REPX 10-K & 10-Q changes, risk factors and insider trading

The Company is subject to various risks and uncertainties in the ordinary course of business. The following summarizes significant risks and uncertainties that may adversely affect our business, financial condition or results of operations. Other risks are described in Item 1 and 2. Business and Properties, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 7A. Quantitative and Qualitative Disclosures About Market Risk. We could also face additional risks and uncertainties not currently known to us or that we currently deem to be immaterial. If any of these risks actually occurs, it could materially harm our business, financial condition or results of operations and the trading price of our sharesstock could decline. Investors should carefully consider each of the following risk factors and all of the other information set forth in this Annual Report.

In recent years, the NMOCD and the RRC have each imposed stricter requirements for oil and gas wastewater injection activities in response to seismic activity in the Permian Basin, including the imposition of additional analysis, reporting, injection rate reduction or curtailment, and notification requirements on operators depending on the number and intensity of seismic events andand, in certain areasareas, suspended issuance of new SWD well permits, as well as suspended or limited existing disposal well permits. These actions have and are being taken in an effort to control induced seismic activity and recent increases in earthquakes in the Permian Basin, which have been linked by the U.S. and local seismologists to wastewater disposal in oilfields. These restrictions on the disposal of produced water and a moratorium on new produced water disposal wells could result in increased operating costs, requiring us or our service providers to truck produced water, recycle it or dispose of it by other means, all of which could be costly. We or our service providers may also need to limit disposal well volumes, disposal rates and pressures or locations, or require us or our service providers to shut down or curtail the injection of produced water into disposal wells. These factors may make drilling activity in the affected parts of the Permian Basin less economical and adversely impact our business, results of operations and financial condition.

Historically, one of the key drivers in the unconventional resource industry has been growth in production and reserves. With historical volatility in oil and natural gas prices and the potential for rising interest rates willwhich may increase the cost of borrowing, capital efficiency and free cash flow from earnings have become the key drivers for energy companies, particularly shale producers. Such shifts in focus sometimes require changes in planning and resource management, which may not occur instantaneously. Any delay in responding to such changes in market sentiment or perception may result in the investment community having a negative sentiment regarding our business plan, potential profitability and our ability to operate in a manner deemed "efficient," which may have a negative impact on the price of our common stock.

During the year ended December 31, 2024,2025, the Company recognized an impairment lossesloss on proved properties relatingof $1.2 million related to certain properties in Texas outside of the Company's acreage in the Champions field and certain properties in New Mexico outside of the Company's acreage in the Red Lake field. The impairmentsimpairment werewas primarily driven by a reduction in reservewell volumeresults due toand lower wellcommodity performance assessments based on historical trends. The affected areas included nine operated producing wells.prices.

Our exploration, developmentexploration and midstreamdevelopment projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our reserves.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the exploration, exploitation, development and acquisition of oil and natural gas reserves and the construction of midstream gathering, compression and pipeline facilities.reserves. We expect to fund our growth primarily through cash flow from operations, availability under our Credit Facility, and subsequent equity or debt offerings when appropriate. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil, natural gas and NGL prices, actual drilling results, the availability of drilling rigs and other services and equipment, construction delays in our midstream project, cost of materials, regulatory, technological and competitive developments, and worldwide and regional economic conditions. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production.

Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs, and potential liabilities, including environmental liabilities. Such assessments are inexact, inherently uncertain, and often time-constrained. For these reasons, the properties we have acquired or will acquire in the future may not produce as projected or may be more costly to operate than projected. In connection with the assessments, we perform a review of the subject properties, but such a review will not reveal all existing or potential problems. In the course of our due diligence, we may not review every well, pipeline or associated facility. We cannot necessarily observe structural and environmental problems, such as pipe corrosion or subsurface or groundwater contamination, when a review is performed. We may be unable to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical and environmental condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

The present value of future net revenues from our reserves should not be assumed to represent the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. For example, our estimated proved reserves as of December 31, 2024,2025, were calculated under SEC rules using the unweighted arithmetic average of the first-day-of-the-month prices for the prior 12 months of $76.32$65.34 per Bbl for oil and NGL volumes and $2.13$3.39 per MMBtu for natural gas volumes.volumes, prior to adjustment for quality, energy content, GP&T costs and market differentials. Using lower prices in estimating proved reserves would likely result in a reduction in proved reserve volumes due to economic limits.

