# Gulfport Energy Corp: Form 10-Q for the period ended Sep 30, 2023

- Company: [Gulfport Energy Corp](/companies/gpor.md) (CIK 874499)
- Form: 10-Q
- Filed: 2023-11-01
- Accepted by EDGAR: Nov 1, 2023, 15:20 ET
- Period: 2023-09-30
- Accession: 0001628280-23-035914
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/874499/000162828023035914/gpor-20230930.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/874499/000162828023035914/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2023-09-30.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2023-07-01 to 2023-09-30 | $266.7m | us-gaap:Revenues |
| Revenue | 9 months, 2023-01-01 to 2023-09-30 | $1.30bn | us-gaap:Revenues |
| Cost of revenue | 3 months, 2023-07-01 to 2023-09-30 | $86.6m | us-gaap:CostOfRevenue |
| Cost of revenue | 9 months, 2023-01-01 to 2023-09-30 | $259.9m | us-gaap:CostOfRevenue |
| Operating income | 3 months, 2023-07-01 to 2023-09-30 | $67.2m | us-gaap:OperatingIncomeLoss |
| Operating income | 9 months, 2023-01-01 to 2023-09-30 | $692.4m | us-gaap:OperatingIncomeLoss |
| Interest expense | 3 months, 2023-07-01 to 2023-09-30 | $14.9m | us-gaap:InterestExpense |
| Interest expense | 9 months, 2023-01-01 to 2023-09-30 | $42.4m | us-gaap:InterestExpense |
| Income tax | 3 months, 2023-07-01 to 2023-09-30 | −$554.7m | us-gaap:IncomeTaxExpenseBenefit |
| Income tax | 9 months, 2023-01-01 to 2023-09-30 | −$554.7m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2023-07-01 to 2023-09-30 | $608.4m | us-gaap:NetIncomeLoss |
| Net income | 9 months, 2023-01-01 to 2023-09-30 | $1.23bn | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2023-07-01 to 2023-09-30 | $27.37 | us-gaap:EarningsPerShareDiluted |
| Diluted EPS | 9 months, 2023-01-01 to 2023-09-30 | $55.08 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2023-07-01 to 2023-09-30 | $27.72 | us-gaap:EarningsPerShareBasic |
| Basic EPS | 9 months, 2023-01-01 to 2023-09-30 | $55.72 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2023-07-01 to 2023-09-30 | 18,954,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Diluted shares (weighted) | 9 months, 2023-01-01 to 2023-09-30 | 18,937,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 9 months, 2023-01-01 to 2023-09-30 | $567.7m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Share repurchases | 9 months, 2023-01-01 to 2023-09-30 | $82.8m | us-gaap:PaymentsForRepurchaseOfCommonStock |
| Cash and equivalents | at 2023-09-30 | $8.3m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2023-09-30 | $272.3m | us-gaap:AssetsCurrent |
| Total assets | at 2023-09-30 | $3.14bn | us-gaap:Assets |
| Current liabilities | at 2023-09-30 | $374.5m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2023-09-30 | $1.11bn | us-gaap:Liabilities |
| Long-term debt | at 2023-09-30 | $644.3m | us-gaap:LongTermDebtNoncurrent |
| Current portion of debt | at 2023-09-30 | $0 | us-gaap:LongTermDebtCurrent |
| Shareholders' equity | at 2023-09-30 | $1.98bn | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 51,900 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, 2022 (“2022 Form 10-K”) and analyzes the changes in the results of operations between the periods of July 1, 2023 through September 30, 2023, January 1, 2023 through September 30, 2023, July 1, 2022 through September 30, 2022 and January 1, 2022 through September 30, 2022. 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

#### Leadership Changes

In January 2023, our CEO Tim Cutt, resigned his position as CEO. Mr. Cutt, who served as CEO and Chairman since 2021, retained his position of Chairman of the Board of Directors. Subsequent to Mr. Cutt's resignation, Gulfport named John Reinhart CEO and Director, effective January 24, 2023. In addition, Matthew Rucker joined Gulfport's leadership team as Senior Vice President of Operations.

In April 2023, Gulfport named Michael Hodges Executive Vice President and Chief Financial Officer. William Buese resigned as Executive Vice President and Chief Financial Officer of the Company on April 1, 2023. Mr. Buese remained with the Company as an adviser until his termination on May 3, 2023.

Effective August 2, 2023, Matthew B. Willrath was promoted to Vice President and Chief Accounting Officer. Prior to the promotion, Mr. Willrath served as our Vice President and Controller and has been with Gulfport Energy since February 2020.

#### Credit Facility

On May 1, 2023, the Company entered into that certain Joinder, Commitment Increase and Borrowing Base Redetermination Agreement, and Third Amendment to Credit Agreement (the “Third Amendment”) which amended the Company’s Existing Credit Facility (as amended, the “Credit Facility”). The Third Amendment, among other things, (a) increased the aggregate elected commitment amounts under the Credit Facility from $700 million to $900 million, (b) increased the borrowing base under the Credit Facility from $1 billion to $1.1 billion, (c) increased the excess cash threshold under the Credit Facility from $45 million to $75 million, and (d) extended the maturity date under the Credit Facility from October 14, 2025 to the earlier of (i) May 1, 2027 and (ii) the 91st day prior to the maturity date of the 2026 Senior Notes or any other permitted senior notes or any permitted refinancing debt under the Credit Facility having an aggregate outstanding principal amount equal to or exceeding $100 million; provided that such notes have not been refinanced, redeemed or repaid in full on or prior to such 91st day.

