GULFPORT ENERGY CORP (GPOR) FY 2024 MD&A
This page reproduces the company's own Item 7 MD&A text from the linked SEC filing. It is filer text, not grepcent analysis, scoring, or investment advice.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis represents management’s perspective of our business, financial condition and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future and should be read in conjunction with “Item 8. Financial Statements and Supplementary Data” of this report. The following information updates the discussion of Gulfport's financial condition provided in its 2023 Annual Report on Form 10-K filing and compares the results of operations for the year ended December 31, 2024 to the year ended December 31, 2023. Discussions of our results from 2022 to 2023 that are not included in this Form 10-K can be found in “Management's Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2023.
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Overview
Gulfport is an independent natural gas-weighted exploration and production company with assets primarily located in the Appalachia and Anadarko basins. Our principal properties are located in eastern Ohio targeting the Utica and Marcellus and in central Oklahoma targeting the SCOOP Woodford and Springer formations. Our strategy is to develop our assets in a safe, environmentally responsible manner, while generating sustainable cash flow, improving margins and operating efficiencies and returning capital to shareholders. To accomplish these goals, we generally allocate capital to projects we believe offer the highest rate of return and we deploy leading drilling and completion techniques and technologies in our development efforts.
Recent Developments
Long-Term Debt and Credit Facility
In September 2024, Gulfport Operating purchased approximately 95%, or $524.3 million of the 2026 Senior Notes in a tender offer using the net proceeds received from the issuance of $650 million of its 2029 Senior Notes. The net impact of these transactions resulted in the Company extending the maturity of substantially all of the senior notes from 2026 to 2029.
Additionally, on September 12, 2024, the Company entered into the Commitment Increase, Borrowing Base Reaffirmation Agreement, and Fourth Amendment to Credit Agreement (the “Fourth Amendment”), which amended the Company’s Third Amended and Restated Credit Agreement. The Fourth Amendment, among other things, (a) increased the aggregate elected commitment amounts under the Credit Facility to $1.0 billion, (b) reaffirmed the borrowing base under the Credit Facility at $1.1 billion, (c) extended the maturity date under the Credit Facility to September 12, 2028, and (d) reduced the pricing grid 50 bps.
Stock Repurchase Program
On November 4, 2024, the Company's Board of Directors approved an increase to the authorized Repurchase Program from $650.0 million to $1.0 billion and extended the authorization through December 31, 2025. During the year ended December 31, 2024, the Company repurchased 1.2 million shares for $184.5 million at a weighted average price of $153.35 per share. As of December 31, 2024, the Company repurchased 5.6 million shares for $584.1 million at a weighted average price of $104.88 per share since the inception of the Repurchase Program.
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2024 Operational and Financial Highlights
During 2024, we had the following notable achievements:
•Reported total net production of 1,054 MMcfe per day.
•Generated $650.0 million of operating cash flows.
•Turned to sales 19 gross operated (17.8 net) wells.
•Expanded common share repurchase program to $1.0 billion and returned $184.5 million to shareholders through the repurchase of 1.2 million shares at a weighted average price of $153.35 per share.
•Extended the maturity of substantially all long-term senior notes from 2026 to 2029.
•Extended the maturity of the Credit Facility to 2028 and increased the available commitments under the Credit Facility by $100 million.
•Exited the year with total liquidity of $899.7 million.
•Achieved MIQ certification for all Appalachian assets for the second consecutive year.
•Reported year-end estimated net proved reserves of 4.0 Tcfe.
Business and Industry Outlook
The Company's primary focus going into 2025 is its continued attention on reducing cycle times and operating costs to improve margins and ultimately support our expected free cash flow generation. We are committed to an emphasis on sustainability and we will continue to prioritize safety, environmental stewardship, and maintaining strong relationships with the communities in which we operate. Throughout the year, we plan to maintain capital discipline, prioritizing free cash flow generation and preserving our strong financial position, while returning capital to shareholders and increasing our resource depth through incremental leasehold opportunities.
In 2024, natural gas prices continued to be volatile as spot prices ranged from $1.21 to $13.20 per MMBtu. Henry Hub averaged $2.19 per MMBtu in 2024 vs $2.53 per MMBtu in 2023. As we look into 2025, we expect continued volatility in natural gas prices. To mitigate our exposure to commodity market volatility and to help provide a level of certainty around our financial strength, we have entered into a combination of natural gas swaps and collars, representing approximately 46% of our expected 2025 production, at an average floor price of $3.59 per Mcf.
Our 2025 capital expenditure program is expected to be in a range of $370 million to $395 million.
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Results of Operations
Comparison of the Year Ended December 31, 2024 and 2023
We reported net loss of $261.4 million for the year ended December 31, 2024, compared to a net income of $1.5 billion for the year ended December 31, 2023. The material changes that led to the decrease in net loss are further discussed by category on the following pages. Some totals and changes throughout the below section may not sum or recalculate due to rounding.