Substantially all of our producing properties are located in the Northwest Shelf within the Permian Basin of West Texas and Southeastern New Mexico, making us vulnerable to risks associated with operating in one major geographic area. Specifically, as the Permian Basin is an area of high industry activity, we may be unable to hire, train, or retain qualified personnel needed to manage and operate our assets. There is also limited availability of qualified third-parties to perform certain services required for operations, regulatory and environmental compliance.

At December 31, 2024,2025, the majority of our total estimated proved reserves were attributable to properties located in the Northwest Shelf within the Permian Basin of West Texas and Southeastern New Mexico, an area in which industry activity has increased rapidly. As a result of this concentration, a number of our properties could experience any of the same conditions at the same time and, when compared to other companies that have a more diversified portfolio of properties, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints or disruptions, electric power limitations, market limitations, water shortages or other drought or extreme weather related conditions or interruption of the processing or transportation of oil, natural gas or NGLs. For example, bottlenecks in processing and transportation that have occurred in some recent periods in the Permian Basin may negatively affect our results of operations, and these adverse effects may be disproportionately severe to us compared to our more geographically diverse competitors.

The marketing of oil and natural gas production depends in large part on the capacity and availability of pipelines and storage facilities, trucks, gas gathering systems and other transportation, processing and refining facilities. Access to such facilities is, in many respects, beyond our control. If these facilities are unavailable to us on commercially reasonable terms or otherwise (either temporarily or long-term), we could be forced to shut in some production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons, as was the case in Julycertain months of 2025, 2024 and August 2023 and in July 2024 when our producing wells in the Red Lake field in New Mexico were shut in due to unexpected maintenance issues with our third party processor.processors. We rely on facilities developed and owned by third parties in order to store, process, transmit, and sell our oil and natural gas production, and even once our planned gathering, compression and pipeline projects are completed, we still expect to rely on third-party facilities. Until our planned pipeline is constructed to connect with our new midstream counterparty's facilities, we are operating under a month-to-month arrangement with our current midstream counterparty, which could be terminated at any time.production. Our plans to develop and sell our oil and natural gas reserves, the expected results of our drilling program and our cash flow and results of operations could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient facilities and services to us on commercially reasonable terms or otherwise. The amount of oil and natural gas that can be produced is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, damage to the gathering, transportation, refining or processing facilities, or lack of capacity on such facilities. For example, increases in activity in the Permian Basin could contribute to bottlenecks in processing and transportation that may negatively affect our results of operations, and these adverse effects could be disproportionately severe to us compared to our more geographically diverse competitors.

The prices we receive for our production will be determined to a significant extent by factors affecting the local and regional supply of and demand for oil and natural gas, including the adequacy of the pipeline and processing infrastructure in the region to process and transport our production in the areas in which we operate and that of other producers. Those factors result in basis differentials between the published indices generally used to establish the price received for regional oil and natural gas production and the actual price we receive for our production, which may be lower than index prices. If the price differentials pursuant to which our production is subject were to widen due to oversupply or other factors, our revenue could be negatively impacted.

