GULFPORT ENERGY CORP

18. COMMITMENTS

Firm Transportation and Gathering Agreements

The Company has contractual commitments with midstream and pipeline companies for future gathering and transportation of natural gas from the Company's producing wells to downstream markets. Under certain of these agreements, the Company has minimum daily volume commitments. The Company is also obligated under certain of these arrangements to pay a demand charge for firm capacity rights on pipeline systems regardless of the amount of pipeline capacity utilized by the Company. If the Company does not utilize the capacity, it often can release it to other counterparties, thus reducing the cost of these commitments. Working interest owners and royalty interest owners, where appropriate, will be responsible for their proportionate share of these costs. Commitments related to future firm transportation and gathering agreements are not recorded as obligations in the accompanying consolidated balance sheets; however, costs associated with utilized future firm transportation and gathering agreements are reflected in the Company's estimates of proved reserves.

A summary of these commitments at December 31, 2023, are set forth in the table below (in thousands):

Other Operational Commitments

The Company entered into various contractual commitments to purchase inventory and other material to be used in future activities. The Company's commitment to purchase these materials spans 2024, with approximately $28.9 million remaining.

Contributions to 401(k) Plan

Gulfport sponsors a 401(k) plan under which eligible employees may contribute a portion of their total compensation up to the maximum pre-tax threshold through salary deferrals. The plan is considered a Safe Harbor 401(k) and provides a company match on 100% of salary deferrals that do not exceed 6% of compensation. The Company may also make discretionary elective contributions to the plan. The following table summarizes the contributions expenses related to this plan for the years ended December 31, 2023, December 31, 2022, Prior Successor Period and Prior Predecessor Period (in thousands):

19. CONTINGENCIES

The Company is involved in a number of litigation and regulatory proceedings including those described below. Many of these proceedings are in early stages, and many of them seek or may seek damages and penalties, the amount of which is indeterminate. The Company's total accrued liabilities in respect of litigation and regulatory proceedings is determined on a case-by-case basis and represents an estimate of probable losses after considering, among other factors, the progress of each case or proceeding, its experience and the experience of others in similar cases or proceedings, and the opinions and views of legal counsel. Significant judgment is required in making these estimates and their final liabilities may ultimately be materially different. In accordance with ASC Topic 450, Contingencies, an accrual is recorded for a material loss contingency when its occurrence is probable and damages are reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes.

Litigation and Regulatory Proceedings

As part of its Chapter 11 Cases and restructuring efforts, the Company filed motions to reject certain firm transportation agreements between the Company and affiliates of TC Energy Corporation ("TC") and Rover Pipeline LLC ("Rover"). During the third quarter of 2021, Gulfport finalized a settlement agreement with TC that was approved by the Bankruptcy Court on September 21, 2021. Pursuant to the settlement agreement, Gulfport and TC agreed that the firm transportation contracts between them would be rejected without any further payment or obligation by either party, and TC assigned its damages claims from such rejection to Gulfport. In exchange, Gulfport agreed to make a payment of $43.8 million in cash to TC. The $43.8 million was paid on October 7, 2021. Gulfport expects to receive distributions for a significant portion of such amounts through future distributions with respect to the assigned claims pursuant to the terms of the Plan that became effective in May 2021. Any future distributions will be recognized once received by Gulfport. In February 2022, Gulfport received an initial distribution of $11.5 million from the above-mentioned claim, which is included in Other, net in the accompanying consolidated statements of operations.

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. The Bankruptcy Court Order provided Rover will: (a) receive an allowed $85.9 million Class 4A General Unsecured Claim (the “Rover Unsecured Claim”), (b) receive an administrative claim of $1.0 million payable by Gulfport, and (c) draw the full amount of its credit assurance. Gulfport paid the $1.0 million administrative claim during the first quarter, and has no further obligations to Rover. The Rover Unsecured Claim will receive distributions under the Plan payable from the liquidating trust, not Gulfport. On February 24, 2023, Gulfport received an additional $17.8 million interim distribution for its TC claim. On December 22, 2023, Gulfport received its final $8.3 million distribution for its TC claim. These payments are included in Other, net in the accompanying consolidated statements of operations.