Natural Gas, Oil and Condensate and NGL Production and Pricing (sales totals in thousands)
| Year Ended December 31, 2024 | Year Ended December 31, 2023 | |||||
|---|---|---|---|---|---|---|
| Natural gas (MMcf/day) | ||||||
| Utica & Marcellus production volumes | 810 | 766 | ||||
| SCOOP production volumes | 157 | 194 | ||||
| Total production volumes | 968 | 960 | ||||
| Total sales | $ | 714,160 | $ | 831,812 | ||
| Average price without the impact of derivatives ($/Mcf) | $ | 2.02 | $ | 2.37 | ||
| Impact from settled derivatives ($/Mcf) | $ | 0.80 | $ | 0.42 | ||
| Average price, including settled derivatives ($/Mcf) | $ | 2.82 | $ | 2.79 | ||
| Oil and condensate (MBbl/day) | ||||||
| Utica & Marcellus production volumes | 2 | 1 | ||||
| SCOOP production volumes | 2 | 3 | ||||
| Total production volumes | 4 | 4 | ||||
| Total sales | $ | 101,589 | $ | 99,854 | ||
| Average price without the impact of derivatives ($/Bbl) | $ | 69.64 | $ | 73.27 | ||
| Impact from settled derivatives ($/Bbl) | $ | 0.11 | $ | (2.53) | ||
| Average price, including settled derivatives ($/Bbl) | $ | 69.75 | $ | 70.74 | ||
| NGL (MBbl/day) | ||||||
| Utica & Marcellus production volumes | 3 | 2 | ||||
| SCOOP production volumes | 8 | 10 | ||||
| Total production volumes | 10 | 12 | ||||
| Total sales | $ | 112,855 | $ | 119,717 | ||
| Average price without the impact of derivatives ($/Bbl) | $ | 29.56 | $ | 27.29 | ||
| Impact from settled derivatives ($/Bbl) | $ | (0.56) | $ | 2.07 | ||
| Average price, including settled derivatives ($/Bbl) | $ | 29.00 | $ | 29.36 | ||
| Total (MMcfe/day) | ||||||
| Utica & Marcellus production volumes | 842 | 784 | ||||
| SCOOP production volumes | 212 | 270 | ||||
| Total production volumes | 1,054 | 1,054 | ||||
| Total sales | $ | 928,604 | $ | 1,051,383 | ||
| Average price without the impact of derivatives ($/Mcfe) | $ | 2.41 | $ | 2.73 | ||
| Impact from settled derivatives ($/Mcfe) | $ | 0.73 | $ | 0.40 | ||
| Average price, including settled derivatives ($/Mcfe) | $ | 3.14 | $ | 3.13 |
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| Year Ended December 31, 2024 | Year Ended December 31, 2023 | % Change | ||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| Natural gas | $ | 714,160 | $ | 831,812 | (14) | % | ||||
| Oil and condensate | 101,589 | 99,854 | 2 | % | ||||||
| NGL | 112,855 | 119,717 | (6) | % | ||||||
| Total natural gas, oil and condensate and NGL sales | $ | 928,604 | $ | 1,051,383 | (12) | % |
The decrease in natural gas sales without the impact of derivatives when comparing the year ended December 31, 2024, to the year ended December 31, 2023, was primarily due to a 15% decrease in realized natural gas prices, partially offset by a 1% increase in sales volumes. The realized price change was primarily driven by the decrease in the average Henry Hub gas index from $2.74 per Mcf in the year ended December 31, 2023, to $2.27 per Mcf during the year ended December 31, 2024. The 1% increase in natural gas production was primarily due to our 2023 and 2024 development programs in the Utica/Marcellus partially offset by natural declines and limited activity in the SCOOP.
The increase in oil and condensate sales without the impact of derivatives when comparing the year ended December 31, 2024, to the year ended December 31, 2023, was due to a 7% increase in sales volumes, partially offset by a 5% decrease in realized oil prices. The 7% increase in oil and condensate production was primarily due to commencement of sales on new wells targeting the Utica liquids window. The realized price change was primarily driven by the decrease in the average WTI crude index from $77.62 per barrel in the year ended December 31, 2023, to $75.72 per barrel during the year ended December 31, 2024.
The decrease in NGL sales without the impact of derivatives when comparing the year ended December 31, 2024, to the year ended December 31, 2023, was due to a 13% decrease in NGL sales volumes, partially offset by an 8% increase in realized prices. The 13% decrease in NGL production was primarily due to natural declines and limited 2023 development in the SCOOP. The realized price change was primarily driven by the increase in the average Mont Belvieu NGL index from $30.07 per barrel in the year ended December 31, 2023, to $32.73 per barrel during the year ended December 31, 2024.
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Natural Gas, Oil and NGL Derivatives (in thousands)
The total natural gas, oil and NGL volumes hedged for the year ended December 31, 2024 and 2023, represented approximately 80% and 95%, respectively, of our total sales volumes for the applicable year.