As a participant in these operations, we may not be able to maximize the value associated with these properties in the manner we believe appropriate, or at all. For example, we cannot control the success of drilling and development activities on properties operated by third parties, which depend on a number of factors under the control of a third-party operator, including such operator’s determinations with respect to, among other things, the nature and timing of drilling and operational activities, the timing and amount of capital expenditures and the selection of suitable technology.technology or appropriately engineered facility design. In addition, the third-party operator’s operational expertise and financial resources and its ability to gain the approval of other participants in drilling wells will impact the timing and potential success of drilling and development activities in a manner that we are unable to control. A third-party operator’s failure to adequately perform operations, non-compliance with applicable regulatory, environmental, and permitting requirements, breach of the applicable agreements, or failure to act in ways that are favorable to us could reduce our production and revenues, negatively impact our liquidity and cause us to spend capital in excess of our current plans, and have a material adverse effect on our financial condition and results of operations.

The availability of a ready market for any oil, natural gas and NGLs we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of oil and gas sold in interstate commerce. In addition, we depend upon a few significant purchasers for the sale of most of our oil and natural gas production. We cannot assure you that we will continue to have ready access to suitable markets for our future oil and natural gas production. Any termination or sustained disruption in the gathering, processing and transportation of our oil, natural gas and NGL production by our purchasers on their systems and in their facilities would materially and adversely affect our financial condition and results of operations.

We have exposure to credit risk through receivables from purchasers of our oil, natural gas and NGL production. One purchaser accounted for 70%60% of our revenues and another purchaser accounted for more than 10%30% of our revenues for the year ended December 31, 2024.2025. Due to the recent acquisition of Stakeholder by Targa and upon commencement of the A&R Gas Purchase Agreement, substantially all of our natural gas and NGLs will be sold to a single purchaser. This concentration of purchasers may impact our overall credit risk in that these purchasers may be similarly affected by changes in economic conditions or commodity price fluctuations. We do not require our customers to post collateral. The inability or failure of our significant purchasers to meet their obligations to us or their insolvency or liquidation may materially adversely affect our financial condition and results of operations.

Our exploration and production activities are subject to all of the operating risks associated with drilling for,for and producing, gathering and compressing oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering or other cratering, uncontrollable flows of natural gas, oil, well fluids and formation water, pipe or pipeline failures, processing or transportation capacity constraints or disruptions, damages to pipelines, compressor stations and related equipment, abnormally pressured formations, casing collapses, reservoir or environmental damage and environmental hazards such as oil, produced water or chemical spills, natural gas leaks, ruptures or discharges of toxic gases.gases or hazardous substances.

InWe have made, and in the future we may makecontinue to make, acquisitions of oil and natural gas properties or businesses that complement or expand our current business. The successful acquisition of oil and natural gas properties requires an assessment of several factors, including:

The accuracy of these assessments is inherently uncertain, and we may not be able to identify accretive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Reviews may not always be performed on every well or facility, and environmental problems, such as pipe corrosion or subsurface or groundwater contamination, are not necessarily observable even when a review is performed. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis. Even if we do identify accretive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.

In addition, our Credit Facility imposesand Senior Notes impose certain limitations on our ability to enter into mergers or combination transactions as well as limitslimit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions.

We may need to access funding through capital market transactions. Due to our relative smaller public float and low market capitalization, ESG, and climate change policies and restrictions, it may be difficult and expensive for us to raise additional funds.

As a result, we may be unable to access funding through sales of our common stock or other equity-linked securities. Even if we were able to access funding, the cost of capital may be substantial due to our low market cap and small public float. The terms of any funding we are able to obtain may not be favorable to us and may be highly dilutive to our stockholders. We may be unable to access capital due to unfavorable market conditions or other market factors outside of our control such as ESG and/or climate change policies and restrictions.. There can be no assurance that we will be able to raise additional capital when needed. The failure to obtain additional capital when needed would have a material adverse effect on our business.

