third and Fourth Amendments to the Credit Facility which increased the elected commitments and borrowing base. The Company also capitalized $1.2 million and $1.1 million in interest expense for the three months ended September 30, 2024 and September 30, 2023, respectively.

#### 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)

|  | Three Months Ended September 30, 2024 | Three Months Ended September 30, 2023 | % Change |
| --- | ---: | ---: | ---: |
| Other, net | $3,133 | $(1,438) | (318)% |

Other, net in the Company’s consolidated statements of operations for the three months ended September 30, 2024, included approximately $3.0 million related to changes in the Company’s legal reserves for certain litigation and regulatory proceedings.

#### Income Taxes

We recorded income tax benefit of $3.8 million and $554.7 million for the three months ended September 30, 2024 and September 30, 2023, respectively. See Note 14 of our consolidated financial statements for further discussion of our income tax benefit.

### Comparison of the Nine Month Periods Ended September 30, 2024 and 2023

#### 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 nine months ended September 30, 2024 as compared to the nine months ended September 30, 2023. Some totals below may not sum or recalculate due to rounding.

| Natural gas sales | Nine Months Ended September 30, 2024 | Nine Months Ended September 30, 2023 |
| --- | ---: | ---: |
| Natural gas production volumes (MMcf) | 266,011 | 260,439 |
| Natural gas production volumes (MMcf) per day | 971 | 954 |
| Total sales | $492,606 | $619,181 |
| Average price without the impact of derivatives ($/Mcf) | $1.85 | $2.38 |
| Impact from settled derivatives ($/Mcf) | $0.91 | $0.37 |
| **Average price, including settled derivatives ($/Mcf)** | $2.76 | $2.75 |
| **Oil and condensate sales** |  |  |
| Oil and condensate production volumes (MBbl) | 978 | 1,041 |
| Oil and condensate production volumes (MBbl) per day | 4 | 4 |
| Total sales | $70,295 | $76,212 |
| Average price without the impact of derivatives ($/Bbl) | $71.89 | $73.21 |
| Impact from settled derivatives ($/Bbl) | $(0.17) | $(2.29) |
| **Average price, including settled derivatives ($/Bbl)** | $71.72 | $70.92 |
| **NGL sales** |  |  |
| NGL production volumes (MBbl) | 2,805 | 3,382 |
| NGL production volumes (MBbl) per day | 10 | 12 |
| Total sales | $80,870 | $92,935 |
| Average price without the impact of derivatives ($/Bbl) | $28.83 | $27.48 |
| Impact from settled derivatives ($/Bbl) | $(0.55) | $1.88 |
| **Average price, including settled derivatives ($/Bbl)** | $28.28 | $29.36 |
| **Natural gas, oil and condensate and NGL sales** |  |  |
| Natural gas equivalents (MMcfe) | 288,710 | 286,974 |
| Natural gas equivalents (MMcfe) per day | 1,054 | 1,051 |
| Total sales | $643,771 | $788,328 |
| Average price without the impact of derivatives ($/Mcfe) | $2.23 | $2.75 |
| Impact from settled derivatives ($/Mcfe) | $0.83 | $0.35 |
| **Average price, including settled derivatives ($/Mcfe)** | $3.06 | $3.10 |
| **Production Costs:** |  |  |
| Average lease operating expenses ($/Mcfe) | $0.18 | $0.18 |
| Average taxes other than income ($/Mcfe) | $0.08 | $0.09 |
| Average transportation, gathering, processing and compression ($/Mcfe) | $0.91 | $0.91 |
| Total lease operating expenses, taxes other than income and midstream costs ($/Mcfe) | $1.16 | $1.18 |

42

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

|  | Nine Months Ended September 30, 2024 | Nine Months Ended September 30, 2023 | % Change |
| --- | ---: | ---: | ---: |
| Natural gas | $492,606 | $619,181 | (20)% |
| Oil and condensate | 70,295 | 76,212 | (8)% |
| NGL | 80,870 | 92,935 | (13)% |
| Natural gas, oil and condensate and NGL sales | $643,771 | $788,328 | (18)% |