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

#### Common Stock Offering

On June 26, 2023, Gulfport completed an underwritten public offering of 1.5 million shares of its common stock by certain stockholders at a price to the public of $95.00 per share. Gulfport did not sell any of its common stock as part of this offering and did not receive any proceeds from the sale of the shares sold by the selling stockholders.

Concurrent with the closing of the offering, Gulfport purchased 263,158 shares of its common stock at $95.00 per share. The repurchase was part of the Company's existing Repurchase Program discussed below.

#### Share Repurchase Program

On September 20, 2023, the Company's Board of Directors approved an increase to the authorized common stock Repurchase Program from $400 million to $650 million, extending the Repurchase Program through December 31, 2024. During the three months ended September 30, 2023, the Company repurchased 76,170 shares for $8.7 million at a weighted average price of $113.97 per share. As of September 30, 2023, the Company repurchased 3.9 million shares for $333.7 million at a weighted average price of $86.07 per share since the inception of the Repurchase Program.

#### Inflation, Rising Interest Rates and Changes in Commodity Prices

The annual rate of inflation in the United States continues to be elevated as compared to historical averages. The Federal Reserve has tightened monetary policy by approving a series of increases to the Federal Funds Rate. Furthermore, the Chairman of the Federal Reserve signaled that the Federal Reserve would continue to take necessary action to bring inflation down and to ensure price stability. The inflationary environment has impacted interest rates on our Credit Facility borrowings throughout 2022 and into 2023. Interest rates on our Credit Facility borrowings have increased from a weighted average of 5.41% and 4.42% for the three and nine months ended September 30, 2022, respectively, to 8.28% and 8.05% for the three and nine months ended September 30, 2023, respectively. Additional increases in interest rates may have a negative impact on the Company’s ability to continue to execute its business strategy.

Our revenues, the value of our assets, and our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in natural gas, oil and NGL prices and the costs to produce our reserves. Natural gas, oil and NGL prices are subject to significant fluctuations that are beyond our ability to control or predict. Certain of our capital expenditures and expenses are affected by general inflation and we expect costs for 2023 to continue to be a function of supply and demand; however, we do not expect inflation to significantly impact cash flow in 2023 as a result of commitments that were entered into during 2022.

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

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

### 2023 Operational and Financial Highlights

During the third quarter of 2023, we had the following notable achievements:

- Reported total net production of 1,056.9 MMcfe per day.
- Drilled and completed Marcellus two-well pad in Belmont County, Ohio.
- Turned to sales 5 gross (4.87 net) operated wells.
- Generated $156.3 million of operating cash flows.
- Expanded the Repurchase Program authorization from $400 million to $650 million.
- Repurchased 76,170 shares for $8.7 million at a weighted average price of $113.97 per share.
- Reaffirmed the $1.1 billion borrowing base and $900 million elected commitment under our Credit Facility.

### 2023 Production and Drilling Activity

#### Production Volumes

| Natural gas (Mcf/day) | Three Months Ended September 30, 2023 | Three Months Ended September 30, 2022 |
| --- | ---: | ---: |
| Utica | 795,191 | 597,027 |
| SCOOP | 176,161 | 218,633 |
| Total | 971,352 | 815,660 |
| Oil and condensate (Bbl/day) |  |  |
| Utica | 528 | 646 |
| SCOOP | 2,667 | 3,721 |
| Total | 3,195 | 4,366 |
| NGL (Bbl/day) |  |  |
| Utica | 2,271 | 2,458 |
| SCOOP | 8,790 | 9,714 |
| Total | 11,061 | 12,172 |
| Combined (Mcfe/day) |  |  |
| Utica | 811,985 | 615,649 |
| SCOOP | 244,902 | 299,239 |
| Total | 1,056,887 | 914,888 |
| Totals may not sum or recalculate due to rounding. |  |  |

Our total net production averaged approximately 1,056.9 MMcfe per day during the three months ended September 30, 2023, as compared to 914.9 MMcfe per day during the three months ended September 30, 2022. The 16% increase in production per day is largely the result of our 2022 and 2023 development programs.

| Natural gas (Mcf/day) | Nine Months Ended September 30, 2023 | Nine Months Ended September 30, 2022 |
| --- | ---: | ---: |
| Utica | 755,372 | 664,967 |
| SCOOP | 198,616 | 200,847 |
| Total | 953,989 | 865,814 |
| Oil and condensate (Bbl/day) |  |  |
| Utica | 558 | 689 |
| SCOOP | 3,256 | 3,539 |
| Total | 3,813 | 4,228 |
| NGL (Bbl/day) |  |  |
| Utica | 2,466 | 2,252 |
| SCOOP | 9,921 | 9,275 |
| Total | 12,387 | 11,526 |
| Combined (Mcfe/day) |  |  |
| Utica | 773,512 | 682,611 |
| SCOOP | 277,676 | 277,730 |
| Total | 1,051,188 | 960,341 |
| Totals may not sum or recalculate due to rounding. |  |  |

Our total net production averaged approximately 1,051.2 MMcfe per day during the nine months ended September 30, 2023, as compared to 960.3 MMcfe per day during the nine months ended September 30, 2022. The 9% increase in production per day is largely the result of our 2022 and 2023 development programs.