The operating and financial restrictions and covenants in our Credit Facility and our Senior Notes restrict, and any future financing agreements likely will restrict, our ability to finance future operations or capital needs, engage, expand or pursue our business activities or pay dividends.dividends or execute stock buybacks. Our Credit Facility and our Senior Notes restrict, and any future financing agreements likely will restrict, our ability to, among other things:

Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of free cash flow and events or circumstances beyond our control, such as a downturn in our business or the economy in general or reduced oil, natural gas and NGL prices. A failure to comply with the provisions of our Credit Facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. Further, our ability to pay dividends to our stockholders or execute stock buybacks will be restricted and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments, and our common stockholders could experience a partial or total loss of their investment. In addition, our obligations under our Credit Facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our Credit Facility, the lenders can seek to foreclose on our assets.

•the covenants contained in our Credit Facility and Senior Notes limit our ability to borrow additional funds, dispose of assets, pay dividendsdividends, execute stock buybacks and make certain investments; and

Riley Permian is a growth-oriented, independent oil and natural gas company focused on horizontal drilling of conventional oil-saturated and liquids-rich formations in the Permian Basin that produce long-term stable cash flows in the Permian Basin.flows. The majority of our acreage is located in Yoakum County, Texas and Eddy County, New Mexico.

Our strategic business objectives include enhancing the rate of return on our invested capital, generating sustainable free cash flow, maintaining a strong and flexible balance sheet whileand maximizing our returns to shareholders. We implement this strategy primarily through identification and capture of attractive development opportunities, optimization of our assets and pursuing complementary growth opportunities that increase our scale and meet our strategic and financial objectives.

Commodity prices remain volatile. General domestic and international politicaleconomic, market and economicpolitical conditions, including the military conflict between Russia and Ukraine, conflicts in the Middle East, and the U.S. and global response to such conflicts, global economic growth, unpredictability of tariffs, actions of OPEC+ countries,countries and implementationchanges ofto tariffsthe current political environment could prolong market volatility orand cause a decline in commodity prices.

InflationAlthough continuesthe broader rate of inflation has moderated, we continue to bemonitor anthe ongoingrisk concern.of Althoughpersistent inflation moderated somewhat, inflationarycost pressures remainin elevated,specific whichareas of our operating expenses and capital expenditures. Our margins may be compressed if costs increase more than commodity prices. Additionally, the current interest rate environment remains sensitive to shifts in turnmacroeconomic may cause our capital expendituresfactors and operatingcentral costsbank to increase. During inflationary periods, interest rates have historically increased.policies. Increased interest rates could have the effects of raising our cost of capital and the potential for depressing economic growth, either of which (or the combination thereof) could hurt the financial and operating results of our business.

2024 New Mexico AssetSilverback Acquisition

On December 13, 2024, the Company entered into the sixteenth amendment to the Credit Facility to, among other things, extend the stated maturity date from April 2026 to December 2028 (or if any Senior Notes are then outstanding, the date that is 181 days prior to the earliest stated maturity date of such Senior Notes, in this case October 2027), increase the borrowing base from $375 million to $400 million, and add one new lender to the lending group. In December 2025, through the semi-annual redetermination process, the Company's borrowing base was reaffirmed at $400 million and the requirement for natural gas hedging was removed.

(1)The Company's oil, natural gas and NGL sales are presented net of gathering, processing and transportationGP&T costs. These costs, related to natural gas and NGLs, at times exceeded the price we received and resulted in negative average realized prices.

Our revenues are derived from the sale of our oil and natural gas production, including the sale of NGLs that are extracted from our natural gas during processing. Realized prices and revenues from product sales are a function of the volumes produced, product quality, market prices, gas Btu content, as well as gathering, processing and transportationGP&T costs. Gathering, processing and transportationGP&T costs are allocated across natural gas and NGLs based on revenue, which leads to heightened fluctuations in such cost allocations across periods. Our revenues from oil, natural gas and NGL sales do not include the effects of derivatives. Our revenues may vary significantly from period to period as a result of changes in the volume of production sold or changes in commodity prices. The Company’s total oil and natural gas sales, net increased $37.2 million, or 10%, for the year ended December 31, 2024, compared to the year ended December 31, 2023. The following table presents the Company's oil and natural gas sales prior to and net of gathering, processing and transportationGP&T costs:

