RING ENERGY, INC.
For the period ended Mar 31, 2026. Filed May 6, 2026.
View on SEC.govAbout this filing
A company's report for each of its first three quarters. The financial statements are not audited. It shows how the business has moved since the last annual report, and what management says changed.
Mar 31, 2026 · Filed May 6, 2026
REI$1.11-0.9%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-Q
Period ended 2025-09-30; filed 2025-11-06.
0001384195-25-000018
Item 2. : Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2026-03-31; filed 2026-05-06.
0001384195-26-000072
Item 2. : Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 96 previous paragraphs and 73 current paragraphs.
33 unchanged; 24 reworded; 15 added; 26 removed; 13 previous and 1 current paragraphs rearranged.
Tables are not compared: 15 previous and 10 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (15)
Current report
Our operating strategy is centered on the following priorities:
Current report
•Reducing long-term debt and strengthening the balance sheet. The Company intends to reduce leverage primarily through the use of excess cash flow and, where appropriate, selective non-core asset sales. The Company's field-level margins and asset quality position it to continue deleveraging over time while preserving financial flexibility.
Current report
•Employing industry-leading drilling and completion techniques. Ring’s executive team leverages technological advancements in completion design, geological evaluation, and reservoir engineering to optimize well performance and capital efficiency, contributing to a competitive cost structure and generating new organic development opportunities across the Company's asset base.
Current report
•Pursuing strategic, accretive acquisitions. The Company has a history of acquiring accretive assets with additional development potential that complement its existing property portfolio. Management intends to continue evaluating acquisition opportunities that improve balance sheet metrics, enhance inventory depth, and are accretive to stockholders. Many of these opportunities are often sourced through the executive team's longstanding operating and transactional relationships in the Permian Basin.
Current report
2026 Developments and Operational Highlights
Current report
As a result of the Company's drilling and operational activities, total production for the three months ended March 31, 2026 increased 5%year over year to 1.74 million Boe. The increase in production was driven by contributions from the Lime Rock acquisition and new operated development, partially offset by natural production declines in legacy assets.
Current report
Operationally, the Company delivered solid field level performance during the quarter. For the three months ended March 31, 2026, Ring generated Exploration and Production segment profit of $49.7 million, despite a challenging commodity price environment, particularly for natural gas. These results reflect continued cost discipline, efficient execution of the development program, and the benefits of the Company’s oil weighted asset base.
Current report
At the Total Company level, reported results were materially impacted by certain non-cash items. The Company recorded a net loss of $220.6 million for the quarter, driven primarily by a $162.1 million full cost ceiling test impairment and $77.0 million unrealized derivative mark to market adjustments resulting from changes in forward commodity prices.
Current report
The Company's underlying operating performance and liquidity remained solid during the quarter, and the non-cash charges we incurred did not affect compliance with the financial covenants under the Company’s Credit Facility. Core operating results remain resilient, supported by disciplined capital allocation, ongoing cost improvements, and a hedge position designed to provide cash flow stability in a volatile pricing environment.
Current report
The Company’s financial results are highly sensitive to changes in commodity prices, and during the first quarter of 2026, oil and natural gas markets experienced significant volatility driven by different factors. In the Permian Basin, natural gas prices remained under severe pressure due to regional takeaway constraints and elevated processing and transportation costs, while crude oil prices were influenced by broader global events late in the quarter.
Current report
As a result of the sustained weakness in Permian natural gas markets, the Company realized negative net natural gas prices during the quarter, as processing and transportation fees exceeded gross realized sales prices, which adversely impacted reported revenues. In response, management continues to pursue commercially reasonable mitigations, including basis hedging, marketing optimization, and disciplined capital allocation, while maintaining a strong focus on preserving liquidity and long term value.