*Utica*. We spud five gross (4.99 net) wells in the Utica during the three months ended September 30, 2023. In addition, we commenced sales on five gross (4.87 net) operated wells.

As of October 26, 2023, 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 September 30, 2023.

As of October 26, 2023, we did not have an operated drilling rig running in the SCOOP.

### RESULTS OF OPERATIONS

### Comparison of the Three Month Periods Ended September 30, 2023 and 2022

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

The following table summarizes our natural gas, oil and condensate and NGL production and related pricing for the three months ended September 30, 2023 as compared to the three months ended September 30, 2022. Some totals below may not sum or recalculate due to rounding.

| Natural gas sales | Three Months Ended September 30, 2023 | Three Months Ended September 30, 2022 |
| --- | ---: | ---: |
| Natural gas production volumes (MMcf) | 89,364 | 75,041 |
| Natural gas production volumes (MMcf) per day | 971 | 816 |
| Total sales | $177,401 | $585,596 |
| Average price without the impact of derivatives ($/Mcf) | $1.99 | $7.80 |
| Impact from settled derivatives ($/Mcf) | $0.54 | $(4.72) |
| **Average price, including settled derivatives ($/Mcf)** | $2.53 | $3.08 |
| **Oil and condensate sales** |  |  |
| Oil and condensate production volumes (MBbl) | 294 | 402 |
| Oil and condensate production volumes (MBbl) per day | 3 | 4 |
| Total sales | $22,896 | $36,050 |
| Average price without the impact of derivatives ($/Bbl) | $77.90 | $89.75 |
| Impact from settled derivatives ($/Bbl) | $(7.25) | $(22.49) |
| **Average price, including settled derivatives ($/Bbl)** | $70.65 | $67.26 |
| **NGL sales** |  |  |
| NGL production volumes (MBbl) | 1,018 | 1,120 |
| NGL production volumes (MBbl) per day | 11 | 12 |
| Total sales | $26,953 | $44,351 |
| Average price without the impact of derivatives ($/Bbl) | $26.49 | $39.61 |
| Impact from settled derivatives ($/Bbl) | $2.62 | $(2.53) |
| **Average price, including settled derivatives ($/Bbl)** | $29.11 | $37.08 |
| **Natural gas, oil and condensate and NGL sales** |  |  |
| Natural gas equivalents (MMcfe) | 97,234 | 84,170 |
| Natural gas equivalents (MMcfe) per day | 1,057 | 915 |
| Total sales | $227,250 | $665,997 |
| Average price without the impact of derivatives ($/Mcfe) | $2.34 | $7.91 |
| Impact from settled derivatives ($/Mcfe) | $0.50 | $(4.35) |
| **Average price, including settled derivatives ($/Mcfe)** | $2.84 | $3.56 |
| **Production Costs:** |  |  |
| Average lease operating expenses ($/Mcfe) | $0.16 | $0.18 |
| Average taxes other than income ($/Mcfe) | $0.07 | $0.20 |
| Average transportation, gathering, processing and compression ($/Mcfe) | $0.89 | $1.06 |
| Total LOE, taxes other than income and midstream costs ($/Mcfe) | $1.12 | $1.44 |

35

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

|  | Three Months Ended September 30, 2023 | Three Months Ended September 30, 2022 | % Change |
| --- | ---: | ---: | ---: |
| Natural gas | $177,401 | $585,596 | (70)% |
| Oil and condensate | 22,896 | 36,050 | (36)% |
| NGL | 26,953 | 44,351 | (39)% |
| Natural gas, oil and condensate and NGL sales | $227,250 | $665,997 | (66)% |

The decrease in natural gas sales without the impact of derivatives when comparing the three months ended September 30, 2023, to the three months ended September 30, 2022, was due to a 75% decrease in realized prices, partially offset by a 19% increase in sales volumes. The realized price change was primarily driven by the decrease in the average Henry Hub gas index from $8.20 per Mcf in the three months ended September 30, 2022, to $2.55 per Mcf during the three months ended September 30, 2023.

The decrease in oil and condensate sales without the impact of derivatives when comparing the three months ended September 30, 2023, to the three months ended September 30, 2022, was due to a 13% decrease in realized prices and a 27% decrease in sales volumes. The realized price change was primarily driven by the decrease in the average WTI crude index from $91.55 per barrel in the three months ended September 30, 2022, to $82.26 per barrel during the three months ended September 30, 2023.

The decrease in NGL sales without the impact of derivatives when comparing the three months ended September 30, 2023, to the three months ended September 30, 2022, was due to a 33% decrease in realized prices and a 9% decrease in sales volumes. The realized price change was primarily driven by the decrease in the average Mont Belvieu NGL index from $42.10 per barrel in the three months ended September 30, 2022, to $28.27 per barrel during the three months ended September 30, 2023.