Our realized oil prices decreased by $1.52$11.15 duringper Bbl, which was the yearresult endedof Decemberan 31,$11.24 2024,per when compared to the year ended December 31, 2023, which corresponded with a $0.95Bbl decrease in the average WTI price during the same period. An increase in basis differentials accounted for the remaining difference.price. Daily oil volumes increased by 15% due to increased production from new wells turned to sales in our ChampionsRed Lake field as well as the 2023partial andyear 2024contribution Newfrom Mexicothe Acquisitions.Silverback Acquisition.

LOE are the costs incurred in the operation and maintenance of producing properties. Expenses for electricity, compression, direct labor, saltwater disposal and materials and supplies comprise the most significant portion of our lease operating expenses. Certain operating cost components, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities or subsurface maintenance result in increased production expenses in periods during which they are performed. Certain operating cost components, such as saltwater disposal associated with produced water, are variable and increase or decrease as hydrocarbon production levels and the volume of water disposal increases or decreases.

The Company’s LOE increased by $12.6$16.0 million for the year ended December 31, 2024,2025, compared to the year ended December 31, 2023.2024. This increase was driven primarily by ahigher $5.5production volumes, including an $8.3 million increase due to morehigher workovers primarilyproduction in our Red Lake field, a $4.5 million increase in our Champions field due to higher production volumes and a $3.4$7.2 million increase due to theSilverback inclusionproduction ofadded LOE expenses associated withto our 2024Red NewLake Mexicofield, Asset Acquisition, partially offset byand a decrease in certain expenses, primarily chemical, fuel and repair costs. On a LOE per BOE basis, the additional volumes fully offset the $12.6$0.9 million increase asin the 2024 LOE per BOE was flat when compared to 2023.workovers.

Production taxes are paid on produced oil, natural gas and NGLs based on a percentage of revenues at fixed rates established by federal, state or local taxing authorities. In general, the production taxes we pay correlate to changes in our oil, natural gas and NGL revenues. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural gas properties, which also trend with oil and natural gas prices and vary across the different counties in which we operate. In addition, the Company became subject to a waste emissions charge in 2024 related to methane emissions in excess of specified limits under new legislation from the EPA. This amount was recorded in production taxes for 2024.

Production and ad valorem taxes increaseddecreased by $3.9$0.4 million for the year ended December 31, 2024,2025, compared to the year ended December 31, 2023,2024, primarily due to increaseslower realized prices of $6.8 million and $1.5 million related to the Environment Protection Agency's WEC that was nullified in ourthe oilfirst quarter of 2025, partially offset by $5.5 million due to increased production and natural gas sales, net and $0.8$2.4 million fromdue to the newSilverback waste emissions charge.Acquisition.

Exploration costs consist of exploratory well expense, expiration of unproved leasehold, and geological and geophysical costs which include seismic survey costs. The following table presents the components of exploration costs for the years ended December 31, 2024, and 2023:

The Company recognized an additional non-cash impairment loss of $1.6 million for the year ended December 31, 2025 related to equipment from the EOR project that was intended to be repurposed for use in our conventional development programs. The Company also recognized an impairment loss of $30.2 million for the year ended December 31, 2024, which consisted of a non-cash impairment loss of $28.9 million related to the discontinuation of the EOR project, and a cash impairment loss of $1.3 million related toa thecontract termination of the Kinder Morgan CO2 contract.payment. The impairment loss relates to the discontinuation of the Company's EOR project,project was in favor of redeploying the required future capital and salvagingrepurposing certain assets for use in the Company's conventional vertical and horizontal development programs. There was no other impairment loss for the year ended December 31, 2023.