| Year Ended December 31, 2024 | Year Ended December 31, 2023 | |||||
|---|---|---|---|---|---|---|
| Natural gas derivatives - fair value (losses) gains | $ | (251,019) | $ | 584,563 | ||
| Natural gas derivatives - settlement gains | 284,626 | 146,381 | ||||
| Total gains on natural gas derivatives | 33,607 | 730,944 | ||||
| Oil and condensate derivatives - fair value gains | 2,351 | 5,971 | ||||
| Oil and condensate derivatives - settlement gains (losses) | 166 | (3,272) | ||||
| Total gains on oil and condensate derivatives | 2,517 | 2,699 | ||||
| NGL derivatives - fair value losses | (4,442) | (2,414) | ||||
| NGL derivatives - settlement (losses) gains | (2,155) | 9,090 | ||||
| Total (losses) gains on NGL derivatives | (6,597) | 6,676 | ||||
| Total gains on natural gas, oil and NGL derivatives | $ | 29,527 | $ | 740,319 |
We recognize fair value changes on our natural gas, oil and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationship between contract prices and the associated forward curves. The significant change in the total gain for the year ended December 31, 2024 compared to the year ended December 31, 2023, was primarily the result of changes in futures pricing for oil, natural gas, and NGLs during each period. The fair value losses of our hedging program totaled $253.1 million for the year ended December 31, 2024 compared to gains of $588.1 million for the year ended December 31, 2023. Settlement gains (losses) in the table above represent realized cash gains or losses to the instruments described in Note 12 of our consolidated financial statements. Our hedging program generated cash receipts of $282.6 million for the year ended December 31, 2024, compared to cash receipts of $152.2 million for the year ended December 31, 2023.
Lease Operating Expenses (in thousands, except per unit)
| Year Ended December 31, 2024 | Year Ended December 31, 2023 | % Change | ||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| Lease operating expenses | ||||||||||
| Utica & Marcellus | $ | 48,321 | $ | 44,394 | 9 | % | ||||
| SCOOP | 21,791 | 24,254 | (10) | % | ||||||
| Total lease operating expenses | $ | 70,112 | $ | 68,648 | 2 | % | ||||
| Lease operating expenses per Mcfe | ||||||||||
| Utica & Marcellus | $ | 0.16 | $ | 0.16 | — | % | ||||
| SCOOP | 0.28 | 0.25 | 12 | % | ||||||
| Total lease operating expenses per Mcfe | $ | 0.18 | $ | 0.18 | — | % |
The increase in total LOE for the year ended December 31, 2024, compared to the year ended December 31, 2023, was primarily the result of increased production in Utica/Marcellus as described above.
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Taxes Other Than Income (in thousands, except per unit)
| Year Ended December 31, 2024 | Year Ended December 31, 2023 | % Change | ||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| Production taxes | $ | 19,385 | $ | 25,564 | (24) | % | ||||
| Property taxes | 8,174 | 6,160 | 33 | % | ||||||
| Other | 2,178 | 1,993 | 9 | % | ||||||
| Total taxes other than income | $ | 29,737 | $ | 33,717 | (12) | % | ||||
| Total taxes other than income per Mcfe | $ | 0.08 | $ | 0.09 | (11) | % |
The decrease in total and per unit taxes other than income for the year ended December 31, 2024, compared to the year ended December 31, 2023, was primarily related to a decrease in production taxes resulting from the decrease in our natural gas, oil and NGL revenues excluding the impact of hedges discussed above.
Transportation, Gathering, Processing and Compression (in thousands, except per unit)
| Year Ended December 31, 2024 | Year Ended December 31, 2023 | % Change | ||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| Transportation, gathering, processing and compression | $ | 351,237 | $ | 348,631 | 1 | % | ||||
| Transportation, gathering, processing and compression per Mcfe | $ | 0.91 | $ | 0.91 | — | % |
Transportation, gathering, processing and compression for the year ended December 31, 2024, compared to the year ended December 31, 2023, increased in total primarily as a result of our small increase in production.
Depreciation, Depletion and Amortization (in thousands, except per unit)
| Year Ended December 31, 2024 | Year Ended December 31, 2023 | % Change | ||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| Depreciation, depletion and amortization of oil and gas properties | $ | 324,078 | $ | 318,473 | 2 | % | ||||
| Depreciation, depletion and amortization of other property and equipment | 1,645 | 1,242 | 32 | % | ||||||
| Total depreciation, depletion and amortization | $ | 325,723 | $ | 319,715 | 2 | % | ||||
| Total depreciation, depletion and amortization per Mcfe | $ | 0.84 | $ | 0.83 | 1 | % |
Depreciation, depletion and amortization of our oil and gas properties for the year ended December 31, 2024, compared to the year ended December 31, 2023, increased 2% primarily the result of our drilling and development activities during 2023 and 2024.
Impairment of Oil and Natural Gas Properties
At September 30, 2024, the net book value of our oil and gas properties exceeded the calculated ceiling. As a result, we recorded a non-cash ceiling test impairment of $30.5 million in the third quarter of 2024. The impairment resulted from declines in the full cost ceiling, which primarily resulted from the significant decrease in the 12-month average trailing price for natural gas. The 12-month average trailing price for natural gas in the third quarter of 2024 was $2.21 per MMBtu.
At December 31, 2024, the net book value of our oil and gas properties exceeded the calculated ceiling. As a result, we recorded a non-cash ceiling test impairment of $342.7 million in the fourth quarter of 2024. The impairment resulted from declines in the full cost ceiling, which primarily resulted from the significant decrease in the 12-month average trailing price for natural gas. The 12-month average trailing price for natural gas in the fourth quarter of 2024 was $2.13 per MMBtu.