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

|  | Three Months Ended September 30, 2023 | Three Months Ended September 30, 2022 |
| --- | ---: | ---: |
| Natural gas derivatives - fair value gains (losses) | $4,534 | $(161,532) |
| Natural gas derivatives - settlement gains (losses) | 48,522 | (354,084) |
| Total gains (losses) on natural gas derivatives | 53,056 | (515,616) |
| Oil derivatives - fair value (losses) gains | (8,414) | 33,545 |
| Oil derivatives - settlement losses | (2,130) | (9,035) |
| Total (losses) gains on oil and condensate derivatives | (10,544) | 24,510 |
| NGL derivatives - fair value (losses) gains | (5,763) | 19,043 |
| NGL derivatives - settlement gains (losses) | 2,668 | (2,832) |
| Total (losses) gains on NGL derivatives | (3,095) | 16,211 |
| Total gains (losses) on natural gas, oil and NGL derivatives | $39,417 | $(474,895) |

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 September 30, 2023 compared to the three months ended September 30, 2022, was primarily the result of a decrease in futures pricing for oil, natural gas, and NGLs. See Note 10 of our consolidated financial statements for hedged volumes and pricing.

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

| Lease operating expenses | Three Months Ended September 30, 2023 | Three Months Ended September 30, 2022 | % Change |
| --- | ---: | ---: | ---: |
| Utica | $10,343 | $9,977 | 4% |
| SCOOP | 5,284 | 5,386 | (2)% |
| Total lease operating expenses | $15,627 | $15,363 | 2% |
| **Lease operating expenses per Mcfe** |  |  |  |
| Utica | $0.14 | $0.18 | (22)% |
| SCOOP | 0.23 | 0.20 | 15% |
| Total lease operating expenses per Mcfe | $0.16 | $0.18 | (12)% |

The increase in our total LOE for the three months ended September 30, 2023 compared to the three months ended September 30, 2022, was primarily the result of a 16% increase in production offset by cost reductions. The decrease in per unit LOE is primarily the result of increased production and cost reductions.

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

|  | Three Months Ended September 30, 2023 | Three Months Ended September 30, 2022 | % Change |
| --- | ---: | ---: | ---: |
| Production taxes | $5,897 | $13,622 | (57)% |
| Property taxes | 1,163 | 1,526 | (24)% |
| Other | 156 | 1,381 | (89)% |
| Total taxes other than income | $7,216 | $16,529 | (56)% |
| Total taxes other than income per Mcfe | $0.07 | $0.20 | (62)% |

The decrease in total and per unit taxes other than income for the three months ended September 30, 2023 compared to the three months ended September 30, 2022, was primarily related to a decrease in production taxes resulting from the decrease in our natural gas, oil and NGL revenues excluding the impact of hedges discussed above.

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

|  | Three Months Ended September 30, 2023 | Three Months Ended September 30, 2022 | % Change |
| --- | ---: | ---: | ---: |
| Transportation, gathering, processing and compression | $86,602 | $89,234 | (3)% |
| Transportation, gathering, processing and compression per Mcfe | $0.89 | $1.06 | (16)% |

Transportation, gathering, processing and compression for the three months ended September 30, 2023 compared to the three months ended September 30, 2022 decreased on a per unit basis primarily as a result of lower minimum volume commitments as a result of our 16% increase in production.

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

|  | Three Months Ended September 30, 2023 | Three Months Ended September 30, 2022 | % Change |
| --- | ---: | ---: | ---: |
| Depreciation, depletion and amortization of oil and gas properties | $79,166 | $64,099 | 24% |
| Depreciation, depletion and amortization of other property and equipment | 339 | 320 | 6% |
| Total depreciation, depletion and amortization | $79,505 | $64,419 | 23% |
| Depreciation, depletion and amortization per Mcfe | $0.82 | $0.77 | 7% |

The increase in total and per unit depreciation, depletion and amortization of our oil and gas properties for the three months ended September 30, 2023 compared to the three months ended September 30, 2022, was primarily the result of our drilling and development activities subsequent to the third quarter of 2022.

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

|  | Three Months Ended September 30, 2023 | Three Months Ended September 30, 2022 | % Change |
| --- | ---: | ---: | ---: |
| General and administrative expenses, gross | $18,983 | $17,015 | 12% |
| Reimbursed from third parties | (3,431) | (3,339) | 3% |
| Capitalized general and administrative expenses | (5,658) | (4,924) | 15% |
| General and administrative expenses, net | $9,894 | $8,752 | 13% |
| General and administrative expenses, net per Mcfe | $0.10 | $0.10 | (2)% |

The increase in general and administrative expenses for the three months ended September 30, 2023 compared to the three months ended September 30, 2022, was primarily driven by increases in employee headcount and compensation.

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

|  | Three Months Ended September 30, 2023 | Three Months Ended September 30, 2022 | % Change |
| --- | ---: | ---: | ---: |
| Interest on 2026 Senior Notes | $11,000 | $11,053 | —% |
| Interest expense on Credit Facility | 4,088 | 3,712 | 10% |
| Amortization of loan costs | 927 | 676 | 37% |
| Capitalized interest | (1,115) | — | 100% |
| Other | 19 | 20 | (5)% |
| Total interest expense | $14,919 | $15,461 | (4)% |
| Interest expense per Mcfe | $0.15 | $0.18 | (16)% |

Interest expense on our Credit Facility increased 10% for the three months ended September 30, 2023 compared to the three months ended September 30, 2022, as a result of increased interest rates resulting from the current inflationary environment. Amortization of loan costs increased by 37% for the three months ended September 30, 2023 compared to the three months ended September 30, 2022, as a result of the Third Amendment to the Credit Facility which increased the elected commitments and borrowing base. See Note 3 of our consolidated financial statements for further details of our Credit Facility. The Company also capitalized $1.1 million in interest expense for the three months ended September 30, 2023 and did not capitalize interest expense for the three months ended September 30, 2022.