G&A expenses consist of administrative costs and share-basedstock-based compensation expense. Administrative costs include corporate overhead such as payroll and benefits for our staff, office costs, fees for professional services such as audit and legal services, technology costs, insurance and other. Share-basedStock-based compensation expense reflects costs associated with our stock granted to employees and members of our board of directors. G&A expenses are reported net of overhead recoveries.

In addition to the information set forth in this Quarterly Report, the risks that are discussed in the Company's Annual Report on Form 10-K for the year ended December 31, 2025, under the headings "Part I, Item 1 and 2. Business and Properties," "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Part I, Item 1A. Risk Factors" and in "Part II, Item 1A. Risk Factors" of our subsequently filed Quarterly Report should be carefully considered, as such risks could materially affect the Company's business, financial condition or future results. Other than those noted below, thereThere have been no material changes in the Company's risk factors from those that were described in the Company's 2025 Annual Report and subsequently filed Quarterly Report.

Commodity prices remain volatile. General domestic and international economic, market and political conditions, including military conflicts, global economic growth, unpredictability of new tariffs, actions of OPEC+ countries,countries and changes to the current political environment could prolong market volatility and continue to cause a decline in commodity prices.

The Company cannot estimate the length or gravity of the future impact these conditionsevents will have on the Company's results of operations, financial position, liquidity and the value of the oil and natural gas reserves.

We expectcontinue to monitor the reliability and capacity of third-party midstream infrastructure serving our relianceNew onMexico thisacreage. counterpartyTo tomitigate diminishthe oncerisk additionalof future processing and takeaway capacityconstraints becomes available fromof the nature experienced during the period, Targa is constructing new high-pressure gathering and trunkhigh-pressure linetrunkline infrastructure currently being constructed by Targa in Eddy County, New Mexico underpursuant to the A&R Gas Purchase Agreement. SeeUpon Notecompletion, 15this –infrastructure Commitmentsis expected to provide increased gathering, processing, and Contingenciestakeaway forcapacity furtherthat discussionreduces ofour reliance on the Gasaffected Purchasethird-party Agreement.processing facilities. The in-service date of the new Targa pipeline system is currently expected to occur beforein the endfourth quarter of 2026. WeSee willNote continue15 to– monitorCommitments theand situation.Contingencies for additional information.

Comparison for the three and six months ended MarchJune 31,30, 2026, and 2025:

(2)The Company's calculation of the effects of derivative settlements includes gains (losses) on the settlement of our commodity derivative contracts. These realized gains (losses), along with unrealized gains (losses) from changes in the fair value of derivatives, are included under other income (expense) on the Company’s condensed consolidated statements of operations.

Three months ended MarchJune 31,30, 2026, compared to three months ended MarchJune 31,30, 2025

The Company’s total oil and natural gas sales, net increased $11.4by million,$80.5 million or 11%.94%. The following tables summarize the effects of price, volume and GP&T costcosts changes on our revenues from oil, natural gas and NGLs:

Natural gas revenues decreased by $7.9$12.5 million,million asdriven lowerby negative realized natural gas prices and higher GP&T coststhat more than offset higher volumes. Despite a $0.57 per Mcfan increase in theproduction averagevolumes. Henry Hub price,Our realized natural gas prices before GP&T costs decreased by $2.92,$4.80 per Mcf, which was the result of an increase in thenegative negativePermian basis differentials due to regional pipeline constraints.constraints Naturalin gas production volumes increased by 70% dueaddition to acquireda wells$0.24 fromdecrease in the Silverbackaverage Acquisition,Henry increasedHub processing capacity from our midstream partner in our Champions field and new wells turned to sales.price.

The following table presents the Company's operating costs and expenses and other (income) expenses:

The Company’s LOE increased by $5.7$10.6 million for the three months ended MarchJune 31,30, 2026, compared to the three months ended MarchJune 31,30, 2025.2025, Theprimarily LOEdue to a $6.4 million increase ofrelated approximatelyto $4.5the Silverback Acquisition, a $3.0 million andincrease in workover expenseexpenses increaseto ofreturn approximatelywells to production and a $1.2 million were driven primarily by the Silverback Acquisition. The LOE increase wasin dueChampions' third-party water disposal costs to higheralign fieldwith payroll and other variable costs driven byour increased productiondrilling volumes.pace.