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Lower natural gas, oil and NGL prices can reduce the value of our assets. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine the actual ceiling test calculation and impairment analysis in future periods. Given the decline of natural gas prices through December 2024, we may have additional ceiling test impairments of our oil and natural gas properties in subsequent quarters if the 12-month average trailing price does not improve from the $2.13 per MMBtu utilized in the fourth quarter 2024 ceiling test. Any such ceiling test impairment could be material to our net earnings; however, given the inter-relationship of the various judgements made to estimate proved reserves, it is impractical to estimate the potential changes in these estimates and their impact on the impairment.
We did not record an impairment during any quarter in 2023.
General and Administrative Expenses (in thousands, except per unit)
| Year Ended December 31, 2024 | Year Ended December 31, 2023 | % Change | ||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| General and administrative expenses, gross | $ | 82,478 | $ | 75,180 | 10 | % | ||||
| Reimbursed from third parties | (14,582) | (13,770) | 6 | % | ||||||
| Capitalized general and administrative expenses | (25,338) | (22,810) | 11 | % | ||||||
| General and administrative expenses, net | $ | 42,558 | $ | 38,600 | 10 | % | ||||
| General and administrative expenses, net per Mcfe | $ | 0.11 | $ | 0.10 | 10 | % |
The increase in total and per unit general and administrative expenses for the year ended December 31, 2024, compared to the year ended December 31, 2023, was primarily driven by increases in employee compensation and headcount.
Restructuring Costs
During the year ended December 31, 2023, Gulfport recognized $4.8 million in personnel-related restructuring expenses associated with changes in the organizational structure and leadership team resulting from the appointment of Gulfport's new CEO in January 2023. Of these expenses, $1.3 million resulted from accelerated vesting of share-based grants, which are non-cash charges. The organizational changes were completed in the second quarter of 2023 and there are no remaining employee termination liabilities associated with these changes.
Interest Expense (in thousands, except per unit)
| Year Ended December 31, 2024 | Year Ended December 31, 2023 | % Change | ||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| Interest on 2026 Senior Notes | $ | 31,417 | $ | 44,000 | (29) | % | ||||
| Interest on 2029 Senior Notes | 13,163 | — | 100 | % | ||||||
| Interest on Credit Facility | 14,143 | 13,810 | 2 | % | ||||||
| Amortization of loan costs | 4,208 | 3,256 | 29 | % | ||||||
| Capitalized interest | (4,771) | (4,147) | 15 | % | ||||||
| Other | 1,822 | 150 | 1115 | % | ||||||
| Total interest expense | $ | 59,982 | $ | 57,069 | 5 | % | ||||
| Interest expense per Mcfe | $ | 0.16 | $ | 0.15 | 7 | % |
Due to the tender offer for the 2026 Senior Notes in the third quarter of 2024 described below, interest paid on the 2026 Senior Notes decreased 29% for the year ended December 31, 2024, compared to the year ended December 31, 2023. The Company also paid $13.2 million of interest on the 2029 Senior Notes for the year ended December 31, 2024. Interest expense on our Credit Facility increased 2% for the year ended December 31, 2024, compared to the year ended December 31, 2023, as a result of a higher average balance outstanding. Amortization of loan costs increased 29% for the year ended December 31, 2024, compared to the year ended December 31, 2023, as a result of the Third Amendment to the Credit Facility which increased the elected commitments and borrowing base and the Fourth Amendment to the Credit Facility which increased the elected commitments. The Company also capitalized $4.8 million and $4.1 million in interest expense for the years ended December 31, 2024 and 2023, respectively.
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Loss on Debt Extinguishment
In September 2024, Gulfport Operating purchased and retired $524.3 million of the 2026 Senior Notes in a tender offer using net proceeds from the 2029 Senior Notes offering. The 2026 Senior Notes were tendered at an average price equal to 102.3% of the principal amount. The retirement of the 2026 Senior Notes resulted in a loss on debt extinguishment of $13.4 million, which included cash costs of $12.9 million.
Other, net (in thousands)
| Year Ended December 31, 2024 | Year Ended December 31, 2023 | % Change | ||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| Other, net | $ | 7,336 | $ | (27,982) | (126) | % |
Other, net in the Company's consolidated statements of operations for the year ended December 31, 2024, included approximately $4.9 million related to changes in the Company's legal reserves for certain litigation and regulatory proceedings. Additionally, Other, net included approximately $1.9 million write-down of certain of its pipe inventory that the Company does not expect to utilize in its drilling and completion activities.
As part of its Chapter 11 Cases and restructuring efforts, the Company filed motions to reject certain firm transportation agreements between the Company and affiliates of TC Energy Corporation (“TC”) and Rover Pipeline LLC (“Rover”). During the first quarter of 2023, Gulfport finalized a settlement agreement with Rover that was approved by the Bankruptcy Court on February 21, 2023. Pursuant to the settlement agreement, Gulfport and Rover agreed that the firm transportation contracts between them would be rejected. As part of the settlement, Gulfport paid a $1.0 million administrative claim, which is included in Other, net. On February 24, 2023, Gulfport received an additional $17.8 million interim distribution for its TC claim, which is also included in Other, net. Other, net in the second quarter of 2023 included a $5.0 million recoupment of previously placed collateral for certain firm transportation commitments during the Company's Chapter 11 Cases. Additionally, in the fourth quarter of 2023, Gulfport received an additional $8.3 million distribution related to its TC claim.