The decrease in natural gas sales without the impact of derivatives when comparing the nine months ended September 30, 2024, to the nine months ended September 30, 2023 was due to a 22% decrease in realized prices, partially offset by a 2% increase in sales volumes. The realized price change was primarily driven by the decrease in the average Henry Hub gas index from $2.69 per Mcf in the nine months ended September 30, 2023, to $2.10 per Mcf in the nine months ended September 30, 2024. The 2% 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 decrease in oil and condensate sales without the impact of derivatives when comparing the nine months ended September 30, 2024, to the nine months ended September 30, 2023, was due to a 6% decrease in sales volumes and a 2% decrease in realized prices. The 6% decrease in oil and condensate production was primarily due to natural declines in the SCOOP, partially offset by commencement of sales on new wells targeting the Utica liquids window.

The decrease in NGL sales without the impact of derivatives when comparing the nine months ended September 30, 2024, to the nine months ended September 30, 2023, was due to a 17% decrease in NGL sales volumes, partially offset by a 5% increase in realized prices. The 17% decrease in NGL production was primarily due to natural declines and limited 2023 development in the SCOOP. The realized price change was driven by the increase in the average Mont Belvieu NGL index from $29.83 per barrel in the nine months ended September 30, 2023, to $32.13 per barrel in the nine months ended September 30, 2024.

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

|  | Nine Months Ended September 30, 2024 | Nine Months Ended September 30, 2023 |
| --- | ---: | ---: |
| Natural gas derivatives - fair value (losses) gains | $(168,516) | $416,473 |
| Natural gas derivatives - settlement gains | 242,645 | 97,794 |
| Total gains on natural gas derivatives | 74,129 | 514,267 |
| Oil derivatives - fair value gains (losses) | 4,832 | (1,424) |
| Oil derivatives - settlement losses | (166) | (2,204) |
| Total gains (losses) on oil and condensate derivatives | 4,666 | (3,628) |
| NGL derivatives - fair value losses | (2,771) | (2,730) |
| NGL derivatives - settlement (losses) gains | (1,537) | 6,357 |
| Total (losses) gains on NGL derivatives | (4,308) | 3,627 |
| Total gains on natural gas, oil and NGL derivatives | $74,487 | $514,266 |

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 nine months ended September 30, 2024 compared to the nine months ended September 30, 2023, 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 | Nine Months Ended September 30, 2024 | Nine Months Ended September 30, 2023 | % Change |
| --- | ---: | ---: | ---: |
| Utica & Marcellus | $34,560 | $33,354 | 4% |
| SCOOP | 16,283 | 18,290 | (11)% |
| Total lease operating expenses | $50,843 | $51,644 | (2)% |
| **Lease operating expenses per Mcfe** |  |  |  |
| Utica & Marcellus | $0.15 | $0.16 | (6)% |
| SCOOP | 0.28 | 0.24 | 17% |
| Total lease operating expenses per Mcfe | $0.18 | $0.18 | (2)% |

The decrease in our total and per unit LOE for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023, was primarily the result of a decrease in water disposal activities, surface rental and labor expenses throughout our SCOOP operations and non-operated expenses in Utica/Marcellus.

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

|  | Nine Months Ended September 30, 2024 | Nine Months Ended September 30, 2023 | % Change |
| --- | ---: | ---: | ---: |
| Production taxes | $14,236 | $19,616 | (27)% |
| Property taxes | 6,326 | 4,802 | 32% |
| Other | 1,549 | 1,431 | 8% |
| Total taxes other than income | $22,111 | $25,849 | (14)% |
| Total taxes other than income per Mcfe | $0.08 | $0.09 | (15)% |

The decrease in total and per unit taxes other than income for the nine months ended September 30, 2024 compared to the nine months ended September 30, 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)

|  | Nine Months Ended September 30, 2024 | Nine Months Ended September 30, 2023 | % Change |
| --- | ---: | ---: | ---: |
| Transportation, gathering, processing and compression | $263,048 | $259,883 | 1% |
| Transportation, gathering, processing and compression per Mcfe | $0.91 | $0.91 | 1% |

Transportation, gathering, processing and compression for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023 increased in total and on a per unit basis primarily as a result of the increase in our production as noted above.