Production and ad valorem taxes increased by $2.4$5.3 million for the three months ended MarchJune 31,30, 2026, compared to the three months ended MarchJune 31,30, 2025, primarily due to higher revenues from increased production involumes, both our Champions and Red Lake fields, with higher production in Red Lake due to the Silverback Acquisition, andincluding an increase in crudevolumes from the Silverback Acquisition and higher oil prices, as well as the reversal of a previously accrued liability related to the Environmental Protection Agency’s waste emission charge that was nullified in the first quarter of 2025.prices.

Total G&A expense increased by $1.6$3.8 million and $5.4 million for the three and six months ended MarchJune 31,30, 2026, compared to the three and six months ended MarchJune 31,30, 2025.2025, Administrative costs increased by $0.7 millionrespectively, primarily due to increased employeeheadcount headcount.and Stock-basedhigher compensationincentive expensed increased by $0.9 million due to an increase in outstanding equity awards.compensation.

Interest expense, net decreased by $0.3$0.4 million and $0.7 million, respectively, for the three and six months ended MarchJune 31,30, 2026, compared to the three and six months ended MarchJune 31,30, 2025, respectively, primarily due to a lower total debt balance along with lower interest rates on borrowings under ourthe Credit Facility.Facility and a lower principal balance on the Senior Notes.

Gain (Loss) on Derivatives, net

The Company recognizes settlements and changes in the fair value of our derivative contracts as a single component within other income (expense) in our condensed consolidated statements of operations. We have oil and natural gas derivative contracts, including fixed price swaps, basis swaps and collars, that settle against various indices. The following table presents the components of the Company's gain (loss) on derivatives, net:

Cash gains or losses on settled derivative contracts relaterelated to contracts that settle during the period and are a function of the difference in settled versus contractual prices and the associated hedged volumes for each underlying commodity. Non-cash gains or losses on derivatives relate to unsettled contracts and are a function of changes in derivative fair values associated with fluctuations in the forward price curves for the commodities relative to contractual pricing and the associated hedged volumes for each underlying commodity for our derivative contracts outstanding.

The increase in deferred income tax expense during the three months ended June 30, 2026, is primarily due to a higher non-cash benefit on derivatives. The decrease in current income tax expense was primarily attributable to higher capital spending during the threesix months ended MarchJune 31,30, 2026, compared to the threesix months ended MarchJune 31,30, 2025. The deferred income tax benefit increased primarily due to a higher non-cash loss on derivatives over the same period.

The business of exploring for, developing and producing oil and natural gas is capital intensive. Because oil, natural gas and NGL reserves are a depleting resource, like all upstream operators, we must make capital investments, like all upstream operators,investments to sustain and grow production. The Company’s principal liquidity requirements are to finance our operations, fund capital expenditures, fund acquisitions and joint venture commitments, pay dividends and satisfy any indebtedness obligations. Cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and the significant capital expenditures required to more fully develop the Company’s oil and natural gas properties. Historically, our primary sources of capital funding and liquidity have been our cash on hand, cash flow from operations, borrowings under our Credit Facility and the issuance of our Senior Notes. At times and as needed, we may also issue debt or equity securities, including through transactions under our shelf registration statement filed with the SEC. We estimate the combination of the sources of capital discussed above will continue to be adequate to meet our short and long-term liquidity needs.