#### Income Taxes

We recorded an income tax benefit of $554.7 million for the three months ended September 30, 2023. The income tax benefit related to the partial release of the valuation allowance maintained against our net deferred tax asset position. We did not record any income tax expense for the three months ended September 30, 2022, as a result of maintaining a full valuation allowance against our net deferred tax asset. 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, 2023 and 2022

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

The following table summarizes our natural gas, oil and condensate, and NGL production and related pricing for the nine months ended September 30, 2023 as compared to the nine months ended September 30, 2022. Some totals below may not sum or recalculate due to rounding.

| Natural gas sales | Nine Months Ended September 30, 2023 | Nine Months Ended September 30, 2022 |
| --- | ---: | ---: |
| Natural gas production volumes (MMcf) | 260,439 | 236,367 |
| Natural gas production volumes (MMcf) per day | 954 | 866 |
| Total sales | $619,181 | $1,529,898 |
| Average price without the impact of derivatives ($/Mcf) | $2.38 | $6.47 |
| Impact from settled derivatives ($/Mcf) | $0.37 | $(3.19) |
| **Average price, including settled derivatives ($/Mcf)** | $2.75 | $3.28 |
| **Oil and condensate sales** |  |  |
| Oil and condensate production volumes (MBbl) | 1,041 | 1,154 |
| Oil and condensate production volumes (MBbl) per day | 4 | 4 |
| Total sales | $76,212 | $111,298 |
| Average price without the impact of derivatives ($/Bbl) | $73.21 | $96.42 |
| Impact from settled derivatives ($/Bbl) | $(2.29) | $(27.26) |
| **Average price, including settled derivatives ($/Bbl)** | $70.92 | $69.16 |
| **NGL sales** |  |  |
| NGL production volumes (MBbl) | 3,382 | 3,147 |
| NGL production volumes (MBbl) per day | 12 | 12 |
| Total sales | $92,935 | $143,741 |
| Average price without the impact of derivatives ($/Bbl) | $27.48 | $45.68 |
| Impact from settled derivatives ($/Bbl) | $1.88 | $(4.38) |
| **Average price, including settled derivatives ($/Bbl)** | $29.36 | $41.30 |
| **Natural gas, oil and condensate and NGL sales** |  |  |
| Natural gas equivalents (MMcfe) | 286,974 | 262,173 |
| Natural gas equivalents (MMcfe) per day | 1,051 | 960 |
| Total sales | $788,328 | $1,784,937 |
| Average price without the impact of derivatives ($/Mcfe) | $2.75 | $6.81 |
| Impact from settled derivatives ($/Mcfe) | $0.35 | $(3.05) |
| **Average price, including settled derivatives ($/Mcfe)** | $3.10 | $3.76 |
| **Production Costs:** |  |  |
| Average lease operating expenses ($/Mcfe) | $0.18 | $0.18 |
| Average taxes other than income ($/Mcfe) | $0.09 | $0.17 |
| Average transportation, gathering, processing and compression ($/Mcfe) | $0.91 | $1.00 |
| Total LOE, taxes other than income and midstream costs ($/Mcfe) | $1.18 | $1.35 |

39

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

|  | Nine Months Ended September 30, 2023 | Nine Months Ended September 30, 2022 | % Change |
| --- | ---: | ---: | ---: |
| Natural gas | $619,181 | $1,529,898 | (60)% |
| Oil and condensate | 76,212 | 111,298 | (32)% |
| NGL | 92,935 | 143,741 | (35)% |
| Natural gas, oil and condensate and NGL sales | $788,328 | $1,784,937 | (56)% |

The decrease in natural gas sales without the impact of derivatives when comparing the nine months ended September 30, 2023, to the nine months ended September 30, 2022, was due to a 63% decrease in realized prices, partially offset by a 10% increase in sales volumes. The realized price change was primarily driven by the decrease in the average Henry Hub gas index from $6.77 per Mcf in the nine months ended September 30, 2022, to $2.69 per Mcf in the nine months ended September 30, 2023.

The decrease in oil and condensate sales without the impact of derivatives when comparing the nine months ended September 30, 2023, to the nine months ended September 30, 2022, was due to a 24% decrease in realized prices and a 10% decrease in sales volumes. The realized price change was driven by the decrease in the average WTI crude index from $98.09 per barrel in the nine months ended September 30, 2022, to $77.39 per barrel in the nine months ended September 30, 2023.

The decrease in NGL sales without the impact of derivatives when comparing the nine months ended September 30, 2023, to the nine months ended September 30, 2022, was due to a 40% decrease in realized prices, partially offset by a 7% increase in NGL sales volumes. The realized price change was driven by the decrease in the average Mont Belvieu NGL index from $49.27 per barrel in the nine months ended September 30, 2022, to $29.83 per barrel in the nine months ended September 30, 2023.