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

|  | Nine Months Ended September 30, 2024 | Nine Months Ended September 30, 2023 | % Change |
| --- | ---: | ---: | ---: |
| Depreciation, depletion and amortization of oil and gas properties | $240,279 | $237,874 | 1% |
| Depreciation, depletion and amortization of other property and equipment | 1,122 | 873 | 29% |
| Total depreciation, depletion and amortization | $241,401 | $238,747 | 1% |
| Depreciation, depletion and amortization per Mcfe | $0.84 | $0.83 | 1% |

Depreciation, depletion and amortization of our oil and gas properties for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023, increased 1% primarily as a 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 for the nine months ended September 30, 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. We did not record an impairment in the first or second quarters of 2024 or during 2023.

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

|  | Nine Months Ended September 30, 2024 | Nine Months Ended September 30, 2023 | % Change |
| --- | ---: | ---: | ---: |
| General and administrative expenses, gross | $59,921 | $53,814 | 11% |
| Reimbursed from third parties | (10,962) | (10,390) | 6% |
| Capitalized general and administrative expenses | (18,530) | (16,186) | 14% |
| General and administrative expenses, net | $30,429 | $27,238 | 12% |
| General and administrative expenses, net per Mcfe | $0.11 | $0.09 | 11% |

The increase in total and per unit general and administrative expenses for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023, was primarily driven by increases in employee compensation.

#### Restructuring costs

During the nine months ended September 30, 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)

|  | Nine Months Ended September 30, 2024 | Nine Months Ended September 30, 2023 | % Change |
| --- | ---: | ---: | ---: |
| Interest on 2026 Senior Notes | $31,014 | $33,000 | (6)% |
| Interest on 2029 Senior Notes | 2,194 | — | 100% |
| Interest expense on Credit Facility | 12,001 | 9,921 | 21% |
| Amortization of loan costs | 2,910 | 2,323 | 25% |
| Capitalized interest | (3,603) | (2,954) | 22% |
| Other | 1,511 | 112 | 1249% |
| Total interest expense | $46,027 | $42,402 | 9% |
| Interest expense per Mcfe | $0.16 | $0.15 | 8% |

Due to the tender of the 2026 Senior Notes, interest paid on the 2026 Senior Notes decreased 6% for the nine months ended September 30, 2024 compared to the nine months September 30, 2023. The Company also paid $2.2 million of interest on the 2029 Senior Notes for the nine months ended September 30, 2024. Interest expense on our Credit Facility increased 21% for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023, as a result of a higher average balance outstanding. Amortization of loan costs increased 25% for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023, as a result of the Third and Fourth Amendments to the Credit Facility which increased the elected commitments and borrowing base. The Company also capitalized $3.6 million and $3.0 million in interest expense for the nine months ended September 30, 2024 and September 30, 2023, respectively.

#### 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)

|  | Nine Months Ended September 30, 2024 | Nine Months Ended September 30, 2023 | % Change |
| --- | ---: | ---: | ---: |
| Other, net | $3,530 | $(20,492) | (117)% |

Other, net in the Company’s consolidated statements of operations for the nine months ended September 30, 2024, included approximately $3.0 million related to changes in the Company’s legal reserves for certain litigation and regulatory proceedings.

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. Additionally, 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 our Chapter 11 Cases.

#### Income Taxes

We recorded income tax expense of $3.4 million for the nine months ended September 30, 2024 compared to an income tax benefit of $554.7 million for the nine months ended September 30, 2023. See Note 14 of our consolidated financial statements for further discussion of our income tax expense.