Income Taxes (in thousands)
For the year ended December 31, 2024, we had an effective tax rate of 18% and an income tax benefit of $56.1 million. For the year ended December 31, 2023, the Company's effective tax rate was (56)% and an income tax benefit of $525.2 million. The higher effective tax rate for the year ended December 31, 2024 is primarily related to the valuation allowance the Company released during the third quarter of 2023. See Note 10 of our consolidated financial statements for further discussion of our income tax benefit.
Liquidity and Capital Resources
Overview. We strive to maintain sufficient liquidity to ensure financial flexibility, withstand commodity price volatility, fund our development projects, operations and capital expenditures and return capital to shareholders. We utilize derivative contracts to reduce the financial impact of commodity price volatility and provide a level of certainty to the Company’s cash flows. We generally fund our operations, planned capital expenditures and any share repurchases with cash flow from our operating activities, cash on hand, and borrowings under our Credit Facility. Additionally, we may access debt and equity markets and sell properties to enhance our liquidity. There is no guarantee that the debt or equity capital markets will be available to us on acceptable terms or at all.
For the year ended December 31, 2024, our primary sources of capital resources and liquidity have consisted of internally generated cash flows from operations and access to the debt markets, and our primary uses of cash have been for development of our oil and natural gas properties, share repurchases, dividend payments on our preferred stock and discretionary acreage acquisitions.
We believe our annual free cash flow generation, borrowing capacity under the Credit Facility and cash on hand will provide sufficient liquidity to fund our operations, capital expenditures, interest expense and share repurchases during the next 12 months and the foreseeable future.
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To the extent actual operating results, realized commodity prices or uses of cash differ from our assumptions, our liquidity could be adversely affected. See Note 4 of our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our senior notes.
As of December 31, 2024, we had $1.5 million of cash and cash equivalents compared to $1.9 million as of December 31, 2023, and a net working capital deficit of $114.2 million as of December 31, 2024, compared to net working capital of $52.4 million as of December 31, 2023. As of December 31, 2024, our net working capital deficit includes no debt due in the next 12 months. Our total principal amount of funded debt as of December 31, 2024, was $713.7 million compared to $668.0 million as of December 31, 2023. See Note 4 of our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our notes.
As of February 20, 2025, we had $3.1 million of cash and cash equivalents, $10.0 million borrowings under our Credit Facility, $63.9 million of letters of credit outstanding, $25.7 million of outstanding 2026 Senior Notes and $650.0 million of outstanding 2029 Senior Notes.
Debt. In May 2021, we issued our 2026 Senior Notes. The 2026 Senior Notes are guaranteed on a senior unsecured basis by each of the Company’s subsidiaries that guarantee the Credit Facility. In September 2024, Gulfport Operating purchased approximately 95%, or $524.3 million, of the 2026 Senior Notes in a tender offer using net proceeds received from the private placement of the 2029 Senior Notes. This resulted in extending the maturity of substantially all of our senior notes from 2026 to 2029.
Additionally, on May 1, 2023, the Company entered into that certain Joinder, Commitment Increase and Borrowing Base Redetermination Agreement, and Third Amendment to Credit Agreement (the “Third Amendment”) which amended the Company’s Credit Facility. The Third Amendment, among other things, (a) increased the aggregate elected commitment amounts under the Credit Facility to $900 million, (b) increased the borrowing base under the Credit Facility to $1.1 billion, (c) increased the excess cash threshold under the Credit Facility to $75 million, and (d) extended the maturity date under the Credit Facility from October 14, 2025 to the earlier of (i) May 1, 2027 and (ii) the 91st day prior to the maturity date of the 2026 Senior Notes or any other permitted senior notes or any permitted refinancing debt under the Credit Facility having an aggregate outstanding principal amount equal to or exceeding $100 million; provided that such notes have not been refinanced, redeemed or repaid in full on or prior to such 91st day. On April 18, 2024, Gulfport completed its semi-annual borrowing base redetermination under its Credit Facility during which the borrowing base was reaffirmed at $1.1 billion with elected commitments remaining at $900 million.
On September 12, 2024, the Company entered into the Commitment Increase, Borrowing Base Reaffirmation Agreement, and Fourth Amendment to Credit Agreement (the “Fourth Amendment”), which amended the Company’s Third Amended and Restated Credit Agreement. The Fourth Amendment, among other things, (a) increased the aggregate elected commitment amounts under the Credit Facility to $1.0 billion, (b) reaffirmed the borrowing base under the Credit Facility at $1.1 billion, (c) extended the maturity date under the Credit Facility to September 12, 2028, and (d) reduced the pricing grid 50 bps.
We may continue to use a combination of cash, borrowings and issuances of our common stock or other securities to retire our outstanding debt and preferred stock through privately negotiated transactions, open market repurchases, redemptions, tender offers or otherwise, but we are under no obligation to do so.
See Note 4 of our consolidated financial statements for additional discussion of our outstanding debt.
Dividends on Preferred Stock. As discussed in Note 5 of our consolidated financial statements, holders of preferred stock are entitled to receive cumulative quarterly dividends at a rate of 10% per annum of the Liquidation Preference with respect to cash dividends and 15% per annum of the Liquidation Preference with respect to dividends paid in kind as additional shares of preferred stock (“PIK Dividends”). We currently have the option to pay either cash dividends or PIK Dividends on a quarterly basis.