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

|  | Nine Months Ended September 30, 2023 | Nine Months Ended September 30, 2022 |
| --- | ---: | ---: |
| Natural gas derivatives - fair value gains (losses) | $416,473 | $(659,193) |
| Natural gas derivatives - settlement gains (losses) | 97,794 | (754,177) |
| Total gains (losses) on natural gas derivatives | 514,267 | (1,413,370) |
| Oil derivatives - fair value (losses) gains | (1,424) | 8,076 |
| Oil derivatives - settlement losses | (2,204) | (31,460) |
| Total losses on oil and condensate derivatives | (3,628) | (23,384) |
| NGL derivatives - fair value (losses) gains | (2,730) | 14,216 |
| NGL derivatives - settlement gains (losses) | 6,357 | (13,779) |
| Total gains on NGL derivatives | 3,627 | 437 |
| Total gains (losses) on natural gas, oil and NGL derivatives | $514,266 | $(1,436,317) |

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, 2023 compared to the nine months ended September 30, 2022, was primarily the result of a significant decrease in futures pricing for oil, natural gas, and NGLs. See Note 10 of our consolidated financial statements for hedged volumes and pricing.

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

| Lease operating expenses | Nine Months Ended September 30, 2023 | Nine Months Ended September 30, 2022 | % Change |
| --- | ---: | ---: | ---: |
| Utica | $33,354 | $32,794 | 2% |
| SCOOP | 18,290 | 14,452 | 27% |
| Total lease operating expenses | $51,644 | $47,246 | 9% |
| **Lease operating expenses per Mcfe** |  |  |  |
| Utica | $0.16 | $0.18 | (11)% |
| SCOOP | 0.24 | 0.19 | 26% |
| Total lease operating expenses per Mcfe | $0.18 | $0.18 | —% |

The increase in total LOE for the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022, was primarily the result of a 9% increase in production. LOE per unit for the nine months ended September 30, 2023 was consistent with the nine months ended September 30, 2022.

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

|  | Nine Months Ended September 30, 2023 | Nine Months Ended September 30, 2022 | % Change |
| --- | ---: | ---: | ---: |
| Production taxes | $19,616 | $36,714 | (47)% |
| Property taxes | 4,802 | 5,311 | (10)% |
| Other | 1,431 | 3,654 | (61)% |
| Total taxes other than income | $25,849 | $45,679 | (43)% |
| Total taxes other than income per Mcfe | $0.09 | $0.17 | (48)% |

The decrease in total and per unit taxes other than income for the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022, was primarily related to a decrease in production taxes resulting from the decrease in our natural gas, oil and NGL revenues excluding the impact of hedges discussed above.

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

|  | Nine Months Ended September 30, 2023 | Nine Months Ended September 30, 2022 | % Change |
| --- | ---: | ---: | ---: |
| Transportation, gathering, processing and compression | $259,883 | $261,778 | (1)% |
| Transportation, gathering, processing and compression per Mcfe | $0.91 | $1.00 | (9)% |

Transportation, gathering, processing and compression for the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022 decreased on a per unit basis primarily as a result of lower minimum volume commitments as a result of our 9% increase in production.

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

|  | Nine Months Ended September 30, 2023 | Nine Months Ended September 30, 2022 | % Change |
| --- | ---: | ---: | ---: |
| Depreciation, depletion and amortization of oil and gas properties | $237,874 | $188,324 | 26% |
| Depreciation, depletion and amortization of other property and equipment | 873 | 981 | (11)% |
| Total depreciation, depletion and amortization | $238,747 | $189,305 | 26% |
| Depreciation, depletion and amortization per Mcfe | $0.83 | $0.72 | 15% |

The increase in total and per unit depreciation, depletion and amortization of our oil and gas properties for the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022, was primarily the result of our drilling and development activities subsequent to the third quarter of 2022.

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

|  | Nine Months Ended September 30, 2023 | Nine Months Ended September 30, 2022 | % Change |
| --- | ---: | ---: | ---: |
| General and administrative expenses, gross | $53,814 | $48,630 | 11% |
| Reimbursed from third parties | (10,390) | (9,874) | 5% |
| Capitalized general and administrative expenses | (16,186) | (14,628) | 11% |
| General and administrative expenses, net | $27,238 | $24,128 | 13% |
| General and administrative expenses, net per Mcfe | $0.09 | $0.09 | 3% |

The increase in total general and administrative expenses for the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022, was primarily driven by increases in employee headcount and compensation as well as legal expenses related to the continued administration of our Chapter 11 filing and settlement of firm transportation agreement as noted in Note 9 of our consolidated financial statements.

#### Restructuring Costs

During the first and second quarters of 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. There are no remaining employee termination liabilities for the impacted employees.

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

|  | Nine Months Ended September 30, 2023 | Nine Months Ended September 30, 2022 | % Change |
| --- | ---: | ---: | ---: |
| Interest on 2026 Senior Notes | $33,000 | $33,155 | —% |
| Interest expense on Credit Facility | 9,921 | 8,476 | 17% |
| Amortization of loan costs | 2,323 | 2,009 | 16% |
| Capitalized interest | (2,954) | — | 100% |
| Other | 112 | 39 | 187% |
| Total interest expense | $42,402 | $43,679 | (3)% |
| Interest expense per Mcfe | $0.15 | $0.17 | (11)% |

Interest expense on our Credit Facility increased 17% for the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022, as a result of increased interest rates resulting from the current inflationary environment. The Company also capitalized $3.0 million in interest expense for the nine months ended September 30, 2023 and did not capitalize interest expense for the nine months ended September 30, 2022.