Current report
Separately, late first quarter 2026 geopolitical developments affected global crude oil markets, resulting in a sharp increase in crude oil prices. These late quarter price movements adversely impacted the fair value of the Company’s outstanding crude oil derivative positions and contributed to the unrealized derivative losses recorded during the quarter. By contrast, the SEC full cost ceiling test is based on an unweighted arithmetic average of first day of the month prices for the preceding twelve months, and accordingly, these late quarter oil price movements had limited impact on the twelve month average prices used in the Company’s March 31, 2026 ceiling test calculation.
Current report
Accordingly, because the ceiling test is based on historical twelve month average pricing, it does not fully reflect significant changes in commodity prices that occur late in a reporting period.
Current report
Gathering, transportation and processing costs. Our total GTP decreased $86,563 from $203,612 to $117,049 and decreased on a per Boe basis from $0.12 to $0.07. The decrease in GTP costs was due to a reduction of $77,561 in gas processing costs and a reduction of $9,002 in NGL processing costs.
Current report
General and administrative expense. G&A expense decreased approximately $1.2 million from $8.6 million to $7.4 million, with the $1.2 million cost decrease primarily due to a decrease of $0.6 million in salaries and bonuses, $0.5 million in additional costs capitalized, and a decrease of $0.1 million in insurance expense.
Removed paragraphs (26)
Previous report
•Reduction of long-term debt and deleveraging of asset. Ring intends to reduce its long-term debt primarily through the use of excess cash flow and potentially through the sale of non-core assets. The Company believes that with its attractive field level margins, it is positioned to maximize the value of its assets and deleverage its balance sheet. The Company also believes through potential accretive acquisitions and strategic asset dispositions, it can accelerate the strengthening of its balance sheet.
Previous report
•Employ industry leading drilling and completion techniques. Ring’s executive team intends to utilize new and innovative technological advancements for completion optimization, comprehensive geological evaluation, and reservoir engineering analysis to generate value and to build future development opportunities. These technological advancements have led to a low-cost structure that helps maximize the returns generated by our drilling programs.
Previous report
•Pursue strategic acquisitions with attractive upside potential. Ring has a history of acquiring leasehold positions that it believes to have additional resource potential that meet its targeted returns on invested capital and comparable to its existing inventory of drilling locations. We pursue an acquisition strategy designed to increase reserves at attractive finding costs and complement existing core properties. Management intends to continue to pursue strategic acquisitions and structure the potential transactions financially, so they improve our balance sheet metrics and are accretive to stockholders. Our executive team, with its extensive experience in the Permian Basin, has many relationships with operators and service providers in the region.
Previous report
2025 Developments and Highlights
Previous report
Lime Rock Acquisition
Previous report
On March 31, 2025, the Company, as buyer, and Lime Rock Resources IV-A, L.P. (“LRRA”), and Lime Rock Resources IV-C, L.P. (“LRRC” and with LRRA, “Lime Rock”), as seller, consummated the transactions contemplated in that certain Purchase and Sale Agreement dated February 25, 2025, by and among the Company, LRRA and LRRC (the “Purchase Agreement”) that was previously reported on Form 8-K filed on February 28, 2025 with the Securities and Exchange Commission (“SEC”). At the closing of the Purchase Agreement, among other things, the Company acquired (the “Lime Rock Acquisition”) interests in oil and gas leases and related property of Lime Rock located in Andrews County, Texas, for an aggregate consideration consisting of: (i) approximately $69.3 million in cash, net of customary purchase price adjustments, paid at the closing of the Lime Rock Acquisition, (ii) $10.0 million in cash to be paid by December 31, 2025, and (iii) 6,452,879 shares of common stock.
Previous report
Drilling and Completion
Previous report
In the first quarter of 2025, in the Northwest Shelf in Yoakum County, the Company drilled and completed three 1-mile horizontal wells and one 1.25-mile horizontal well, all with a working interest of 75%. In the Central Basin Platform in Ector County, the Company drilled and completed three vertical wells, all with a working interest of 100%.
Previous report
In the second quarter of 2025, in the Central Basin Platform in Andrews County, the Company drilled and completed one 1-mile horizontal well, with a working interest of 100%. Also in the Central Basin Platform in Crane County, the Company drilled and completed one vertical well, with a working interest of 100%.