During the years ended December 31, 2024 and 2023, the Company paid $4.2 million and $4.8 million, respectively, of cash dividends to holders of our preferred stock.
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Supplemental Guarantor Financial Information. The 2026 Senior Notes are guaranteed on a senior unsecured basis by all existing consolidated subsidiaries that guarantee our Credit Facility or certain other debt (the “2026 Senior Notes Guarantors”). The 2026 Senior Notes are not guaranteed by Grizzly Holdings or Mule Sky, LLC. The 2026 Senior Notes Guarantors are 100% owned by the Parent, and the guarantees are full, unconditional, joint and several. There are no significant restrictions on the ability of the Parent or the 2026 Senior Notes Guarantors to obtain funds from each other in the form of a dividend or loan. The guarantees rank equally in the right of payment with all of the senior indebtedness of the subsidiary guarantors and senior in the right of payment to any future subordinated indebtedness of the subsidiary guarantors. The 2026 Senior Notes and the guarantees are effectively subordinated to all of our and the subsidiary guarantors' secured indebtedness (including all borrowings and other obligations under our amended and restated credit agreement) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated to all indebtedness and other liabilities of any of our subsidiaries that do not guarantee the 2026 Senior Notes.
The 2029 Senior Notes are guaranteed on a senior unsecured basis by Gulfport and certain of Gulfport’s wholly owned subsidiaries (collectively, the “2029 Senior Notes Guarantors” and, together with the 2026 Senior Notes Guarantors, the “Guarantors”) and certain future subsidiaries of Gulfport that become borrowers or guarantors under any credit agreement with an aggregate principal amount outstanding or commitment amount in excess of $15 million. The 2029 Senior Notes Guarantors are 100% owned by the Parent, and the guarantees are full, unconditional, joint and several. There are no significant restrictions on the ability of the Parent or the 2029 Senior Notes Guarantors to obtain funds from each other in the form of a dividend or loan. The guarantees rank (i) senior in right of payment to any future subordinated indebtedness of Gulfport Operating or the 2029 Senior Notes Guarantors, (ii) pari passu in right of payment with all existing and future unsecured senior indebtedness of Gulfport Operating or the 2029 Senior Notes Guarantors, (iii) effectively junior to any secured indebtedness of Gulfport Operating or the 2029 Senior Notes Guarantors, including indebtedness under the credit agreement, to the extent of the value of the collateral securing such indebtedness, and (iv) structurally subordinated in right of payment to all indebtedness and other liabilities of Gulfport Operating’s subsidiaries that are not 2029 Senior Notes Guarantors.
SEC Regulation S-X Rule 13-01 requires the presentation of “Summarized Financial Information” to replace the “Condensed Consolidating Financial Information” required under Rule 3-10. Rule 13-01 allows the omission of Summarized Financial Information if assets, liabilities and results of operations of the Guarantors are not materially different than the corresponding amounts presented in our consolidated financial statements. The Parent and Guarantor subsidiaries comprise our material operations. Therefore, we concluded that the presentation of the Summarized Financial Information is not required as our Summarized Financial Information of the Guarantors is not materially different from our consolidated financial statements.
Derivatives and Hedging Activities. Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. Our natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to predict with greater certainty the total revenue we will receive. See Item 7A. “Quantitative and Qualitative Disclosures About Market Risk” for further discussion on the impact of commodity price risk on our financial position. Additionally, see Note 12 of our consolidated financial statements for further discussion of derivatives and hedging activities.
Subsequent to December 31, 2024 and as of February 20, 2025, we entered into the following natural gas, oil, and NGL derivative contracts:
| Period | Type of Derivative Instrument | Index | Daily Volume | Weighted Average Price | |||||
|---|---|---|---|---|---|---|---|---|---|
| Natural Gas | (MMBtu/d) | ($/MMBtu) | |||||||
| 2025 | Swaps | NYMEX Henry Hub | 18,301 | $3.85 | |||||
| 2026 | Basis Swaps | Rex Zone 3 | 40,000 | $(0.17) | |||||
| Oil | (Bbl/d) | ($/Bbl) | |||||||
| 2025 | Swaps | NYMEX WTI | 1,000 | $70.87 |
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Contractual and Commercial Obligations. The following table sets forth our contractual and commercial obligations at December 31, 2024 (in thousands):
| Payment due by period | ||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Contractual Obligations | Total | 2025 | 2026-2027 | 2028-2029 | 2030 and Thereafter | |||||||||||||
| Long-term debt(1): | ||||||||||||||||||
| Principal | $ | 713,702 | $ | — | $ | 25,702 | $ | 688,000 | $ | — | ||||||||
| Interest | 220,923 | 44,481 | 88,692 | 87,750 | — | |||||||||||||
| Firm transportation and gathering contracts(2) | 1,147,946 | 140,434 | 270,729 | 273,366 | 463,417 | |||||||||||||
| Other operational commitments(3) | 13,791 | 13,791 | — | — | — | |||||||||||||
| Operating lease liabilities(4) | 6,228 | 5,657 | 571 | — | — | |||||||||||||
| Total contractual cash obligations(5) | $ | 2,102,590 | $ | 204,363 | $ | 385,694 | $ | 1,049,116 | $ | 463,417 |
_____________________
(1) The maturities of our debt obligations and associated interest reflect their original expiration dates and do not reflect any acceleration due to any events of default pertaining to these obligations. See Note 4 of our consolidated financial statements for a description of our long-term debt.