#### Other, net (in thousands)

|  | Nine Months Ended September 30, 2023 | Nine Months Ended September 30, 2022 | % Change |
| --- | ---: | ---: | ---: |
| Other, net | $(20,492) | $(11,385) | 80% |

Other, net in the Company's consolidated statements of operations for the nine months ended September 30, 2023, included $17.8 million related to the interim TC claim distribution and a $1 million administrative payment to Rover as part of the executed settlement. The distribution and settlement is more fully described in Note 9 of our consolidated financial statements. The timing and amount of any future distributions to Gulfport are not certain, and the total amount will be impacted by the liquidating trust's distributions and resolution of other remaining bankruptcy claims. Additionally, Other, net included a $5.0 million recoupment of previously placed collateral for certain firm transportation commitments during our Chapter 11 filing.

Other, net in the Company's consolidated statements of operations for the nine months ended September 30, 2022, included $11.5 million related to the initial TC claim distribution as discussed in Note 9 of our consolidated financial statements. Additionally, Other, net included a $5.1 million payment to settle certain gas imbalance positions and a $5.2 million receipt of funds from a litigation settlement.

#### Income Taxes

We recorded an income tax benefit of $554.7 million for the nine months ended September 30, 2023. The income tax benefit related to the partial release of the valuation allowance maintained against our net deferred tax asset position. We did not record any income tax expense for the nine months ended September 30, 2022, as a result of maintaining a full valuation allowance against our net deferred tax asset. 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 and nine months ended September 30, 2023, our primary sources of capital resources and liquidity have consisted of internally generated cash flows from operations, and our primary uses of cash have been for development of our oil and natural gas properties and share repurchases.

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, 2023, we had $8.3 million of cash and cash equivalents, $95.0 million of borrowings under our Credit Facility, $66.9 million of letters of credit outstanding, and $550 million of outstanding 2026 Senior Notes. Our total principal amount of funded debt as of September 30, 2023 was $645.0 million.

As of October 26, 2023 we had $8.8 million of cash and cash equivalents, $59.0 million in borrowings under our Credit Facility, $60.9 million of letters of credit outstanding, and $550 million of outstanding 2026 Senior Notes.

*Debt.* On May 2, 2022, the Company completed its semi-annual borrowing base redetermination and entered into the Amendment to Borrowing Base Redetermination Agreement and First Amendment to our Credit Agreement, which amended the Existing Credit Facility. The amendment, among other things, (a) increased the borrowing base under the Credit Facility from $850 million to $1.0 billion with elected commitments remaining at $700 million, (b) amended certain covenants related to hedging to ease certain requirements and limitations and (c) amended the covenants governing restricted payments to (i) increase the Net Leverage Ratio allowing unlimited restricted payments from 1.00 to 1.00 to 1.25 to 1.00 and (ii) permit additional restricted payments to redeem preferred equity until December 31, 2022 provided certain leverage, no event of default or borrowing base deficiency and availability tests are met and (d) provided for the transition from a LIBOR to a SOFR benchmark, with a 10 basis point credit spread adjustment for all tenors.

On October 31, 2022, the Company completed its semi-annual borrowing base redetermination and entered into the Borrowing Base Reaffirmation Agreement and Second Amendment to our Credit Agreement, which amended the Existing Credit Facility. The amendment, among other things, reaffirmed the borrowing base under the Credit Facility at $1.0 billion and the elected commitments at $700 million.

On May 1, 2023, the Company entered into that certain Joinder, Commitment Increase and Borrowing Base Redetermination Agreement, and Third Amendment to Credit Agreement (the “Third Amendment”) which amended the Company’s Existing Credit Facility (as amended, the “Credit Facility”). The Third Amendment, among other things, (a) increased the aggregate elected commitment amounts under the Credit Facility from $700 million to $900 million, (b) increased the borrowing base under the Credit Facility from $1 billion to $1.1 billion, (c) increased the excess cash threshold under the Credit Facility from $45 million to $75 million, and (d) extended the maturity date under the Credit Facility from October 14, 2025 to the earlier of (i) May 1, 2027 and (ii) the 91st day prior to the maturity date of the 2026 Senior Notes or any other permitted senior notes or any permitted refinancing debt under the Credit Facility having an aggregate outstanding principal amount equal to or exceeding $100 million; provided that such notes have not been refinanced, redeemed or repaid in full on or prior to such 91st day.

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

Additionally, on the Emergence Date, pursuant to the terms of the Plan, we issued our 2026 Senior Notes. The 2026 Senior Notes are guaranteed on a senior unsecured basis by each of the Company's subsidiaries that guarantee the Credit Facility.