Previous report
The table below sets forth our drilling and completion activities for the nine months ended September 30, 2025.
Previous report
As of September 30, 2025, the Company was in the process of drilling one 1.5-mile horizontal well in the Northwest Shelf in Yoakum County. That well has since been completed and placed on production.
Previous report
Our financial results depend on many factors, particularly the price of crude oil and natural gas and our ability to market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand both domestically and world wide, which are impacted by many factors. As a result, we cannot accurately predict future commodity prices, and therefore, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our drilling program, production volumes or revenues.
Previous report
Average oil and natural gas prices received through 2024 and 2025 to date continue to demonstrate commodity price volatility and we believe oil and natural gas prices will continue to be volatile for the foreseeable future. The ability to find and develop sufficient amounts of crude oil and natural gas reserves at economical costs are critical to our long-term success.
Previous report
Oil sales. Oil sales decreased approximately $11.5 million from $90.4 million to $78.9 million, driven by a price variance of $(12.4) million from a decrease in the average realized price per barrel from $74.43 to $64.32. This was offset by a volume variance of $0.9 million from an increase in sales volume from 1,214,788 barrels to 1,226,537 barrels. The increase in volume of 11,749 barrels consisted of two components: an increase in volumes of 145,893 barrels was due to the wells acquired in the Lime Rock Acquisition (which closed at the end of March 2025), and a decrease of 134,144 was attributed to natural production declines from our legacy assets. The decreased average realized price per barrel was primarily a result of lower oil prices.
Previous report
Natural gas liquids sales. NGL sales decreased approximately $0.7 million from $2.7 million to $2.0 million. NGL sales volumes for the three months ended September 30, 2025 were 377,141 barrels compared to 350,975 barrels for the comparable period in 2024. Of the increase in volume of 26,166 barrels, 40,700 barrels were attributable to wells acquired in the Lime Rock Acquisition, offset by a reduction of 14,534 barrels attributable to our legacy assets in correlation with gas sales. The average realized price per barrel of NGLs was $5.22 for the three months ended September 30, 2025 compared to $7.66 for the three months ended September 30, 2024, due to weaker market conditions. Specifically, the gross realized price per NGL barrel was $17.52 and the average fees per barrel was $(12.30), resulting in a net realized price of $5.22 for the three months ended September 30, 2025, while the gross realized price per NGL barrel was $18.45 and the average fees per barrel was $(10.79), resulting in a net realized price of $7.66 for the same period in 2024.
Previous report
Lease operating expenses. Our total lease operating expenses (“LOE”) increased from $20.3 million to $20.5 million and decreased on a per Boe basis from $10.98 to $10.73. These per Boe amounts are calculated by dividing our total lease operating expenses by our total volume sold, in Boe. Total LOE increased primarily due to an 3% increase in production of 62,677 Boe as a result of the increased production and well count from the Lime Rock Acquisition as well as new wells drilled and completed in our development program. The primary cost drivers for the period were an increase of $0.9 million in electricity, $0.6 million for environmental sustainability and cleanup, and $0.3 million for salt water disposal, offset by reductions of $1.2 million for workover costs and $0.3 million for pressure, vacuum, and hot oil truck costs.
Previous report
Gathering, transportation and processing costs. Our total gathering, transportation and processing costs (“GTP”) increased from $102,420 to $126,569 and increased slightly on a per Boe basis from $0.06 to $0.07. Beginning May 1, 2022, due to a natural gas processing entity taking control of transportation at the wellhead, GTP costs were re-classified as a reduction to oil and natural gas sales revenues. However, one contract remains in place with a natural gas processing entity where point of control of gas dictates requiring the fees be recorded as an expense. The increase in GTP costs was primarily due to the higher natural gas Mcf and NGL barrels processed.