### Liquidity and Capital Resources

*Overview*. We strive to maintain sufficient liquidity to ensure financial flexibility, withstand commodity price volatility, fund our development projects, operations and capital expenditures and return capital to shareholders. We utilize derivative contracts to reduce the financial impact of commodity price volatility and provide a level of certainty to the Company’s cash flows. We generally fund our operations, planned capital expenditures and any share repurchases with cash flow from our operating activities, cash on hand, and borrowings under our Credit Facility. Additionally, we may access debt and equity markets and sell properties to enhance our liquidity. There is no guarantee that the debt or equity capital markets will be available to us on acceptable terms or at all.

For the three and nine months ended September 30, 2024, 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 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 3 of our consolidated financial statements for further discussion of our debt obligations, including the principal and carrying amounts of our senior notes.

As of September 30, 2024, we had $3.2 million of cash and cash equivalents, $30.0 million of outstanding borrowings under our Credit Facility, $63.8 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 September 30, 2024 was $705.7 million.

As of October 28, 2024 we had $3.3 million of cash and cash equivalents, $10.0 million in borrowings under our Credit Facility, $63.8 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 results 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 and (c) extended the maturity date under the Credit Facility to September 12, 2028.

See Note 3 of our consolidated financial statements for additional discussion of our outstanding debt.

*Dividends on Preferred Stock*. As discussed in Note 4 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.

The Company paid $1.1 million and $3.3 million of cash dividends to holders of our preferred stock during the three and nine months ended September 30, 2024, respectively, and $1.1 million and $3.7 million during the three and nine months ended September 30, 2023, respectively.

*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 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 nine months ended September 30, 2024, the Company's incurred capital expenditures totaled $367.8 million, of which $277.4 million related to drilling and completion activities, $51.6 million related to maintenance leasehold and land investment and $38.8 million related to discretionary acreage acquisitions.

Our drilling and completion capital expenditures for 2024 are currently estimated to be in the range of $325 million to $335 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, 2025 and 2026. We expect this capital program to result in approximately 1,055 to 1,070 MMcfe per day of production in 2024.

Additionally, we are pursuing accretive acreage opportunities that expand our resource footprint and provide optionality to our near-term development plans and intend to allocate approximately $45 million in discretionary acreage acquisitions for 2024.

### Sources and Uses of Cash

The following table presents the major changes in cash and cash equivalents for the nine months ended September 30, 2024 and 2023 (in thousands):

|  | Nine Months Ended September 30, 2024 | Nine Months Ended September 30, 2023 |
| --- | ---: | ---: |
| Net cash provided by operating activities | $501,185 | $567,680 |
| Additions to oil and natural gas properties | (376,910) | (421,132) |
| Debt activity, net | 24,761 | (50,000) |
| Debt issuance and loan commitment fees | (14,820) | (6,965) |
| Repurchases of common stock | (103,885) | (82,757) |
| Dividends on preferred stock | (3,293) | (3,718) |
| Shares exchanged for tax withholdings | (23,606) | (3,191) |
| Other | (2,141) | 1,149 |
| Net change in cash and cash equivalents | $1,291 | $1,066 |
| Cash and cash equivalents at end of period | $3,220 | $8,325 |

*Net cash provided by operating activities.* Net cash flow provided by operating activities was $501.2 million for the nine months ended September 30, 2024, as compared to $567.7 million for the nine months ended September 30, 2023. The decrease was primarily the result of decreases in natural gas revenues.

*Additions to oil and natural gas properties.* During the nine months ended September 30, 2024, we spud 13 gross (12.7 net) operated wells and commenced sales from 16 gross (15.4 net) operated wells targeting the Utica formation for a total incurred cost of approximately $227.5 million. During the nine months ended September 30, 2024, we commenced sales from 3 gross (2.4 net) operated wells in the SCOOP for a total incurred cost of approximately $47.5 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 nine months ended September 30, 2024 and 2023, were as follows (in thousands):

| Oil and Natural Gas Property Cash Expenditures: | Nine Months Ended September 30, 2024 | Nine Months Ended September 30, 2023 |
| --- | ---: | ---: |
| Drilling and completion costs | $267,802 | $339,170 |
| Leasehold acquisitions | 89,931 | 65,845 |
| Other | 19,177 | 16,117 |
| Total oil and natural gas property expenditures | $376,910 | $421,132 |

*Debt activity, net.* In the nine months ended September 30, 2024, the Company had $737.0 million and $825.0 million 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 October 28, 2024 the Company had $10.0 million in borrowings outstanding on its Credit Facility.