The Company, along with other oil and gas companies, have been named as a defendant in a number of lawsuits where Plaintiffs assert their respective leases are limited to the Marcellus and Utica shale geological formations and allege that Defendants have willfully trespassed and illegally produced oil, natural gas, and other hydrocarbon products beyond these respective formations. They also allege that Defendants engaged in conversion and were unjustly enriched. Plaintiffs seek the full value of any production from below the Marcellus and Utica shale formations, unspecified damages from the diminution of value to their mineral estate, unspecified punitive damages, and the payment of reasonable attorney fees, legal expenses, and interest. On April 27, 2021, the Bankruptcy Court for the Southern District of Texas approved a settlement agreement in which the plaintiffs fully released the Company from all claims that accrued and any damages related to the period before the effective date of the Company’s Chapter 11 plan, which occurred on May 17, 2021. The plaintiffs are continuing to pursue alleged damages after May 17, 2021.

Business Operations

The Company is involved in various lawsuits and disputes incidental to its business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions.

Environmental Contingencies

The nature of the oil and gas business carries with it certain environmental risks for Gulfport and its subsidiaries. Gulfport and its subsidiaries have implemented various policies, programs, procedures, training and audits to reduce and mitigate environmental risks. The Company conducts periodic reviews, on a company-wide basis, to assess changes in its environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. The Company manages its exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the extent of an identified environmental concern, it may, among other things, exclude a property from the transaction, require the seller to remediate the property to its satisfaction in an acquisition or agree to assume liability for the remediation of the property.

Other Matters

Based on management’s current assessment, they are of the opinion that no pending or threatened lawsuit or dispute relating to its business operations is likely to have a material adverse effect on their future consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.

Concentration of Credit Risk

Gulfport operates in the oil and natural gas industry principally in the states of Ohio and Oklahoma with sales to refineries, re-sellers such as marketers, and other end users. While certain of these customers are affected by periodic downturns in the economy in general or in their specific segment of the oil and gas industry, Gulfport believes that its level of credit-related losses due to such economic fluctuations has been immaterial and will continue to be immaterial to the Company’s results of operations in the long term.

The Company maintains cash balances at several banks. Accounts at each institution are insured by the Federal Deposit Insurance Corporation. At December 31, 2023, Gulfport held no cash in excess of insured limits in these banks.

During the year ended December 31, 2023, one customer accounted for approximately 12% of the Company's total sales. During the year ended December 31, 2022, two customers accounted for approximately 31% of the Company's total sales. During the Prior Successor Period, two customers accounted for approximately 30% of the Company's total sales. During the Prior Predecessor Period, three customers accounted for approximately 37% of the Company's total sales. The Company does not believe that the loss of any of these customers would have a material adverse effect on its natural gas, oil and condensate and NGL sales as alternative customers are readily available.

20. SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED)

The Company is making the following supplemental disclosures of oil and gas activities, in accordance with the full cost method of accounting for its oil and gas exploration and development activities. The Company owns a 24.5% interest in Grizzly. However, Grizzly did not have any material activity or proved reserves in the years presented below. As such, amounts related to Grizzly have been omitted below.

The following table provides historical revenue and cost information relating to the Company’s oil and gas operations located entirely in the United States:

Capitalized Costs Related to Oil and Gas Producing Activities (in thousands)

Costs Incurred in Oil and Gas Property Acquisition and Development Activities (in thousands)

Capitalized interest is included as part of the cost of oil and natural gas properties. The Company didnot capitalize interest expense for the year ended December 31, 2022, or Prior Predecessor Period. The Company capitalized $4.1 million for the year ended December 31, 2023, and $0.2 million during the Prior Successor Period based on the Company's weighted average cost of borrowings used to finance expenditures.

In addition to capitalized interest, the Company capitalized internal costs totaling $22.8 million, $20.2 million, $11.9 million and $8.0 million during the years ended December 31, 2023, December 31, 2022, Prior Successor Period and Prior Predecessor Period, respectively, which were directly related to the acquisition, exploration and development of the Company's oil and natural gas properties.

Results of Operations for Producing Activities (in thousands)

The following table sets forth the revenues and expenses related to the production and sale of oil and natural gas. The income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include depreciation, depletion and amortization allowances, after giving effect to the permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas production.