Working capital represents the funds available to meet day-to-day operational needs and is the difference in our current assets and our current liabilities. Working capital is an indication of liquidity and potential need for short-term funding. The change in our working capital requirements is driven generally by changes in accounts receivable, accounts payable, commodity prices, credit extended to, and the timing of collections from customers, the level and timing of spending for expansion activity, and the timing of debt maturities. Our working capital fluctuates as our drilling and completion activity changes with periods of higher and lower activity. We utilize our Credit Facility and cash on hand to manage the timing of cash flows and fund short-term working capital deficits. At MarchJune 31,30, 2026, we had $293$262 million of undrawn capacity under our Credit Facility. The following table presents the components of working capital:

Net cash provided by operating activities were $47.2$110.7 million for the threesix months ended MarchJune 31,30, 2026, compared to $50.4$84.0 million for the threesix months ended MarchJune 31,30, 2025, and primarily consisted of the following:

(1)Operating expenses include LOE, production and ad valorem taxes, administrative costs, transaction costs and other minormiscellaneous operating expenses.

The decreaseincrease in net cash provided by operating activities was primarily attributabledue to derivativehigher settlementsrevenues receivedfrom inincreased the prior year versus paid in the current yearproduction and an increase in accounts receivable, both driven by higher crude oil prices.prices, Thisalong was partially offset bywith an increase in advances from joint interest owners.owners, partially offset by higher operating expenses associated with increased production and derivative settlement losses resulting from higher oil prices.

Net cash flows used in investing activities were $28.8$101.7 million for the threesix months ended MarchJune 31,30, 2026, compared to $25.4$70.5 million for the threesix months ended MarchJune 31,30, 2025, and primarily consisted of the following:

Capital expenditures for oil and natural gas properties increased by $13.4$55.9 million due to an increase in wells drilleddrilling and completed.completion Theactivity Companyand hadan proceedsincrease fromin infrastructure investments. Funds held in escrow relate to the saleSilverback ofAcquisition, non-operatedwhich wellsclosed inon 2026.July 1, 2025.

Net cash flows used in financing activities were $20.4$6.2 million for the threesix months ended MarchJune 31,30, 2026, compared to $29.2$12.7 million for the threesix months ended MarchJune 31,30, 2025, and primarily consisted of the following:

TheNet Companyborrowings decreased net debt repaymentsincreased by $13.0$14 million, partially offset by repurchasedthe repurchase of common shares of $4.0$5 million and an increase in repurchases of common shares for tax withholding of 1.5 million.

The Credit Facility and Senior Notes had a principal balance of $140$138 million and $135 million, respectively, as of MarchJune 31,30, 2026.

For the threesix months ended MarchJune 31,30, 2026, the Company recognized quarterly dividends totaling approximately $8.6$17.3 million, with $8.4$17.0 million paid in cash and $0.2$0.3 million accrued for the holders of unvested restricted stock awards.

As of MarchJune 31,30, 2026, the Company had a remaining volume commitment that expires the earlier of fiveachieving yearsa specified quantity of cumulative volumes delivered or by the contract expiration date in 2031 with Targa, formerly Stakeholder,Stakeholder Midstream, LLC, in Texas. The Company also had natural gas delivery commitments under the A&R Tolling Agreement and a remaining equity commitment under the Second Amendment to the A&R LLC Agreement to fund our portion of the capital budget for the RPC Power joint venture. The Company also entered into the A&R Gas Purchase Agreement that required an acreage dedication and a minimum volume commitment to Targa for a significant portion of our natural gas production in New Mexico. This agreement is expected to commence beforein the endfourth quarter of 2026. In addition, the Company entered into the Waterbridge Agreement, which includes minimum produced water volume commitments for a portion of our New Mexico operations and is expected to be in service in Septemberthe fourth quarter of 2026. See Note 15 - Commitments and Contingencies for additional information.

The Company's critical accounting estimates are described in "Critical Accounting Estimates" within "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 1 of the Notes to the Consolidated Financial Statements in the 2025 Annual Report. The accounting estimates used in preparing our interim condensed consolidated financial statements for the threesix months ended MarchJune 31,30, 2026, are the same as those described in the 2025 Annual Report.