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

*Preferred Dividends*. As discussed in Note 4 of our consolidated financial statements, holders of preferred stock are entitled to 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 and nine months ended September 30, 2023, the Company paid $1.1 million and $3.7 million, respectively, of cash dividends to holders of our preferred stock compared to $1.3 million and $4.1 million in the three and nine months ended September 30, 2022, 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, 2023, the Company's incurred capital expenditures totaled $385.5 million, of which $319.2 million related to drilling and completion activities, $41.4 million related to maintenance leasehold and land investment and $24.9 million related to discretionary acreage acquisitions.

Our drilling and completion capital expenditures for 2023 are currently estimated to be in the range of $385 million to $395 million. Also, we currently expect to spend approximately $50 million to $60 million in 2023 for maintenance leasehold and land investment, which is focused on near-term drilling programs and facilitating increases in our working interests and lateral footage in units we plan to drill in 2023 and 2024. We expect this capital program to result in approximately 1,045 to 1,055 MMcfe per day of production in 2023.

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

### Sources and Uses of Cash

The following table presents the major changes in cash and cash equivalents for the nine months ended September 30, 2023 and 2022 (in thousands):

|  | Nine Months Ended September 30, 2023 | Nine Months Ended September 30, 2022 |
| --- | ---: | ---: |
| Net cash provided by operating activities | $567,680 | $551,082 |
| Additions to oil and natural gas properties | (421,132) | (331,994) |
| Debt activity, net | (50,000) | 15,000 |
| Repurchases of common stock | (82,757) | (225,791) |
| Preferred stock dividends | (3,718) | (4,136) |
| Other | (9,007) | 866 |
| Net change in cash and cash equivalents | $1,066 | $5,027 |
| Cash and cash equivalents at end of period | $8,325 | $8,287 |

*Net cash provided by operating activities.* Net cash flow provided by operating activities was $567.7 million for the nine months ended September 30, 2023, as compared to $551.1 million for the nine months ended September 30, 2022. The increase was primarily the result of a decrease in cash payments from settled derivative instruments due to decreased realized commodities pricing.

*Additions to oil and natural gas properties.* During the nine months ended September 30, 2023, we spud 13 gross (12.0 net) operated wells and commenced sales from 16 gross (15.0 net) operated wells in the Utica for a total incurred cost of approximately $282.0 million. During the nine months ended September 30, 2023, we spud and commenced sales from two gross (1.7 net) operated wells in the SCOOP for a total incurred cost of approximately $32.0 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, 2023 and 2022, were as follows (in thousands):

| Oil and Natural Gas Property Cash Expenditures: | Nine Months Ended September 30, 2023 | Nine Months Ended September 30, 2022 |
| --- | ---: | ---: |
| Drilling and completion costs | $339,170 | $291,926 |
| Leasehold acquisitions | 65,845 | 27,086 |
| Other | 16,117 | 12,982 |
| Total oil and natural gas property expenditures | $421,132 | $331,994 |

*Debt activity, net.* In the nine months ended September 30, 2023, the Company had $698.0 million and $748.0 million in borrowings and repayments, respectively, on its Credit Facility. As of October 26, 2023 the Company had $59.0 million in borrowings outstanding on its Credit Facility.

*Repurchases of common stock.* During the nine months ended September 30, 2023, the Company repurchased 976,769 shares for approximately $82.9 million under the Repurchase Program at a weighted average price of $84.88 per share. For the same period in 2022, the Company repurchased 2,607,059 shares for $227.6 million at a weighted average price of $87.29 per share. As of October 26, 2023, we repurchased 3.9 million shares for approximately $334.6 million under the Repurchase Program at a weighted average price of $86.14 per share.

*Preferred stock dividends.* During the nine months ended September 30, 2023, the Company paid $3.7 million of cash dividends to holders of our preferred stock compared to $4.1 million in the nine months ended September 30, 2022.

*Other*. During the nine months ended September 30, 2023, the Company paid other expenses of $9.0 million, as compared to other expenses of $0.9 million paid during the nine months ended September 30, 2022. The increase was primarily related to a $6.8 million increase in debt issuance costs as a result of the Third Amendment to the Credit Facility which increased the commitment and redetermined its borrowing base, as discussed in Note 3 of our consolidated financial statements.

### 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, 2022.

### 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, 2023, our material off-balance sheet arrangements and transactions include $66.9 million in letters of credit outstanding against our Credit Facility and $37.5 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 2023 and 2024, with approximately $19.8 million remaining in 2023 and $23.5 million for 2024. 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, 2023, there have been no significant changes in our critical accounting policies from those disclosed in our 2022 Annual Report on Form 10-K.

## Market risk

As filed, 7,006 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, 2023, 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, 2023, we had a net asset derivative position of $64.4 million as compared to a net liability derivative position of $347.9 million as of December 31, 2022. Utilizing actual derivative contractual volumes, a 10% increase in underlying commodity prices would have increased our liability by approximately $112.8 million, while a 10% decrease in underlying commodity prices would have decreased our liability by approximately $109.5 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, 2023, we had $95.0 million outstanding borrowings under our Credit Facility which bore interest at a weighted average rate of 8.05% for the nine months ended September 30, 2023. As of September 30, 2023, 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, 2023, 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, 2023, our disclosure controls and procedures are effective.

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

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

## 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, 2022.

Filed Nov 1, 2023.
Source: SEC EDGAR, the filing index for accession 0001628280-23-035914. Last ingested by Listed: Nov 4, 2026, 17:24 ET. No prices; not investment advice.