(2) See Note 17 of our consolidated financial statements for further discussion of our firm transportation and gathering commitments.
(3) See Note 17 of our consolidated financial statements for a description of our other operational commitments.
(4) See Note 9 of our consolidated financial statements for a description of our operating lease liabilities.
(5) This table does not include derivative liabilities or the estimated discounted cost for future abandonment of oil and natural gas properties. See Notes 12 and 3 of our consolidated financial statements, respectively.
Off-balance Sheet Arrangements. We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2024, our material off-balance sheet arrangements and transactions include $63.8 million in letters of credit outstanding against our Credit Facility and $44.9 million in surety bonds issued. Both the letters of credit and surety bonds are being used as financial assurance, primarily for certain firm transportation agreements. Additionally, the Company entered into various contractual commitments to purchase inventory and other material to be used in future activities. The Company's commitment to purchase these materials exists through 2025, with approximately $13.8 million remaining. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources. See Note 17 of our consolidated financial statements for further discussion of the various financial guarantees we have issued.
Capital Expenditures. Our capital expenditures have historically been related to the execution of our drilling and completion activities in addition to certain lease acquisition activities. Our capital investment strategy is focused on prudently developing our existing properties to generate sustainable cash flow considering current and forecasted commodity prices. For the year ended December 31, 2024, the Company's incurred capital expenditures totaled $430.1 million, of which $327.4 million related to drilling and completion activities, $57.9 million related to maintenance leasehold and land investment and $44.8 million related to discretionary acreage acquisitions.
Our drilling and completion capital expenditures for 2025 are currently estimated to be in the range of $335 million to $355 million. Also, we currently expect to spend approximately $35 million to $40 million in 2025 for maintenance leasehold and land investment, which is focused on near-term drilling programs and facilitating increases in our working interests and lateral footage in units we plan to drill in 2025, 2026 and 2027. We expect this capital program to result in approximately 1,040 to 1,065 MMcfe per day of production in 2025.
Commodity Price Risk. The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty. During 2024, WTI prices ranged from $66.73 to $87.69 per barrel and the Henry Hub spot market price of natural gas ranged from $1.21 to $13.20 per MMBtu. During 2023, WTI prices ranged from $66.61 to $93.67 per barrel and the Henry Hub spot market price of natural gas ranged from $1.74 to $3.78 per MMBtu. If the prices of oil and natural gas decline further, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected. In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to write-down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Reductions in commodity prices and/or our reserves could also negatively impact the borrowing base under our revolving credit facility, which could limit our liquidity and ability to fund development activities.
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See Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” for further information regarding our open derivative instruments at December 31, 2024.
Sources and Uses of Cash
The following table presents the major changes in cash and cash equivalents for the year ended December 31, 2024 and 2023 (in thousands):
| Year Ended December 31, 2024 | Year Ended December 31, 2023 | |||||
|---|---|---|---|---|---|---|
| Net cash provided by operating activities | $ | 650,033 | $ | 723,181 | ||
| Additions to oil and natural gas properties | (454,098) | (537,360) | ||||
| Debt activity, net | 32,761 | (27,000) | ||||
| Debt issuance and loan commitment fees | (14,933) | (7,068) | ||||
| Repurchases of common stock | (184,477) | (149,165) | ||||
| Dividends on preferred stock | (4,230) | (4,840) | ||||
| Shares exchanged for tax withholdings | (23,614) | (3,207) | ||||
| Other | (1,898) | 129 | ||||
| Net change in cash and cash equivalents | $ | (456) | $ | (5,330) | ||
| Cash and cash equivalents at end of period | $ | 1,473 | $ | 1,929 |
Net cash provided by operating activities. Net cash provided by operating activities was $650.0 million for the year ended December 31, 2024, compared to $723.2 million for the year ended December 31, 2023. The decrease was primarily the result of a decrease in our natural gas revenues.
Additions to oil and natural gas properties. During the year ended December 31, 2024, we spud 20 gross (19.7 net) operated wells and commenced sales from 16 gross (15.4 net) operated wells targeting the Utica formation for a total cost incurred of approximately $259.8 million. During the year ended December 31, 2024, we spud 2 gross (1.8 net) operated wells and commenced sales from 3 gross (2.4 net) operated wells in the SCOOP for a total incurred cost of approximately $63.8 million. Additionally, the Company incurred $57.9 million related to maintenance leasehold and land investment and $44.8 million related to discretionary acreage acquisitions.