Oil and Natural Gas Reserves

The following table presents estimated volumes of proved developed and undeveloped oil and gas reserves as of December 31, 2023, 2022 and 2021 and changes in proved reserves during the last three years. The reserve reports use an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2023, 2022 and 2021, in accordance with guidelines of the SEC applicable to reserves estimates. The prices used for the 2023 reserve report are $78.21 per barrel of oil, $2.64 per MMbtu and $31.42 per barrel for NGL, adjusted by lease for transportation fees and regional price differentials, and for oil and gas reserves, respectively. The prices used at December 31, 2022 and 2021 for reserve report purposes are $94.14 per barrel, $6.36 per MMbtu and $47.86 per barrel for NGL and $66.55 per barrel, $3.60 per MMbtu and $31.90 per barrel for NGL, respectively.

Gulfport emphasizes that the volumes of reserves shown below are estimates which, by their nature, are subject to revision. The estimates are made using all available geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data.

In 2023, the Company experienced extensions of 995.7 Bcfe of estimated proved reserves, which were primarily attributable to the Company's continued development of its Utica/Marcellus and SCOOP acreages. Of the total extensions,789.2 Bcfe was attributable to the addition of 67 Utica PUD locations,88.6 Bcfe was attributable to the addition of 12 Marcellus PUD locations, and 110.4 Bcfe was attributable to the addition of 14 SCOOP PUD locations. The Company experienced total downward revisions of 444.9 Bcfe in estimated proved reserves. These consisted of upward revisions of 24.9 Bcfe as a result of positive well performance and 293.9 Bcfe due to an increase in working interest and net revenue interest as a result of our successful leasing efforts through 2023. These were offset by downward revisions of 554.9 Bcfe which were primarily a result of development schedule changes with some PUD well design changes. The schedule changes moved the development of 36 Utica/Marcellus PUD locations and 8 SCOOP PUD locations beyond the SEC requirement of developing these wells five years from initial booking. The development schedule changes reflect our ongoing commitment to optimizing the long-term plan to best develop our asset, maximize cash flow, and overall economic returns. These locations excluded from our SEC reserves report remain in Gulfport's development plan. Additionally, downward revisions of 159.7 Bcfe due to commodity price changes. Commodity prices experienced volatility throughout 2023 and the 12-month average price for natural gas decreased from $6.36 per MMBtu for 2022 to $2.64 per MMBtu for 2023, the 12-month average price for NGL increased from $47.86 per barrel for 2022 to $31.42 per barrel for 2023, and the 12-month average price for crude oil decreased from $94.14 per barrel for 2022 to $78.21 per barrel for 2023. Finally, downward revisions of 49.1 Bcfe were a result of a combination of various economic assumption updates.

In 2022, the Company experienced extensions of 438.9 Bcfe of estimated proved reserves, which were primarily attributable to the Company's continued development of its Utica/Marcellus and SCOOP acreages. Of the total extensions,295.9 Bcfe was attributable to the addition of 36 PUD locations in the Utica,72.1 Bcfe was attributable to the addition of 8 PUD locations in the Marcellus and 65.4 Bcfe was attributable to the addition of 5 PUD locations in the SCOOP. The Company experienced total upward revisions of approximately 69.7 Bcfe in estimated proved reserves, of which 47.7 Bcfe was the result of improved commodity prices. The 12-month average price for natural gas increased from $3.60 per MMBtu for 2021 to $6.36 per MMBtu for 2022, the 12-month average price for NGL increased from $31.90 per barrel for 2021 to $47.86 per barrel for 2022, and the 12-month average price for crude oil increased from $66.55 per barrel for 2021 to $94.14 per barrel for 2022. Upward revisions of 144.5 Bcfe were a result of an increase in working interest and net revenue interests as a result of our successful leasing efforts through 2022. Downward revisions of 95.6 Bcfe were experienced as a result of the SEC five-year development window, which removed 4 PUD locations in the Utica and 5 PUD locations in the SCOOP. The development plan changes reflect our commitment to optimizing the long-term development schedule to maximize cash flow and overall economic returns. A small downward revision of 26.9 Bcfe was primarily a result of performance changes to several wells and changes in PUD location forecasts.

In 2021, the Company experienced extensions of 694.6 Bcfe of estimated proved reserves, which were primarily attributable to the Company's continued development of its Utica and SCOOP acreage. Of the total extensions,352.2 Bcfe was attributable to the addition of 29 PUD locations in the Utica,342.2 Bcfe was attributable to the addition of 34 PUD locations in the SCOOP. The Company experienced total upward revisions of approximately 982.2 Bcfe in estimated proved reserves, of which 889.2 Bcfe was the result of improved commodity prices. The 12-month average price for natural gas increased from $1.99 per MMBtu for 2020 to $3.60 per MMBtu for 2021, the 12-month average price for NGL increased from $15.40 per barrel for 2020 to $31.90 per barrel for 2021, and the 12-month average price for crude oil increased from $39.54 per barrel for 2020 to $66.55 per barrel for 2021. Upward revisions of 157.6 Bcfe were experienced from a combination of well performance, operating and development cost improvements and working interest changes. This was partially offset by a downward revision of 64.6 Bcfe, which was primarily a result of the exclusion of 4 PUD locations in the Utica when changes in the Company's schedule moved development of these PUD locations beyond five years of initial booking. The development plan change reflects the Company's commitment to capital discipline, funding future activities within cash flow and ongoing optimization of our development plan. Finally, during 2021, we sold approximately 0.2 Bcfe of proved oil and natural gas reserves through various sales of our non-operated interests in our other non-core assets.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following tables present the estimated future cash flows, and changes therein, from Gulfport’s proven oil and gas reserves as of December 31, 2023, 2022 and 2021 using an unweighted average first-of-the-month price for the period January through December 31, 2023, 2022 and 2021. The average gas prices used were $2.64, $6.36 and $3.60 for the periods ended December 31, 2023, 2022 and 2021, respectively. The average oil prices used were $78.21, $94.14 and $66.55, for the periods ended December 31, 2023, 2022 and 2021, respectively. The average NGL prices used were $31.42, $47.86 and $31.90, for the periods ended December 31, 2023, 2022 and 2021, respectively.

Year ended operating expenses, development costs and appropriate statutory income tax rates, with consideration of future tax rates, were used to compute the future net cash flows. All cash flows were discounted at 10% to reflect the time value of cash flows, without regard to the risk of specific properties. The estimated future costs to develop proved developed non-producing and proved undeveloped reserves are approximately $246.3 million in 2024, $328.7 million in 2025 and $282.6 million in 2026. Estimated future development costs include capital spending on major development projects. Gulfport believes cash flow from its operating activities, cash on hand and borrowings under its Credit Facility will be sufficient to cover these estimated future development costs.

The assumptions used to derive the standardized measure of discounted future net cash flows are those required by accounting standards and do not necessarily reflect the Company's expectations. The information may be useful for certain comparative purposes but should not be solely relied upon in evaluating Gulfport or its performance. Furthermore, information contained in the following table may not represent realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of the Company's reserves. Management believes that the following factors should be considered when reviewing the information below:

•Future commodity prices received for selling the Company's net production will likely differ from those required to be used in these calculations.

•Future operating and capital costs will likely differ from those required to be used in these calculations and do not reflect cost savings of Company owned midstream operations on future operating expenses.

•Future market conditions, government regulations, reservoir conditions and risks inherent in the production of oil and condensate and gas may cause production rates in future years to vary significantly from those rates used in the calculations.

•Future revenues may be subject to different production, severance and property taxation rates.

•The selection of a 10% discount rate is arbitrary and may not be a reasonable factor in adjusting for future economic conditions or in considering the risk that is part of realizing future net cash flows from the reserves.

The following table summarizes estimated future net cash flows from natural gas and crude oil reserves (in millions):

Future development and abandonment costs include not only development costs but also all future costs to settle asset retirement obligations. The following table summarizes the total of all future costs to settle asset retirement obligations that are included in future development and abandonment costs above (in millions):

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The principal source of change in the standardized measure of discounted future net cash flows relating to proved reserves is presented in the table below (in millions):