*Debt issuance and loan commitment fees.* During the nine months ended September 30, 2024, the Company incurred debt issuance and loan commitment fees of $14.8 million, as compared to $7.0 million during the nine months ended September 30, 2023. The increase was primarily related to the issuance of the 2029 Senior Notes and the Fourth Amendment to the Credit Facility. See Note 3 of our consolidated financial statements for further discussion of the long-term debt activity.

*Repurchases of common stock.* During the nine months ended September 30, 2024, the Company repurchased 711,829 shares for approximately $104.4 million under the Repurchase Program at a weighted average price of $146.60 per share. For the same period in 2023, the Company repurchased 976,769 shares for $82.9 million at a weighted average price of $84.88 per share. As of October 28, 2024, we repurchased 5.2 million shares for approximately $518.7 million under the Repurchase Program at a weighted average price of $100.17 per share.

*Dividends on preferred stock.* During the nine months ended September 30, 2024, the Company paid $3.3 million of cash dividends to holders of our preferred stock compared to $3.7 million in the nine months ended September 30, 2023.

*Shares exchanged for tax withholdings.* During the nine months ended September 30, 2024, the Company paid $23.6 million of shares exchanged for tax withholdings compared to $3.2 million in the nine months ended September 30, 2023. The increase in shares traded for taxes was primarily due to the vesting of certain PSU awards as discussed in Note 6.

*Other*. During the nine months ended September 30, 2024, the Company incurred other expenses of $2.1 million, as compared to other income of $1.1 million during the nine months ended September 30, 2023. The change was primarily related to proceeds from sales of oil and gas properties of $2.6 million during the nine months ended September 30, 2023.

### 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, 2023.

### Off-balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of September 30, 2024, our material off-balance sheet arrangements and transactions include $63.8 million in letters of credit outstanding against our Credit Facility and $43.8 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 spans 2024, with approximately $5.5 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 September 30, 2024, there have been no significant changes in our critical accounting policies from those disclosed in our 2023 Annual Report on Form 10-K.

*Oil and Natural Gas Properties.* 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 commodity prices through the date of this filing and the current pricing outlook for the remainder of 2024, we may have additional ceiling test impairments of our oil and natural gas properties in subsequent quarters. 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. Full cost impairments have no impact to our cash flow or liquidity.

## Market risk

As filed, 6,992 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 September 30, 2024, 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 price collar has a set floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, the Company will cash-settle the difference with the counterparty.
- *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 September 30, 2024, we had a net asset derivative position of $73.8 million as compared to a net asset derivative position of $240.2 million as of December 31, 2023. Utilizing actual derivative contractual volumes, a 10% increase in underlying commodity prices would have decreased our asset by approximately $86.2 million, while a 10% decrease in underlying commodity prices would have increased our asset by approximately $85.9 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 September 30, 2024, we had $30.0 million outstanding borrowings under our Credit Facility which bore interest at a weighted average rate of 8.37% for the nine months ended September 30, 2024. As of September 30, 2024, we did not have any interest rate swaps to hedge interest rate risks.

## Controls and procedures

As filed, 2,315 characters.

*Evaluation of Disclosure Control and Procedures*. Under the supervision 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 September 30, 2024, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and 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 September 30, 2024, 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, 2023.

Filed Nov 6, 2024.
Source: SEC EDGAR, the filing index for accession 0001628280-24-045496. Last ingested by Listed: Nov 5, 2026, 16:36 ET. No prices; not investment advice.