Drilling and completion costs discussed above reflect incurred costs while drilling and completion costs presented in the table below reflect cash payments for drilling and completions. Incurred capital expenditures and cash capital expenditures may vary from period to period due to the cash payment cycle. Cash capital expenditures for the year ended December 31, 2024 and 2023, were as follows (in thousands):
| Year Ended December 31, 2024 | Year Ended December 31, 2023 | |||||
|---|---|---|---|---|---|---|
| Oil and Natural Gas Property Cash Expenditures: | ||||||
| Drilling and completion costs | $ | 325,129 | $ | 413,258 | ||
| Leasehold acquisitions | 102,630 | 101,191 | ||||
| Other | 26,339 | 22,911 | ||||
| Total oil and natural gas property expenditures | $ | 454,098 | $ | 537,360 |
Debt activity, net. During the year ended December 31, 2024, the Company had $956.0 million and $1.0 billion in borrowings and repayments, respectively, on its Credit Facility. In September 2024, the Company purchased $524.3 million of the 2026 Senior Notes in a tender offer. The retirement of the 2026 Senior Notes resulted in a loss on debt extinguishment of $13.4 million, which included cash costs of $12.9 million. The Company also issued $650.0 million aggregate principal amount of its 6.750% senior notes due 2029. As of February 20, 2025, the Company had $10.0 million in borrowings outstanding on its Credit Facility.
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Debt issuance and loan commitment fees. During the year ended December 31, 2024, the Company incurred debt issuance and loan commitment fees of $14.9 million, as compared to $7.1 million during the year ended December 31, 2023. The increase was primarily related to the issuance of the 2029 Senior Notes and the Fourth Amendment to the Credit Facility. See Note 4 of our consolidated financial statements for further discussion of the long-term debt activity.
Repurchases of common stock. During the year ended December 31, 2024, the Company repurchased 1.2 million shares for approximately $184.5 million under the Repurchase Program at a weighted average price of $153.35 per share. For the same period in 2023, the Company repurchased 1.5 million shares for $148.9 million at a weighted average price of $101.53 per share. As of February 20, 2025, we repurchased 5.6 million shares for approximately $593.2 million under the Repurchase Program at a weighted average price of $105.57 per share.
Dividends on preferred stock. During the year ended December 31, 2024, the Company paid $4.2 million of cash dividends to holders of our preferred stock compared to $4.8 million in the year ended December 31, 2023.
Shares exchanged for tax withholdings. During the year ended December 31, 2024, the Company paid $23.6 million of shares exchanged for tax withholdings compared to $3.2 million in the year ended December 31, 2023. The increase in shares traded for taxes was primarily due to the vesting of certain PSU awards as discussed in Note 7 of our consolidated financial statements.
Other. During the year ended December 31, 2024, the Company incurred other expenses of $1.9 million, as compared to other income of $0.1 million paid during the year ended December 31, 2023. The change was primarily related to proceeds from sales of oil and gas properties of $2.6 million during the year ended December 31, 2023.
Critical Accounting Policies and Estimates
The preparation of financial statements in accordance with accounting principles generally accepted in the United States require us to make estimates and assumptions. The accounting estimates and assumptions we consider to be most significant to our financial statements are discussed below. Our management has discussed each critical accounting estimate with the Audit Committee of our Board of Directors.
Oil and Natural Gas Properties. We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including non-productive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and natural gas properties, are capitalized.
Under the full cost method, capitalized costs are amortized on a composite unit-of-production method based on proved oil and natural gas reserves. If we maintain the same level of production year over year, the depreciation, depletion and amortization expense may be significantly different if our estimate of remaining reserves or future development costs changes significantly.
We review the carrying value of our oil and natural gas properties under the full cost method of accounting prescribed by the SEC on a quarterly basis. This quarterly review is referred to as a ceiling test.
Two primary factors impacting this test are reserve estimates and the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, 2024. Downward revisions to estimates of oil and natural gas reserves and/or unfavorable prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes, is generally written off as an expense. During 2024, the Company recognized ceiling test impairments of $373.2 million and did not record an impairment of its oil and natural gas properties for the year ended December 31, 2023. See Oil and Natural Gas Properties in Note 1 of our consolidated financial statements for further information on the full cost method of accounting.
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Oil, Natural Gas and NGL Reserves. Estimates of oil and natural gas reserves and their values, future production rates, future development costs and commodity pricing differentials are the most significant of our estimates. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These revisions could materially affect our financial statements. The volatility of commodity prices results in increased uncertainty inherent in these estimates and assumptions. Changes in natural gas, oil or NGL prices could result in actual results differing significantly from our estimates. See Note 20 of our consolidated financial statements for further information.
Income Taxes. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized in the year in which realization becomes determinable. At each reporting period, the Company weighs all available positive and negative evidence to determine whether its deferred tax assets are more likely than not to be realized. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. To assess that likelihood, the Company uses estimates and judgment regarding future taxable income and considers the tax laws in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities and tax planning strategies as well as the current and forecasted business economics of the oil and gas industry. Based upon the Company’s analysis, the Company currently believes that it is more likely than not that a portion of the Company's federal and state deferred tax assets will be utilized.
Revenue Recognition. We derive almost all of our revenue from the sale of natural gas, crude oil and NGL produced from our oil and natural gas properties. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment on substantially all of these sales from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers that month and the price we will receive. Variances between our estimated revenue and the actual amounts for product sales is recorded in the month that payment is received from the purchaser. Historically, our actual payments received have not significantly deviated from our accruals.
Derivative Instruments. We seek to reduce our exposure to unfavorable changes in natural gas, oil and NGL prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps, costless collars and various types of option contracts. All derivative instruments are recognized as assets or liabilities in the balance sheet, measured at fair value. We estimate the fair value of all derivative instruments using industry-standard models that considered various assumptions including current market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures.
The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Our current commodity derivative instruments are not designated as hedges for accounting purposes. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities.