CRK 10-K & 10-Q changes, risk factors and insider trading
Comstock Resources Inc. · NYSE · Crude Petroleum & Natural Gas · CIK 23194 · All filings on SEC.gov
At a glance
What changed in the latest 10-K
Risk Factors
New heading “Some of our undeveloped leasehold acreage is subject to leases that will expire unless production is established on units containing the acreage. Failure to administer lease acquisitions, lease contracting, lease maintenance and timely lease payments could lead to loss of leased land.”
New heading “The unavailability or high cost of drilling rigs, completion equipment, supplies, qualified personnel and oilfield services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.”
New heading “We may be subject to physical and financial risks associated with climate-related effects.”
New heading “Scrutiny and uncertain expectations from stakeholders with respect to our environmental, social and governance practices may impose additional costs on us or expose us to new or additional risks.”
Removed heading “We may be subject to physical and financial risks associated with climate change.”
Removed heading “Increasing scrutiny and changing expectations from stakeholders with respect to our environmental, social and governance practices may impose additional costs on us or expose us to new or additional risks.”
Largest changes
“Changing climate may create physical and financial risks to our business. Energy needs vary with weather conditions. To the extent weather conditions may be affected by climate change, energy use could increase or decrease depending on the duration and magnitude of any changes. Increased energy use due to weather changes may require us to invest in more infrastructure to serve increased demand. A decrease in energy use due to weather changes may affect our financial condition through decreased revenues. …”see in full comparison
“Environmental regulations relating to climate change and/or greenhouse gases could also reduce demand for our products or increase our operating and drilling costs. Our business could also be affected by the potential for lawsuits against companies that emit greenhouse gases, based on links drawn between greenhouse gas emissions and climate conditions. To the extent financial markets view GHG emissions as a financial risk, this could negatively impact our cost of and access to capital.”see in full comparison
“We may be subject to physical and financial risks associated with climate-related effects.”see in full comparison
“We may be subject to physical and financial risks associated with climate change.”see in full comparison
We rely on information technology and operational technology systems to process, transmit, and store information, to manage and support a variety of business processes and activities, and to comply with regulatory, legal and tax requirements. Our information technology and operational technology systems, some of which are dependent on third-party business partners, may be vulnerable to damage, interruption or shutdown due to any number of causes outside of our control such as catastrophic events, natural disasters, fires, power outages, systems failures, telecommunications failures and employee error or malfeasance. As a natural gas and oil producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the safety of our employees, threats to the security or operation of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. Cybersecurity attacks in particular are evolving and include, but are not limited to, ransomware or other malicious software, social engineering attacks, deepfakes and artificial intelligence ("AI")-enhanced phishing, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. Threat actors may leverage AI and machine learning, technologies to conduct more sophisticated surveillance, reconnaissance and attacks against our systems. We seek to prevent, detect and investigate cybersecurity incidents, but in some cases, we might be unaware of an incident or its magnitude and effects. Although we utilize various procedures and controls to monitor and protect against these threats and to mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing.see in full comparison
“Some of our undeveloped leasehold acreage is subject to leases that will expire unless production is established on units containing the acreage. Failure to administer lease acquisitions, lease contracting, lease maintenance and timely lease payments could lead to loss of leased land.”see in full comparison
Full comparison: every changed paragraph (29)
political conditions and events in other natural gas-producing countries, including embargoes and other sustained military campaigns, and acts of terrorism or sabotagesabotage, and armed conflicts;
tariffs and trade restrictions that may be imposed by the United States or other countries on natural resources, including natural gas;
the price and availability of alternative fuels; and overall U.S. and global economic and political conditions, including inflationary pressures, further increases in interest rates,rate adjustments, a general economic slowdown or recession, political tensions and war (including future developments in the ongoing Russia-Ukraine conflict and Israel-Hamasconflicts conflictsin the Middle East).
A prospect is a property in which we own an interest, or have operating rights to, and that has what our geoscientists believe, based on available seismic and geological information, to be an indication of potential oil or natural gas. Our prospects are in various stages of evaluation, ranging from a prospect that is ready to be drilled to a prospect that will require substantial additional evaluation and interpretation. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether natural gas or oil will be present or, if present, whether natural gas or oil will be present in commercial quantities. The analysis that we perform using data from other wells, more fully explored prospects and/or producing fields may not be useful in predicting the characteristics and potential reserves associated with our drilling prospects. If we drill additional unsuccessful wells, our drilling success rate may decline and we may not achieve our targeted rate of return. Further, unsuccessful drilling may impact our ability to fulfill our firm transportation commitments.
Some of our undeveloped leasehold acreage is subject to leases that will expire unless production is established on units containing the acreage. Failure to administer lease acquisitions, lease contracting, lease maintenance and timely lease payments could lead to loss of leased land.
A large portion of our undeveloped leasehold acreage is subject to leases with primary terms that expire prior to 2028 unless we establish and maintain production on units containing these leases during their terms or we renew them before their expiration. The cost to renew such leases could increase significantly and we may not be able to renew such leases on economically beneficial terms or at all. If our leases expire or we are unable to renew such leases, we will lose our right to develop such leasehold acreage and our exploration and development activities could materially differ from our current expectations, which could adversely affect our business.
The unavailability or high cost of drilling rigs, completion equipment, supplies, qualified personnel and oilfield services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.
When drilling and completion activity in the United States or a particular operating area increases, associated costs also increase, including costs associated with drilling rigs, completion equipment, drill pipe, casing and other tubular goods, sand and other proppants, personnel and other related services. If these costs increase, we may not be able to obtain necessary equipment, supplies and services or obtain them at economically beneficial terms. Such increases in cost could result in delays in our drilling or completion activities, which could limit our ability to establish and replace reserves, or should we choose to incur higher costs, could negatively impact our business.
We expect to continue to expend substantial capital in the acquisition of, exploration for and development of natural gas reserves. In order to finance these activities, we may need to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of non-strategic assets or other means. The issuance of additional equity securities could have a dilutive effect on the value of our common shares and may not be possible on terms acceptable to us given the current volatility in the financial markets. The issuance of additional debt would likely require that a portion of our cash flow from operations be used for the payment of interest on our debt, thereby reducing our ability to use our cash flow to fund working capital, capital expenditures, acquisitions, dividends and general corporate requirements, which could place us at a competitive disadvantage relative to other competitors. Our cash flow from operations and access to capital is subject to a number of variables, including:
A prospect is a property in which we own an interest, or have operating rights to, and that has what our geoscientists believe, based on available seismic and geological information, to be an indication of potential oil or natural gas. Our prospects are in various stages of evaluation, ranging from a prospect that is ready to be drilled to a prospect that will require substantial additional evaluation and interpretation. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. The analysis that we perform using data from other wells, more fully explored prospects and/or producing fields may not be useful in predicting the characteristics and potential reserves associated with our drilling prospects. If we drill additional unsuccessful wells, our drilling success rate may decline and we may not achieve our targeted rate of return. Further, unsuccessful drilling may impact our ability to fulfill our firm transportation commitments.
We may be subject to physical and financial risks associated with climate change.
Changing climate may create physical and financial risks to our business. Energy needs vary with weather conditions. To the extent weather conditions may be affected by climate change, energy use could increase or decrease depending on the duration and magnitude of any changes. Increased energy use due to weather changes may require us to invest in more infrastructure to serve increased demand. A decrease in energy use due to weather changes may affect our financial condition through decreased revenues. Extreme weather conditions in general require more equipment redundancy, adding to costs, and can contribute to increased risk of delivery disruptions. Additionally, many climate models indicate that global warming is likely to result in rising sea levels and increased frequency and severity of weather events, which may lead to higher insurance costs, or a decrease in available coverage, for our assets in areas subject to severe weather. These climate-related changes could damage our physical assets, especially operations located in low-lying areas near coasts and riverbanks, and facilities situated in hurricane-prone and rain-susceptible regions. To the extent the frequency of extreme weather events increases, this could increase our cost of producing products. We may not be able to pass on the higher costs to our customers or recover all costs related to mitigating these physical risks. Regulations relating to climate change and/or greenhouse gases could also reduce demand for our products or increase our operating and drilling costs. Our business could also be affected by the potential for lawsuits against companies that emit greenhouse gases, based on links drawn between greenhouse gas emissions and climate change. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital.
Increasing scrutiny and changing expectations from stakeholders with respect to our environmental, social and governance practices may impose additional costs on us or expose us to new or additional risks.
Companies across all industries are facing increasing scrutiny from stakeholders related to their environmental, social and governance ("ESG") practices. Investor advocacy groups, certain institutional investors, investment funds and other influential investors are also increasingly focused on ESG practices and in recent years have placed increasing importance on the implications and social cost of their investments. Regardless of the industry, investors' increased focus and activism related to ESG and similar matters may hinder access to capital, as investors may decide to reallocate capital or to not commit capital as a result of their assessment of a company's ESG practices. Companies that do not adapt to or comply with investor or other stakeholder expectations and standards, which are evolving, or that are perceived to have not responded appropriately to the growing concern for ESG issues, regardless of whether there is a legal requirement to do so, may suffer from reputational damage and the business, financial condition, and/or stock price of such a company could be materially and adversely affected. We face pressures from our stockholders, who are increasingly focused on climate change, to prioritize sustainable energy practices, reduce our carbon footprint and promote sustainability. Our stockholders may require us to implement new ESG procedures or standards in order to continue engaging with us, to remain invested in us or before they may make further investments in us. Additionally, we may face reputational challenges in the event our ESG procedures or standards do not meet the standards set by certain constituencies. We have adopted certain practices and metrics as highlighted on our website, including with respect to air emissions, land use, environmental, health and safety management and corporate governance. It is possible, however, that our stockholders might not be satisfied with our sustainability efforts or the speed of their adoption. If we do not meet our stockholders' expectations, our business, ability to access capital, and/or our stock price could be harmed. Additionally, adverse effects upon the oil and gas industry related to the worldwide social and political environment, including uncertainty or instability resulting from climate change, changes in political leadership and environmental policies, changes in geopolitical-social views toward fossil fuels and renewable energy, concern about the environmental impact of climate change, and investors' expectations regarding ESG matters, may also adversely affect demand for our products. Any long-term material adverse effect on the natural gas and oil industry could have a significant financial and operational adverse impact on our business. The occurrence of any of the foregoing could have a material adverse effect on the price of our stock and our business and financial condition.
We had $3.0 billion principal amount of debt as of December 31, 2024.
We rely on information technology and operational technology systems to process, transmit, and store information, to manage and support a variety of business processes and activities, and to comply with regulatory, legal and tax requirements. Our information technology and operational technology systems, some of which are dependent on third-party business partners, may be vulnerable to damage, interruption or shutdown due to any number of causes outside of our control such as catastrophic events, natural disasters, fires, power outages, systems failures, telecommunications failures and employee error or malfeasance. As a natural gas and oil producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the safety of our employees, threats to the security or operation of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. Cybersecurity attacks in particular are evolving and include, but are not limited to, ransomware or other malicious software, social engineering attacks, deepfakes and artificial intelligence ("AI")-enhanced phishing, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. Threat actors may leverage AI and machine learning, technologies to conduct more sophisticated surveillance, reconnaissance and attacks against our systems. We seek to prevent, detect and investigate cybersecurity incidents, but in some cases, we might be unaware of an incident or its magnitude and effects. Although we utilize various procedures and controls to monitor and protect against these threats and to mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing.
Further, we rely on third-party service providers and technologies on a limited basis to operate business systems to process sensitive information in a variety of contexts, including, without limitation, cloud-based infrastructure, encryption and authentication technology and other similar functions. Our ability to monitor these third parties' information security practices is limited, and these third parties may not have adequate information security measures in place, or they may suffer unexpected power losses or computer system or data network failures that negatively impact the systems or solutions on which we rely. If our third-party service providers experience a security incident or other type of interruption or if an unexpected flaw or failed software update related to third-party software used in our information systems occurs, even if inadvertent, our information systems may become disabled or inaccessible and access to our data and other business information may be limited, which could materially disrupt our operations. If any of these events were to materialize, either to the Company or a third party upon which we rely, they could lead to, without limitation, any of the following:
If any of these events were to materialize, either to the Company or a third party upon which we rely, they could lead to, without limitation, any of the following:
We face a growing regulatory landscape around data protection and cybersecurity incident reporting, including, but not limited to, new SEC rules requiring disclosure of material cybersecurity incidents within specified timeframes which may result in proposed rulemaking affecting incident reporting requirements for our industry.
We had $2.8 billion principal amount of debt as of December 31, 2025.
To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of natural gas, we have entered into and may continue to enter into hedging transactions for certain of our expected natural gas production. These transactions could result in both realized and unrealized hedging losses. Further, these hedges may be inadequate to protect us from continuing and prolonged declines in the price of natural gas. To the extent that natural gas prices remain at current levels or decline further, we will not be able to hedge future production at the same level as our current hedges, and our results of operations and financial condition would be negatively impacted.
We may be subject to physical and financial risks associated with climate-related effects.
Changing climate and weather conditions may create physical and financial risks to our business. Energy needs vary with weather conditions. To the extent weather conditions may be affected by climate change, energy use could increase or decrease depending on the duration and magnitude of any changes. Increased energy use due to weather changes may require us to invest in more infrastructure to serve increased demand. A decrease in energy use due to weather changes may affect our financial condition through decreased revenues. Extreme weather conditions in general require more equipment redundancy, adding to costs, and can contribute to increased risk of delivery disruptions.
Additionally, extreme adverse weather conditions or volatility may lead to higher insurance costs, or a decrease in available coverage, for our assets in areas subject to severe weather. These climate-related changes could damage our physical assets, especially operations located in low-lying areas near coasts and riverbanks, and facilities situated in hurricane-prone and rain-susceptible regions. To the extent the frequency of extreme weather events increases, this could increase our cost of producing products. We may not be able to pass on the higher costs to our customers or recover all costs related to mitigating these physical risks.
Environmental regulations relating to climate change and/or greenhouse gases could also reduce demand for our products or increase our operating and drilling costs. Our business could also be affected by the potential for lawsuits against companies that emit greenhouse gases, based on links drawn between greenhouse gas emissions and climate conditions. To the extent financial markets view GHG emissions as a financial risk, this could negatively impact our cost of and access to capital.
Scrutiny and uncertain expectations from stakeholders with respect to our environmental, social and governance practices may impose additional costs on us or expose us to new or additional risks.
Companies across all industries are facing scrutiny from stakeholders related to their environmental, social and governance ("ESG") practices. Different stakeholders, including investor advocacy groups, certain institutional investors, investment funds, other influential investors, consumers and governmental agencies have varied and often conflicting perspectives on ESG practices. Companies that do not adapt to or comply with investor or other stakeholder expectations and standards, which are evolving, or that are perceived to have not responded appropriately to the growing concern for ESG issues, regardless of whether there is a legal requirement to do so, may suffer from reputational damage and the business, financial condition, and/or stock price of such a company could be materially and adversely affected.
Additionally, adverse effects upon the oil and gas industry related to the worldwide social and political environment, including uncertainty or instability resulting from climate change, changes in political leadership and environmental policies, changes in geopolitical-social views toward fossil fuels and renewable energy, concern about the environmental impact of climate change, and investors' expectations regarding ESG matters, may also adversely affect demand for our products. Any long-term material adverse effect on the natural gas and oil industry could have a significant financial and operational adverse impact on our business.
The occurrence of any of the foregoing could have a material adverse effect on the price of our stock and our business and financial condition.
Management's Discussion & Analysis (MD&A)
New heading “Year Ended December 31, 2025 Compared to Year Ended December 31, 2024”
Removed heading “Year Ended December 31, 2023 Compared to Year Ended December 31, 2022”
Largest changes
“If the qualitative assessment indicates that it is more likely than not that our business is impaired, a quantitative analysis would be performed to assess our fair value and to determine the amount of impairment, if any, that requires recognition. When performing a quantitative impairment assessment of goodwill, fair value is determined based on a market approach or an income approach. If the carrying value of goodwill exceeds the fair value calculated using the quantitative approach, an impairment charge would be recorded for the difference between fair value and carrying value. …”see in full comparison
“Goodwill. We have goodwill of $335.9 million as of December 31, 2024 that was recorded in 2018. Goodwill represents the excess of purchase price over fair value of net tangible and identifiable intangible assets. We are not required to amortize goodwill as a charge to earnings; however, we are required to conduct an annual review of goodwill for impairment. We determine the potential for impairment of our goodwill by initially preparing a qualitative fair value assessment of our business value. …”see in full comparison
“Year Ended December 31, 2025 Compared to Year Ended December 31, 2024”see in full comparison
“Year Ended December 31, 2023 Compared to Year Ended December 31, 2022”see in full comparison
“We recognized $29.1 million of impairments to our non-operated Eagle Ford shale unproved and proved properties in 2025 to adjust the carrying value of our Eagle Ford shale assets to their estimated fair value. We may need to recognize further impairments of our natural gas and oil properties if natural gas and oil prices decline, and as a result, the expected future cash flows from these properties become insufficient to recover their carrying value.”see in full comparison
“Impairment of oil and gas properties. We recorded an impairment to our Eagle Ford shale proved and unproved natural gas and oil properties of $29.1 million in 2025. This charge primarily resulted from diminished activity on our leasehold acreage in the area by operators, low oil prices and our capital allocation strategy, which prioritizes higher-return projects in the Haynesville and Bossier shales.”see in full comparison
Full comparison: every changed paragraph (49)
Prices for natural gas and oil have been highly volatile in recent years but we expect our natural gas production to increase,increase in 2026, assuming we maintain a sufficient development program to offset expected production declines from our producing wells. The level of our drilling activity is dependent on natural gas prices. If we are unable to offset production declines with the new wells we plan to drill in 20252026 and future periods, our production volumes and cash flows from our operating activities may not be sufficient to fund our capital expenditures, and thus, we may need to either curtail drilling activity or seek additional borrowings, which would result in an increase in our interest expense in 20252026 and future periods. We may need to recognize impairments of our natural gas and oil properties if natural gas and oil prices decline, and as a result, the expected future cash flows from these properties become insufficient to recover their carrying value.
We recognized $29.1 million of impairments to our non-operated Eagle Ford shale unproved and proved properties in 2025 to adjust the carrying value of our Eagle Ford shale assets to their estimated fair value. We may need to recognize further impairments of our natural gas and oil properties if natural gas and oil prices decline, and as a result, the expected future cash flows from these properties become insufficient to recover their carrying value.
Year Ended December 31, 2025 Compared to Year Ended December 31, 2024
Our operating data for the year ended December 31, 2025 and 2024 are summarized below:
Natural gas and oil sales. Natural gas and oil sales of $1.4 billion in 2025 increased by $0.4 billion, or 36%, as compared to $1.0 billion in 2024. The increase was primarily due to higher prices received for our natural gas production. Our 2025 natural gas production decreased 15% to 450.2 Bcf (1.2 Bcf per day), which was sold at an average price of $3.17 per Mcf as compared to 527.5 Bcf (1.4 Bcf per day) sold at an average price of $1.98 in 2024.
Gas services revenues. Gas services revenues of $500.2 million in 2025 increased $294.1 million (143%) from $206.1 million in 2024. Gas services activities include sales of natural gas purchased from unaffiliated third parties for resale and fees received from unaffiliated third parties for natural gas gathering and treating services. Gas services revenues increased in 2025 due primarily to higher natural gas prices on sales of natural gas purchased to utilize our excess transport capacity.
Gain on sale of assets. We reported a gain on sale of assets of $291.9 million in 2025, which was primarily related to the divestiture of our Shelby Trough properties in East Texas for net proceeds of $417.2 million. We also sold our interest in our Cotton Valley properties in East Texas and North Louisiana for net proceeds of $15.2 million. In 2024, we sold our interest in certain non-operated properties and realized a gain of $0.9 million.
Production and ad valorem taxes. Our production and ad valorem taxes decreased $17.0 million (30%) to $40.5 million in 2025 from $57.4 million in 2024. This decrease was primarily related to a decrease in Louisiana production tax and ad valorem tax rates and lower natural gas production volumes in 2025.
Gathering and transportation. Gathering and transportation costs decreased $28.8 million (15%) to $166.1 million in 2025 as compared to $194.9 million in 2024. This decrease was due primarily to lower production volumes in 2025.
Lease operating expenses. Our lease operating expense of $122.7 million ($0.27 per Mcfe) in 2025 was $7.8 million, or 6% lower than lease operating expenses in 2024 of $130.5 million ($0.25 per Mcfe). The decrease in lease operating expense was due to lower production volumes as compared to 2024.
Gas services expenses. Gas services expenses of $516.2 million in 2025 were $310.8 million (151%) higher than gas services expenses in 2024 of $205.4 million. The increase was due primarily to higher natural gas prices for purchases of third-party natural gas for resale.
Depreciation, depletion and amortization expense ("DD&A"). DD&A expense decreased $154.2 million (19%) to $641.2 million in 2025 from $795.4 million in 2024. Our DD&A expense per equivalent Mcf produced was $1.42 per Mcfe in 2025 as compared to $1.51 per Mcfe in 2024. The decrease in DD&A rate was primarily due to the increase in estimated proved undeveloped reserves used in determining the DD&A rate, which resulted from the higher natural gas price used in the estimation of proved reserves at December 31, 2025.
General and administrative expenses. General and administrative expenses, which are reported net of overhead reimbursements, increased to $48.7 million in 2025 from $39.4 million in 2024 due primarily to higher personnel costs including stock-based compensation. Stock-based compensation included in general and administrative expenses was $21.2 million and $15.3 million in 2025 and 2024, respectively.
Impairment of oil and gas properties. We recorded an impairment to our Eagle Ford shale proved and unproved natural gas and oil properties of $29.1 million in 2025. This charge primarily resulted from diminished activity on our leasehold acreage in the area by operators, low oil prices and our capital allocation strategy, which prioritizes higher-return projects in the Haynesville and Bossier shales.
Derivative financial instruments. We use derivative financial instruments as part of our price risk management program to protect the cash flow we generate from our operating activities. We had net gains on derivative financial instruments of $82.5 million for 2025 as compared to $10.2 million for 2024. Realized net gains from our natural gas price risk management program were $20.1 million in 2025 as compared to $207.8 million in 2024. We recognized unrealized gains on derivative financial instruments of $62.4 million and unrealized losses of $197.6 million in 2025 and 2024, respectively.
Interest expense. Interest expense was $222.8 million for 2025 as compared to $210.6 million for 2024. Included in interest expense was amortization of the premiums or discounts on our senior notes and the debt issuance cost amortization associated with our outstanding debt. The non-cash interest expense for 2025 totaled $12.0 million compared with $11.5 million for 2024. The increase in interest expense in 2025 was due primarily to the issuance of our 6.75% senior notes in 2024 and increased borrowings on our bank credit facility in 2025.
Exploration expense. Exploration expense was $10.1 million in 2025, which was related to the acquisition of seismic data for our Western Haynesville area.
Income taxes. Our income tax provision was $88.5 million in 2025 as compared to a benefit of $149.1 million in 2024. Our effective tax rate of 17% in 2025 differed from the federal income tax rate of 21% due primarily to research and development and other tax credits claimed in 2025 and state income taxes. Our effective tax rate of 41% in 2024 differed from the federal income tax rate of 21% primarily due to changes in our valuation allowance on our federal and state net operating loss carryforwards and state income taxes.
Net income. We reported net income of $420.2 million or $1.43 per diluted share in 2025 and a net loss of $218.8 million or $0.76 per diluted share in 2024. The net income in 2025 is primarily due to the impact of higher natural gas prices in 2025, gain on sale of assets of $291.9 million and the unrealized gain on our derivative financial instruments of $62.4 million. Income from operations in 2025 was $645.9 million as compared to loss from operations of $168.6 million in 2024.
Our operating data for the year ended December 31, 2024 and 2023 are summarized below:
Natural gas and oil sales. Natural gas and oil sales of $1.0 billion in 2024 decreased by $0.2 billion, or 17%, as compared to $1.3 billion in 2023. The decrease was primarily due to lower prices received for our natural gas production. Our 2024 natural gas production increased 1% to 527.5 Bcf (1.4 Bcf per day), which was sold at an average price of $1.98 per Mcf as compared to 524.5 Bcf (1.4 Bcf per day) sold at an average price of $2.40 in 2023.
Gas services revenues. Gas services revenues of $206.1 million in 2024 decreased $94.4 million (31%) from $300.5 million in 2023. Gas services activities include sales of natural gas purchased from unaffiliated third parties for resale and fees received from unaffiliated third parties for natural gas gathering and treating services. These activities commenced in 2022 with the acquisition of a pipeline and natural gas treating plant and the opportunity to utilize our excess transport capacity in North Louisiana. Gas services revenues decreased in 2024 due primarily to lower natural gas prices on sales of natural gas purchased to utilize our excess transport capacity.
Production and ad valorem taxes. Our production and ad valorem taxes decreased $34.4 million (37%) to $57.4 million in 2024 from $91.8 million in 2023. This decrease was primarily related to a statutory decrease to the Louisiana production tax rate and lower Texas production taxes and ad valorem taxes related to lower natural gas prices in 2024.
Gathering and transportation. Gathering and transportation costs increased $10.0 million (5%) to $194.9 million in 2024 as compared to $184.9 million in 2023. This increase was due to production growth in areas with higher average gathering and transportation rates.
Lease operating expenses. Our lease operating expense of $130.5 million ($0.25 per Mcfe) in 2024 was $1.7 million, or 1% lower than lease operating expenses in 2023 of $132.2 million ($0.25 per Mcfe). The decrease in lease operating expense was due to lower water disposal costs and other production costs as compared to 2023.
Gas services expenses. Gas services expenses of $205.4 million in 2024 were $76.6 million (27%) lower than gas services expenses in 2023 of $282.1 million. The decrease was due primarily to lower natural gas prices for purchases of third-party natural gas for resale.
Depreciation, depletion and amortization expense ("DD&A"). DD&A expense increased $187.5 million (31%) to $795.4 million in 2024 from $607.9 million in 2023 and our DD&A expense per equivalent Mcf produced was $1.51 per Mcfe in 2024 as compared to $1.16 per Mcfe in 2023. The increase in DD&A rate was primarily due to lower estimated proved undeveloped reserves used in determining the DD&A rate, which resulted from the low natural gas price used in the estimation of proved reserves at December 31, 2024.
General and administrative expenses. General and administrative expenses, which are reported net of overhead reimbursements, increased to $39.4 million in 2024 from $38.0 million in 2023 due primarily to higher stock-based compensation. Stock-based compensation included in general and administrative expenses was $15.3 million and $9.9 million in 2024 and 2023, respectively.
Derivative financial instruments. We use derivative financial instruments as part of our price risk management program to protect the cash flow we generate from our operating activities. We had net gains on derivative financial instruments of $10.2 million for 2024 as compared to net gains on derivative financial instruments of $187.6 million for 2023. Realized net gains from our natural gas price risk management program were $207.8 million in 2024 as compared to $80.3 million of realized net gains in 2023. We recognized unrealized losses on derivative financial instruments of $197.6 million and unrealized gains of $107.3 million in 2024 and 2023, respectively.
Interest expense. Interest expense was $210.6 million for 2024 as compared to $169.0 million for 2023. Included in interest expense was amortization of the premiums or discounts on our senior notes and the debt issuance cost amortization associated with our outstanding debt. The non-cash interest expense for 2024 totaled $11.5 million compared with $8.0 million for 2023. The increase in interest expense in 2024 was due primarily to the issuance of our 6.75% senior notes in 2024.
Income taxes. Our income tax benefit was $149.1 million in 2024 as compared to a provision of $35.1 million in 2023. Our effective tax rate of 41% in 2024 differed from the federal income tax rate of 21% due primarily to research and development and other tax credits claimed in 2024, changes in our valuation allowance on our federal and state net operating loss carryforwards and state income taxes, including a reduction in the Louisiana state corporate tax rates. Our effective tax rate of 14% in 2023 differed from the federal income tax rate of 21% primarily due to changes in our valuation allowance on our federal and state net operating loss carryforwards and state income taxes.
Net income. We reported a net loss available to common stockholders of $218.8 million or $(0.76) per diluted share in 2024 and net income available to common stockholders of $211.9 million or $0.76 per diluted share in 2023. The net loss in 2024 is primarily due to the impact of lower natural gas prices in 2024 and the unrealized loss on our derivative financial instruments of $197.6 million. Loss from operations in 2024 was $168.6 million as compared to income from operations of $226.6 million in 2023.
Year Ended December 31, 2023 Compared to Year Ended December 31, 2022
Cash flows from operating activities. Net cash provided by our operating activities decreasedincreased $396.5$279.3 million (39%45%) to $899.6 million in 2025 from $620.3 million in 2024 from $1.0 billion in 2023.2024. The decreaseincrease was primarily due to the lowerhigher natural gas prices we realized in 2024.2025.
Proceeds from asset sales. In 2025, we sold our Shelby Trough properties in East Texas and our Cotton Valley properties in East Texas and North Louisiana and other assets. In 2024, we sold certain non-operated properties for net proceeds of $1.2 million.
Contributions from and distributions to noncontrolling interest. In 2023, we formed a midstream partnership to fund the future build-out of our Western Haynesville midstream system. During 2025 and 2024, our noncontrolling partner contributed $215.5 million and $60.5 million, respectively, to the midstream partnership. Also during 2025 and 2024, we distributed preferred dividends of $16.5 million and $3.7 million, respectively, to our noncontrolling partner.
Contributions from noncontrolling interest. In 2023, we formed a midstream partnership to fund the future build-out of our Western Haynesville midstream system. During 2024 and 2023, our noncontrolling partner contributed $60.5 million and $24.0 million, respectively, to the midstream partnership.
Proceeds from asset sales. In 2024, we sold certain non-operated properties for net proceeds of $1.2 million. In 2023, we sold certain non-operated properties for net proceeds of $41.3 million.
Capital expenditures. The decreaseincrease in capital expenditures of $373.6$258.8 million is primarily due to lowerhigher drilling and completion activities in 2024.2025.
Common stock dividends. In 2023, we paid a quarterly cash dividend of 12.5¢ per share of common stock. We did not pay a dividend in 2024.
As of December 31, 2024,2025, we had $415.0$260.0 million outstanding under a bank credit facility. Aggregate commitments under the credit facility are $1.5 billion, which matures on November 15, 2027. Borrowings under the bank credit facility are subject to a borrowing base, which is currently set at $2.0 billion. The borrowing base is re-determined on a semi-annual basis and upon the occurrence of certain other events. Borrowings under the bank credit facility are secured by substantially all of our assets and those of our restricted subsidiaries and bear interest at our option, at either adjusted SOFR plus 2.25% to 3.25% or an alternate base rate plus 1.25% to 2.25%, in each case depending on the utilization of the borrowing base. We also pay a commitment fee of 0.375% to 0.5% on the unused portion of the committed borrowing base. The bank credit facility places certain restrictions upon our and our restricted subsidiaries' ability to, among other things, incur additional indebtedness, pay cash dividends, repurchase common stock, make certain loans, investments and divestitures and redeem our senior notes. The only financial covenants are the maintenance of a leverage ratio of less than 4.0 to 1.0, which reduces to 3.75 to 1.0 on June 30, 2025 and to 3.5 to 1.0 on September 30, 2025 and an adjusted current ratio of at least 1.0 to 1.0. We were in compliance with the covenants as of December 31, 2024.2025.
We expect to fund our future development and exploration activities with future operating cash flow.flow or borrowings under our bank credit facility. The timing of most of our capital expenditures is mostly discretionary. We have a significant degree of flexibility to adjust the level of our capital expenditures as circumstances warrant. If our plans or assumptions change or prove to be inaccurate, we may be required to seek additional capital, including debt or equity financing. We expect to fund future acquisitions, depending on the size and timing, with future operating cash flow, borrowings under our bank credit facility, or other debt or equity financings, to the extent available. The availability and attractiveness of debt or equity financing will depend upon a number of factors, some of which will relate to our financial condition and performance and some of which will be beyond our control, such as prevailing interest rates, natural gas and oil prices and other market conditions. We cannot provide any assurance that we will be able to obtain such capital, or if such capital is available, that we will be able to obtain it on acceptable terms.
Our contractual obligations consist primarily of natural gas transportation and gathering contracts, principal and interest payments on our senior notes and bank credit facilityfacility, natural gas transportation and gathering contracts and other operating lease obligations. Interest payments under our senior notes and bank credit facility are $182.6 million for 2026, $180.6 million for 2027, $166.3 million for 2028, $75.0 million for 2029 and $2.4 million for 2030. Our natural gas transportation and gathering contracts extend to 2031 and commitments under these contracts are $84.4 million for 2025, $91.6$85.4 million for 2026, $90.0$84.2 million for 2027, $82.9$79.3 million for 2028, $73.8$67.6 million for 20292029, $27.7 million for 2030 and $98.0$58.9 million for commitments thereafter. Interest payments under our senior notes and bank credit facility are $196.6 million for 2025 and 2026, $192.8 million for 2027, $166.3 million for 2028, $75.0 million for 2029 and $2.4 million for all periods thereafter.
On December 31, 2024,2025, we had $743.0$1.4 millionbillion in U.S. federal net operating loss carryforwards andcarryforwards, $1.8 billion in certain state net operating loss carryforwards.carryforwards, $17.7 million of U.S. federal research and development tax credits and $11.0 million of certain state research and development tax credits. As a result of a change of control in August 2018, our ability to use U.S. federal net operating losses ("NOLs") to reduce taxable income is limited. If we do not generate a sufficient level of taxable income prior to the expiration of the pre-2018 NOL carry-forward periods, then we will lose the ability to apply those NOLs as offsets to future taxable income. We estimate that $740.6 million of the U.S. federal NOL carryforwards and $1.2 billion of the estimated state NOL carryforwards will expire unused.
Our federal income tax returns for the years subsequent to December 31, 20202021 remain subject to examination. Our income tax returns in major state income tax jurisdictions remain subject to examination for various periods subsequent to December 31, 2021.2022. Currently, we are under examination with the United States Internal Revenue Service and the state of Louisiana and we believe that our significant filing positions are highly certain and that all of our other significant income tax filing positions and deductions wouldwill be sustained uponunder audit or the final resolution wouldwill not have a material effect on our consolidated financial statements. Therefore, we have not established any significant reserves for uncertain tax positions.
In July 2025, the One Big Beautiful Bill Act ("OBBBA") was signed into United States federal law. We have benefited from certain provisions contained in the OBBBA, including increased interest expense deductions and bonus depreciation, which are included in our income tax provision for the year ending December 31, 2025.
Impairment of natural gas and oil properties. We evaluate our proved properties for potential impairment when circumstances indicate that the carrying value of an asset may not be recoverable. If impairment is indicated based on a comparison of the asset's carrying value to its undiscounted expected future net cash flows, then it is recognized to the extent that the carrying value exceeds fair value. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Expected future cash flows are determined using estimated future prices based on market based forward prices applied to projected future production volumes. The projected production volumes are based on the property's proved and risk adjusted probable natural gas and oil reserves estimates at the end of the period. The estimated future cash flows that we use in our assessment of the need for an impairment are based on a corporate forecast which considers forecasts from multiple independent price forecasts. Prices are not escalated to levels that exceed observed historical market prices. Costs are also assumed to escalate at a rate that is based on our historical experience, currently estimated at 2% per annum. The natural gas and oil prices used for determining asset impairments will generally differ from those used in the standardized measure of discounted future net cash flows because the standardized measure requires the use of the average first day of the month historical price for the year. Unproved properties are evaluated for impairment based upon the results of drilling, planned future drilling and the terms of our natural gas and oil leases. During 2025, we recognized impairment charges of $29.1 million to reduce the capitalized costs of our proved and unproved natural gas and oil properties in the Eagle Ford shale to their fair value. It is reasonably possible that our estimates of undiscounted future net cash flows attributable to our natural gas and oil properties may change in the future. The primary factors that may affect estimates of future cash flows include future adjustments, both positive and negative, to proved and appropriate risk-adjusted probable natural gas and oil reserves, results of future drilling activities, future prices for natural gas and oil, and increases or decreases in production and capital costs. As a result of these changes, there may be further impairments in the carrying values of our proved and unproved natural gas and oil properties in the future.
Goodwill. We have goodwill of $335.9 million as of December 31, 2024 that was recorded in 2018. Goodwill represents the excess of purchase price over fair value of net tangible and identifiable intangible assets. We are not required to amortize goodwill as a charge to earnings; however, we are required to conduct an annual review of goodwill for impairment. We determine the potential for impairment of our goodwill by initially preparing a qualitative fair value assessment of our business value. In performing this qualitative assessment, we examine relevant events and circumstances that could have a negative effect on our business, including macroeconomic conditions, industry and market conditions (including current commodity price), earnings and cash flows, overall financial performance and other relevant entity specific events.
If the qualitative assessment indicates that it is more likely than not that our business is impaired, a quantitative analysis would be performed to assess our fair value and to determine the amount of impairment, if any, that requires recognition. When performing a quantitative impairment assessment of goodwill, fair value is determined based on a market approach or an income approach. If the carrying value of goodwill exceeds the fair value calculated using the quantitative approach, an impairment charge would be recorded for the difference between fair value and carrying value. If oil or natural gas prices decrease, drilling efforts are unsuccessful or our market capitalization declines, it is reasonably possible that impairments would need to be recognized. We performed a quantitative assessment of goodwill as of October 1, 2024 and determined there was no goodwill impairment.
What changed in the latest 10-Q
Risk Factors
We are subject to various risks and uncertainties in the course of our business. For a discussion of such risks and uncertainties, please see "Item 1A. Risk Factors" in the Annual Report. There have been no material changes to the Risk Factors we have disclosed in the Annual Report.
No wording changes found in this section.
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Management's Discussion & Analysis (MD&A)
Largest changes
As ofsee in full comparisonMarchJune31,30, 2026, PGS had$47.0nomillionborrowings outstanding underaits bank credit facility. Aggregate commitments under the PGS bank credit facility are $150 million, which matures on March 26, 2030. Borrowings under the PGS bank credit facility bear interest at our option, at either SOFR plus 2.5% to 3.5% or an alternate base rate plus 1.5% to 2.5%, in each case depending on a consolidated net leverage ratio. PGS also pays a commitment fee of 0.375% to 0.5%, which is dependent on the PGS consolidated net leverage ratio. The PGS bank credit facility contains financial covenants that require the maintenance of an interest coverage ratio of at least 2.5 to 1.0 and a consolidated net leverage ratio of less than 4.0 to 1.0. PGS was in compliance with the covenants as of June 30, 2026.
We reported net income available to the Company ofsee in full comparison$112.5$8.8million, or $0.38 per sharemillion for the quarter endedMarchJune31,30,2026.2026 as compared to net income available to the Company of $124.8 million for the quarter ended June 30, 2025. Income from operations for thefirstsecond quarter of 2026 was$174.9$22.6 million as compared to income from operations of$126.2$89.4 million for the second quarter of 2025. In the first six months of 2026, we reported net income available to the Company of $116.2 million as compared to net income available to the Company of $3.6 million for the firstquartersix months of 2025.WeIncomereportedfroma net loss of $115.4 million or $0.40 per shareoperations for thequarterfirstendedsixMarchmonths31,of 2026 was $197.5 million as compared to income from operations of $215.6 million for the first six months of 2025.
Depreciation, depletion and amortization ("DD&A")see in full comparisondecreasedincreased$26.4$9.1 million to$141.5$167.4 million in thefirstsecond quarter of 2026 from$167.9$158.4 million in thefirstsecond quarter of2025 due to lower natural gas production in the first quarter of 2026.2025. Our DD&A per equivalent Mcf produced was$1.45$1.48 per Mcfe for the quarter endedMarchJune31,30, 2026 as compared to $1.41 per Mcfe for the quarter ended June 30, 2025. The increase was due primarily to higher finding and development costs in 2026. DD&A decreased $17.3 million to $309.0 million for the first six months of 2026 from $326.3 million during the first six months of 2025. Our DD&A per equivalent Mcf produced was $1.46 per Mcfe for the six months ended June 30, 2026, which was comparable to$1.46$1.44 per Mcfe for thequartersix months endedMarchJune31,30, 2025.
We use derivative financial instruments as part of our price risk management program to protect our capital investments. During the quarter endedsee in full comparisonMarchJune31,30, 2026, we had net gains related to our derivative financial instruments of$2.4$44.4 million, as compared to netlossesgains on derivative financial instruments of$330.3$235.8 million during the quarter endedMarchJune31,30, 2025, resulting from thedeclinedecrease in future natural gas prices since June 30, 2025. Realized net gains from our price risk management program were $43.3 million for the quarter ended June 30, 2026 as compared to realized net gains of $4.3 million for the quarter ended June 30, 2025. Net gains on derivative financial instruments were $46.8 million for the first six months of 2026 as compared to net losses of $94.5 million for the first six months of 2025, resulting from a decrease in future natural gas prices since December 31, 2025. Realized net losses from our price risk management program were$80.4$37.1 million for thequarterfirstendedsixMarchmonths31,of 2026 as compared to realized net losses of$8.0$3.7 million for thequarterfirstendedsixMarchmonths31,of 2025.
General and administrative expenses, which are reported net of overhead reimbursements, increased tosee in full comparison$18.2$17.2 million for thefirstsecond quarter of 2026 as compared to$11.1$12.3 million in thefirstsecond quarter of 2025. General and administrative expenses increased to $35.4 million for the six months ended June 30, 2026 as compared to $23.4 million for the six months ended June 30, 2025. Theincreaseincreaseswasin both periods were primarily due to higheremployee compensation, includingstock-based compensation, which increased to$7.4$8.4 million in thefirstsecond quarter of 2026 as compared to$4.4$5.5 million in thefirstsecond quarter of 2025, and a reduction in overhead reimbursements resulting from the property divestitures completed in 2025. For the six months ended June 30, 2026, stock-based compensation increased to $15.8 million as compared to $10.0 million for the same period in 2025.
“Natural gas and oil sales of $707.3 million for the six months ended June 30, 2026 decreased by $45.7 million (6%) as compared to $753.0 million for the six months ended June 30, 2025, which was primarily attributable to lower natural gas production, which decreased 7% to 210.9 Bcf (1.2 Bcf per day) during the first six months of 2026. Natural gas prices increased by 1% during the first six months of 2026 as compared to 2025 natural gas prices. Our natural gas production for the first six months of 2025 was 227.2 Bcf (1.3 Bcf per day) and was sold at an average price of $3.31 per Mcf.”see in full comparison
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This report contains forward-looking statements that involve risks, uncertainties and assumptions that are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 including those described under the heading "Risk Factors" in our Annual Report on Form 10-K for the year ended December 31, 2025 (the "Annual Report"). All statements other than statements of historic facts contained, or incorporated by reference, in this report, may be forward-looking statements. Actual results may differ materially from those anticipated in our forward-looking statements due to many factors. Such forward-looking statements are based on management's current expectations and are subject to a number of factors and uncertainties which could cause actual results to differ materially from those described herein. Although the we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. You are cautioned not to place undue reliance on the forward-looking statements included in this report, which speak only as of the date made. We expressly disclaim any obligation or undertaking to release publicly any updates or revisions to any forward-looking statement to reflect any change in our expectations with regard thereto or any change of events, conditions or circumstances on which any such statement was based, except as required by law. The following discussion should be read in conjunction with the consolidated financial statements and notes thereto included in this report and in our Annual Report as well as with the Risk Factors contained in our Annual Report.
Natural gas and oil sales of $419.0$288.2 million for the three months ended MarchJune 31,30, 2026 increaseddecreased by $6.0$51.7 million (1%15%) as compared to $413.0$340.0 million for the firstsecond quarter of 2025. The increasedecrease was due to higherlower natural gas prices realized in the firstsecond quarter of 2026 as compared to the same period in 2025. The average realized price for our natural gas was $4.27$2.54 per thousand cubic feet ("Mcf"), which increaseddecreased 19%16% from the average realized natural gas price in the firstsecond quarter of 2025. Our natural gas production for the firstsecond quarter of 2026 decreasedincreased 15%1% to 97.9113.1 billion cubic feet ("Bcf") (1.11.2 Bcf per day). Natural gas production for the firstsecond quarter of 2025 was 115.0112.2 Bcf (1.31.2 Bcf per day) and was sold at an average price of $3.58$3.02 per Mcf.
Natural gas and oil sales of $707.3 million for the six months ended June 30, 2026 decreased by $45.7 million (6%) as compared to $753.0 million for the six months ended June 30, 2025, which was primarily attributable to lower natural gas production, which decreased 7% to 210.9 Bcf (1.2 Bcf per day) during the first six months of 2026. Natural gas prices increased by 1% during the first six months of 2026 as compared to 2025 natural gas prices. Our natural gas production for the first six months of 2025 was 227.2 Bcf (1.3 Bcf per day) and was sold at an average price of $3.31 per Mcf.
Gas service revenues of $166.5$63.5 million increaseddecreased $66.6$66.8 million (67%51%) for the firstsecond quarter of 2026 from $99.9$130.3 million in the firstsecond quarter of 2025. Gas service revenues of $230.0 million decreased $0.2 million for the first six months of 2025 from $230.2 million for the first six months of 2025. The increasesdecreases were primarily due to higherlower natural gas prices related to sales of natural gas purchased to utilize our excess transport capacity.
We reported a gain on sale of assets of $1.8 million for the first quarter of 2026, which was primarily due to post-closing adjustments related to the divestiture of our Shelby Trough properties in East Texas during the fourth quarter of 2025.
Our production and ad valorem taxes decreased $0.8$3.4 million (7%32%) to $10.4$7.2 million for the firstsecond quarter of 2026 from $11.2$10.6 million in the firstsecond quarter of 2025. Production and ad valorem taxes decreased $4.1 million (19%) to $17.6 million during the first six months of 2026 from $21.7 million during the first six months of 2025. The decreasedecreases waswere due primarily due to lowerthe productionsale of producing properties in the firstprior quarterperiods ofand 2026.changes in natural gas prices.
Gathering and transportation costs for the firstsecond quarter of 2026 decreasedincreased $0.8$1.6 million (2%4%) to $41.8$43.3 million as compared to $42.6$41.8 million in the firstsecond quarter of 2025. Gathering and transportation costs during the first six months of 2026 increased $0.8 million (1%) to $85.1 million as compared to the first six months of 2025. The decreaseincreases wasin both periods were due primarily to lowerproduction production.growth in areas with higher average gathering and transportation rates.
Our lease operating expense of $28.3$28.2 million ($0.29$0.25 per Mcfe) for the firstsecond quarter of 2026 decreased $6.7$3.0 million (19%10%) as compared to our lease operating expense of $35.0$31.1 million ($0.30$0.28 per Mcfe) for the firstsecond quarter of 2025. Lease operating expense of $56.4 million ($0.27 per Mcfe) during the first six months of 2026 decreased $9.7 million (15%) from lease operating expense of $66.1 million ($0.29 per Mcfe) during the first six months of 2025. The decreasedecreases waswere due primarily to lowerthe productionsale of producing properties in the firstprior three months of 2026.periods.
Gas service expenses of $162.9$63.0 million increaseddecreased $46.1$63.7 million (39%50%) for the firstsecond quarter of 2026 from $116.8$126.7 million in the firstsecond quarter of 2025. Gas service expenses of $225.9 million decreased $17.6 million (7%) for the first six months of 2026 from $243.5 million for the first six months of 2025. The increasedecreases waswere primarily due to higherlower natural gas prices and volumes related to purchases of third party natural gas for resale.
Depreciation, depletion and amortization ("DD&A") decreasedincreased $26.4$9.1 million to $141.5$167.4 million in the firstsecond quarter of 2026 from $167.9$158.4 million in the firstsecond quarter of 2025 due to lower natural gas production in the first quarter of 2026.2025. Our DD&A per equivalent Mcf produced was $1.45$1.48 per Mcfe for the quarter ended MarchJune 31,30, 2026 as compared to $1.41 per Mcfe for the quarter ended June 30, 2025. The increase was due primarily to higher finding and development costs in 2026. DD&A decreased $17.3 million to $309.0 million for the first six months of 2026 from $326.3 million during the first six months of 2025. Our DD&A per equivalent Mcf produced was $1.46 per Mcfe for the six months ended June 30, 2026, which was comparable to $1.46$1.44 per Mcfe for the quartersix months ended MarchJune 31,30, 2025.
General and administrative expenses, which are reported net of overhead reimbursements, increased to $18.2$17.2 million for the firstsecond quarter of 2026 as compared to $11.1$12.3 million in the firstsecond quarter of 2025. General and administrative expenses increased to $35.4 million for the six months ended June 30, 2026 as compared to $23.4 million for the six months ended June 30, 2025. The increaseincreases wasin both periods were primarily due to higher employee compensation, including stock-based compensation, which increased to $7.4$8.4 million in the firstsecond quarter of 2026 as compared to $4.4$5.5 million in the firstsecond quarter of 2025, and a reduction in overhead reimbursements resulting from the property divestitures completed in 2025. For the six months ended June 30, 2026, stock-based compensation increased to $15.8 million as compared to $10.0 million for the same period in 2025.
We use derivative financial instruments as part of our price risk management program to protect our capital investments. During the quarter ended MarchJune 31,30, 2026, we had net gains related to our derivative financial instruments of $2.4$44.4 million, as compared to net lossesgains on derivative financial instruments of $330.3$235.8 million during the quarter ended MarchJune 31,30, 2025, resulting from the declinedecrease in future natural gas prices since June 30, 2025. Realized net gains from our price risk management program were $43.3 million for the quarter ended June 30, 2026 as compared to realized net gains of $4.3 million for the quarter ended June 30, 2025. Net gains on derivative financial instruments were $46.8 million for the first six months of 2026 as compared to net losses of $94.5 million for the first six months of 2025, resulting from a decrease in future natural gas prices since December 31, 2025. Realized net losses from our price risk management program were $80.4$37.1 million for the quarterfirst endedsix Marchmonths 31,of 2026 as compared to realized net losses of $8.0$3.7 million for the quarterfirst endedsix Marchmonths 31,of 2025.
Interest expense was $53.1$55.0 million and $54.8$55.2 million for the quarters ended MarchJune 31,30, 2026 and 2025, respectively, and $108.1 million and $110.0 million for six months ended June 30, 2026 and 2025, respectively. The decrease in interest expense was due primarily to decreased borrowings on our bank credit facility.
Exploration expense was $9.3$4.4 million for the firstsecond quarter of 20262026, asand comparedexploration toexpense was $13.8 million and $2.2 million for the firstsix quartermonths ofended June 30, 2026 and 2025, respectively, which waswere related to the acquisition of seismic data in our Western Haynesville area.
Income taxes for the quarters ended MarchJune 31,30, 2026 and 2025 were a benefit of $2.8 million and a provision of $141.5 million, respectively. Income taxes for the six months ended June 30, 2026 and 2025 were a provision of $12.0$9.2 million and a benefit of $143.3$1.8 million, respectively. Income taxes for the quarters ended MarchJune 31,30, 2026 and 2025 reflect an effective tax rate of 9.6%(23.3)% and 55.4%,52.0%, respectively, and income taxes for the six months ended June 30, 2026 and 2025 reflect an effective tax rate of 6.7% and (13.2)%, respectively. The difference between the federal statutory tax rate of 21% and our effective rate is primarily attributable to research and development and other tax credits, release of valuation allowance on deferred tax assets, state income taxes, changes in certain nondeductible items and the income attributable to noncontrolling interest.
We reported net income available to the Company of $112.5$8.8 million, or $0.38 per sharemillion for the quarter ended MarchJune 31,30, 2026.2026 as compared to net income available to the Company of $124.8 million for the quarter ended June 30, 2025. Income from operations for the firstsecond quarter of 2026 was $174.9$22.6 million as compared to income from operations of $126.2$89.4 million for the second quarter of 2025. In the first six months of 2026, we reported net income available to the Company of $116.2 million as compared to net income available to the Company of $3.6 million for the first quartersix months of 2025. WeIncome reportedfrom a net loss of $115.4 million or $0.40 per shareoperations for the quarterfirst endedsix Marchmonths 31,of 2026 was $197.5 million as compared to income from operations of $215.6 million for the first six months of 2025.
Cash flows from operating activities. Net cash provided by our operating activities increaseddecreased $97.2$80.1 million (56%15%) to $272.0$442.2 million in the first threesix months of 2026 from $174.7$522.3 million in the same period in 2025. The increasedecrease was due primarily to higherlower natural gas production and lower realized natural gas prices.
Contributions and redemption of noncontrolling interest. On June 15, 2026, PGS redeemed Cactus' interest in PGS for $445 million. The redemption was funded by the issuance of 600,000 Class A-2 Units representing a 27% ownership interest in PGS for $600 million to Starville, net of $18.5 million in related transaction costs.
Contributions from noncontrolling interest. During the first three months of 2025, our noncontrolling interest partner contributed $59.5 million to our midstream partnership to fund the build-out of our Western Haynesville midstream system.
We drilled 1734 (15.330.9 net) wells and completed 1329 (11.724.4 net) Haynesville and Bossier shale operated wells during the first threesix months of 2026. We currently expect to spend an additional $1.1$720 billionmillion to $1.2$820 billionmillion in the remaining ninesix months of 2026 on drilling, completion, infrastructure and other activity.
As of MarchJune 31,30, 2026, we had $1.27$1.2 billion of liquidity, comprised of $1.15$1.1 billion of unused borrowing capacity under our bank credit facilities and $14.8$45.0 million of cash and cash equivalents on hand. $103$150 million of unused borrowing capacity under our PGS bank credit facility is restricted to PGS midstream activities. Our short and long-term capital requirements consist primarily of funding our development, exploration and midstream activities, acquisitions, payments of contractual obligations and debt service.
As of MarchJune 31,30, 2026, we had $350.0$545.0 million outstanding under the Comstock bank credit facility. Aggregate commitments under this bank credit facility are $1.5 billion, which matures on November 15, 2027. Borrowings under our bank credit facility are subject to a borrowing base that is currently set at $2.0 billion. The borrowing base is re-determined on a semi-annual basis and upon the occurrence of certain other events. Borrowings under the Comstock bank credit facility are secured by substantially all of our assets and those of our subsidiaries, except for PGS, and bear interest at our option at either adjusted SOFR plus 2.25% to 3.25% or an alternate base rate plus 1.25% to 2.25%, in each case depending on the utilization of the borrowing base. We also pay a commitment fee of 0.375% to 0.5%, which is dependent on the utilization of the borrowing base. Comstock's bank credit facility places certain restrictions upon our and our restricted subsidiaries' ability to, among other things, incur additional indebtedness, pay cash dividends, repurchase common stock, make certain loans, investments and divestitures and redeem the senior notes. The only financial covenants are the maintenance of a leverage ratio of less than 3.5 to 1.0, and an adjusted current ratio of at least 1.0 to 1.0. We were in compliance with the covenants as of MarchJune 31,30, 2026.
As of MarchJune 31,30, 2026, PGS had $47.0no millionborrowings outstanding under aits bank credit facility. Aggregate commitments under the PGS bank credit facility are $150 million, which matures on March 26, 2030. Borrowings under the PGS bank credit facility bear interest at our option, at either SOFR plus 2.5% to 3.5% or an alternate base rate plus 1.5% to 2.5%, in each case depending on a consolidated net leverage ratio. PGS also pays a commitment fee of 0.375% to 0.5%, which is dependent on the PGS consolidated net leverage ratio. The PGS bank credit facility contains financial covenants that require the maintenance of an interest coverage ratio of at least 2.5 to 1.0 and a consolidated net leverage ratio of less than 4.0 to 1.0. PGS was in compliance with the covenants as of June 30, 2026.
At MarchJune 31,30, 2026, we had $1.5 billion in U.S. federal net operating loss ("NOL") carryforwards and $1.9$2.0 billion in certain state NOL carryforwards. As a result of the change of control in August 2018, our ability to use NOLs to reduce taxable income is limited. If we do not generate a sufficient level of taxable income prior to the expiration of the pre-2018 NOL carryforward periods, then we will lose the ability to apply those NOLs as offsets to future taxable income. We estimate that $720.7 million of the U.S. federal NOL carryforwards and $1.2 billion of the estimated state NOL carryforwards will expire unused.
In Part II, Item 7 of our 2025the Annual Report, we disclosed our critical accounting policies and estimates, which are made in accordance with GAAP, involve a significant level of estimation uncertainty and have had or are reasonably likely to have a material impact on our financial condition or results of operation. There have been no significant changes to our critical accounting policies and estimates during the threesix months ended MarchJune 31,30, 2026, as compared to those disclosed in the 2025 Annual Report.
CRK insider buying and selling (Form 4)
Since 2026-04-11, insiders reported open-market purchases in 0 Form 4 filings and open-market sales in 0 filings. Totals add up every open-market (code P and S) line in those filings, using the prices reported in the filings. Awards, option exercises, tax withholding and gifts are listed below but not counted.
| Trade date | Insider | Transaction | Shares | Price | Value |
|---|---|---|---|---|---|
| 2026-06-06 | Sanders Larae Lynn |
Shares withheld for tax | 1,054 | $13.00 | $13.7K |
| 2026-06-06 | Presley Daniel K |
Shares withheld for tax | 1,092 | $13.00 | $14.2K |
| 2026-06-06 | Newell Clifford Doyle Iii |
Shares withheld for tax | 2,651 | $13.00 | $34.5K |
| 2026-06-06 | Mills Ronald Eugene |
Shares withheld for tax | 1,189 | $13.00 | $15.5K |
| 2026-06-06 | Mcgough Patrick |
Shares withheld for tax | 1,127 | $13.00 | $14.7K |
| 2026-06-06 | Harrison Daniel S |
Shares withheld for tax | 6,693 | $13.00 | $87.0K |
| 2026-06-06 | Claunch Brian Christopher |
Shares withheld for tax | 1,251 | $13.00 | $16.3K |
| 2026-06-06 | Burns Roland O |
Shares withheld for tax | 24,405 | $13.00 | $317.3K |
| 2026-06-06 | Allison M Jay |
Shares withheld for tax | 35,879 | $13.00 | $466.4K |
| 2026-06-02 | Turner Jim L |
Grant/award | 14,870 | $13.45 | $200.0K |
| 2026-06-02 | Foster Morris E |
Grant/award | 14,870 | $13.45 | $200.0K |
| 2026-06-02 | Davis Elizabeth B |
Grant/award | 14,870 | $13.45 | $200.0K |
Well-known investors holding CRK (13F)
| Investor | Quarter | Shares | Reported value | % of their 13F | Change vs prior quarter |
|---|---|---|---|---|---|
| Point72 Asset Management (Steve Cohen) | 2026-06-30 | 1,284,883 | $27.1M | — | Sold out |
| Citadel Advisors (Ken Griffin) | 2026-06-30 | 292,851 | $4.4M | 0.0% | Reduced 47% |
| Renaissance Technologies | 2026-06-30 | 238,700 | $3.6M | 0.0% | Added 81% |
| Two Sigma Investments | 2026-06-30 | 49,102 | $732.6K | 0.0% | Added 98% |
| Millennium Management (Israel Englander) | 2026-06-30 | 41,269 | $615.7K | 0.0% | Reduced 83% |
| AQR Capital Management (Cliff Asness) | 2026-06-30 | 34,699 | $517.7K | 0.0% | Added 11% |
| D. E. Shaw & Co. | 2026-06-30 | 25,608 | $382.1K | 0.0% | Reduced 81% |