Previous report
Ad valorem taxes. Our total ad valorem taxes increased from $2.2 million to $2.4 million and increased on a per Boe basis from $1.17 to $1.28. Of the $0.3 million increase in ad valorem taxes, $0.8 million was for Andrews County tax estimates, primarily related to the Lime Rock Acquisition as well as $0.1 million for Ector County tax estimates. This was offset by a decrease of $0.6 million for Yoakum County tax estimates.
Previous report
Gathering, transportation and processing costs. Our total GTP increased $87,887 from $376,103 to $463,990 and increased slightly on a per Boe basis from $0.07 to $0.08. The increase in GTP costs was due to the higher natural gas Mcf and NGL barrels processed as well as a prior period adjustment for fee exempt owners.
Previous report
Oil and natural gas production taxes. Oil and natural gas production taxes as a percentage of oil and natural gas sales were 4.33% for the nine months ended September 30, 2024 and increased to 4.61% for the nine months ended September 30, 2025. For the nine months ended September 30, 2024, the overall average percentage of production taxes to oil and gas sales was 4.7%, which is in line with historical rates. However, in May 2024, an accrual of $(0.9) million was made for estimated severance tax refunds expected, which lowered the average for the nine months ended September 30, 2024.
Previous report
Depreciation, depletion and amortization. Our depreciation, depletion and amortization decreased from $25.7 million to $25.2 million, with $0.4 million of the reduction from lower depletion. The decrease in depletion was the result of a price variance of $(1.3) million, due to a lower depletion rate per Boe, driven by a higher percentage increase in the amortization base than the percentage increase in the estimated costs of property, offset by a volume variance of $0.9 million from an increase of 62,677 in Boe produced. Our average depreciation, depletion and amortization per Boe decreased from $13.87 per Boe to $13.19 per Boe.
Previous report
Asset retirement obligation accretion. Our asset retirement obligation (“ARO”) accretion increased from $354,195 to $390,563 primarily due to additional ARO accretion associated with properties acquired in the Lime Rock Acquisition.
Previous report
General and administrative expense. General and administrative ("G&A") expense increased from $6.4 million to $8.1 million. The $1.7 million cost increase was primarily driven by an increase of $1.6 million in share-based compensation costs and $0.7 million in salaries and bonuses, related to the separation of a former executive. These costs were offset by reductions of $0.2 million in environmental sustainability, $0.1 million in reduced legal fees, $0.1 million additional costs capitalized, and $0.1 million in employee health insurance.
Previous report
General and administrative expense. G&A expense increased approximately $2.3 million from $21.6 million to $23.9 million, with the $2.3 million cost increase primarily due to an increase of $3.0 million in salaries and bonuses (including impacts from severance paid to a former executive), $0.8 million in stock based compensation, $0.1 million in rent expense, offset by reductions of $0.5 million in legal fees, $0.4 million in environmental sustainability, $0.3 million in additional costs capitalized, $0.2 million in other professional fees, and $0.2 million in credit loss expense.
Previous report
Interest expense. Interest expense decreased from $10.8 million to $10.1 million primarily due to a reduction in deferred financing costs recognized from the credit agreement modification which was completed in June 2025. Although the Company had higher amounts outstanding on its Credit Facility, with a weighted average daily debt of approximately $445.1 million during the third quarter of 2025 compared to approximately $406.5 million during the third quarter of 2024, the interest on the revolving line of credit decreased due to a meaningful reduction in interest rates, with a weighted average annual interest rate of 8.2% in the third quarter of 2025 compared to 9.3% in the third quarter of 2024. Offsetting the reduction in interest expense was the deferred cash payment accretion related to the Lime Rock Acquisition which closed in March 2025.
Previous report
(1) The oil basis swap hedges are calculated as the fixed price (weighted average spread price above) less the difference between WTI Midland and WTI Cushing, in the issue of Argus Americas Crude.
Reworded paragraphs (24)
Previous wording
Ring Energy, Inc. (the “Company,” “Ring,” “we,” “us,” “our” and similar terms) is a growth oriented independent oil and natural gas exploration and production company based in The Woodlands, Texas engaged in oil and natural gas development, production, acquisition, and exploration activities currently focused in the Permian Basin in Texas. Our primary drilling operations target the oil and liquids rich producing formations in the Northwest Shelf and the Central Basin Platform, both of which are part of the Permian Basin.
Current wording
Ring Energy, Inc. (the “Company,” “Ring,” “we,” “us,” “our” and similar terms) is an independent, growth-oriented oil and natural gas exploration and production company headquartered in The Woodlands, Texas and focused on the Permian Basin. Our operations are concentrated in the Northwest Shelf and Central Basin Platform, where we pursue disciplined development of oil weighted, long life production assets while maintaining a strong focus on capital efficiency, cost control, and balance sheet strength.
Previous wording
The Company is focused on balancing the need to reduce long-term debt and further developing our oil and gas properties to maintain or grow our annual production. We intend to achieve both through proper allocation of cash flow generated by our operations and potentially through the sale of non-core assets. We intend to continue evaluating potential transactions to acquire strategic producing assets with attractive acreage positions that can provide competitive returns for our stockholders.
Current wording
The Company is focused on balancing the reduction of long-term debt with the continued development of our oil and gas properties in order to maintain or grow annual production. We intend to achieve these objectives through disciplined allocation of cash flow generated from operations and, where appropriate, through the sale of non-core assets. In addition, we continue to evaluate potential acquisitions of strategic producing assets with attractive acreage positions that we believe can generate competitive returns for our stockholders.
Previous wording
•Growing production and reserves by developing our oil-rich resource base through conventional and horizontal drilling. In an effort to maximize its value and resources potential, Ring intends to drill and develop its acreage base in both the Northwest Shelf and Central Basin Platform, allowing Ring to execute on its plan of operating within its generated cash flow.
Current wording
•Growing production and reserves through disciplined development. Ring seeks to develop its oil-rich resource base through a combination of conventional and horizontal drilling across the Northwest Shelf and Central Basin Platform, with an emphasis on operating within cash flow and generating competitive returns.
Previous wording
In the third quarter of 2025, in the Central Basin Platform in Andrews County, the Company drilled and completed three 1-mile horizontal wells, each with a working interest of 100%. Also in the Central Basin Platform in Crane County, the Company drilled and completed one 1-mile horizontal well and one vertical well, both with a working interest of 100%.
Current wording
During the first quarter of 2026, the Company continued execution of its development program across its core operated positions. In the Northwest Shelf (Yoakum County), Ring drilled and completed five one-mile horizontal wells, each with a working interest of approximately 91%. In addition, the Company in the Central Basin Platform (Crane County), completed one previously drilled one-mile horizontal DUC well, and drilled and completed one vertical well, with a 100% working interest.
Previous wording
(1)Total does not include the SWD well(s) drilled and completed in the [ ].
Current wording
(1) The horizontal well completed in the Central Basin Platform in the first quarter of 2026 is the completion of a previously drilled but uncompleted (“DUC”) well.(1)Total does not include the SWD well(s) drilled and completed in the [ ].
Previous wording
We perform a ceiling test at the end of each reporting period to evaluate for potential non-cash impairments. Under the full cost method of accounting, the net book value of properties, less related deferred income taxes, may not exceed a calculated “ceiling,” which is defined as the estimated after-tax future net revenues from proved oil and natural gas properties, discounted at an annual rate of 10%. The discounted future net revenues are estimated using spot prices for oil and natural gas, based on the average price during the preceding twelve months. This average is calculated as an unweighted arithmetic mean of the first-day-of-the-month prices for each month within that period, except when changes are fixed and determinable by existing contracts. As a result of the ceiling test, driven by a decrease in the twelve month average commodity price over the past few months, the Company recognized a non-cash impairment charge of $72.9 million during the three months ended September 30, 2025. If this downward trend continues, the Company's discounted future net revenues could continue to decline, which may trigger additional non-cash impairments recognized in future periods. Estimating potential future non-cash impairments is complex due to numerous factors affecting the ceiling test calculation, including but not limited to future prices, operating costs, upward or downward reserve revisions, reserve additions, and tax attributes. The amount of any additional non-cash impairment, if any, is not estimable at this time given the uncertainty of these factors.
Current wording
We perform a ceiling test at the end of each reporting period to evaluate for potential non-cash impairments. Under the full cost method of accounting, the net book value of properties, less related deferred income taxes, may not exceed a calculated “ceiling,” which is defined as the estimated after-tax future net revenues from proved oil and natural gas properties, discounted at an annual rate of 10%. The discounted future net revenues are estimated using spot prices for oil and natural gas, based on the average price during the preceding twelve months. This average is calculated as an unweighted arithmetic mean of the first-day-of-the-month prices for each month within that period, except when changes are fixed and determinable by existing contracts.
Previous wording
The Permian Basin has been experiencing a lack of sufficient pipeline transportation that is connected to markets that are purchasing the natural gas produced. This has resulted in negative natural gas prices at times, whereby the seller is actually paying the purchaser to take the gas. We have experienced negative realized gas prices at times and conditions are continuing. If these depressed or inverted natural gas prices continue in the region, our natural gas revenues will continue to be negatively impacted.
Current wording
The Permian Basin has been experiencing a lack of sufficient pipeline transportation that is connected to markets that are purchasing the natural gas produced. This has resulted in negative natural gas prices for us in 2025 and continuing through 2026 to date, whereby we actually pay the purchaser to take our natural gas. These negative realized gas prices at times and conditions are continuing. If these depressed or inverted natural gas prices continue in the region, our natural gas revenues will continue to be negatively impacted.
Previous wording
Oil sales. Oil sales decreased approximately $43.8 million from $282.0 million to $238.2 million, with a price variance of $(40.8) million from a decrease in the average realized price per barrel from $76.77 to $65.54 as well as a volume variance of $(3.0) million due to a decrease in sales volume from 3,673,356 barrels to 3,633,739 barrels. The decrease in volume of 39,617 barrels consisted of two components: an increase in volumes of 299,770 was due to the Lime Rock Acquisition, and a decrease of 339,387 was attributed to natural production declines in the legacy assets. The Company's drilling and completion spend was 43% lower in the months that affected production for the first nine months of 2025 compared to the same months that affected production in the first nine months of 2024. This resulted in less offsets to declining production. The decreased average realized price per barrel was primarily the result of lower oil prices.
Current wording
Oil sales. Oil sales decreased approximately $0.3 million from $76.5 million to $76.2 million, with a price variance of $(1.6) million from a decrease in the average realized price per barrel from $70.40 to $68.97 offset by a volume variance of $1.3 million due to an increase in sales volume from 1,086,694 barrels to 1,104,823 barrels. The increase in volume of 18,129 barrels consisted of two components: an increase in volumes of 143,132 was due to the Lime Rock acquisition, and a decrease of 125,003 was attributed to natural production declines in the legacy assets. The Company's drilling and completion spend was 43% lower in the months that affected production for the first three months of 2026 compared to the same months that affected production in the first three months of 2025. This resulted in less offsets to declining production in the legacy assets. The decreased average realized price per barrel was primarily the result of lower oil prices.
Previous wording
Natural gas sales. Natural gas sales increased approximately $1.6 million from a negative $3.9 million to a negative $2.3 million. Our natural gas sales volumes increased from 1,705,027 Mcf to 1,853,599 Mcf, and the average realized price per Mcf increased from $(2.26) to $(1.22). Of the increase in volume of 148,572 Mcf, an increase of 168,823 Mcf was from the Lime Rock Acquisition and a decrease of 20,251 Mcf was attributable to legacy assets. The price increase was driven by improved market conditions. The realized revenue pricing included the impact of gas plant processing fees that were netted from revenue. For the three months ended September 30, 2025, gross revenues were $0.84 per Mcf and fees were $(2.06) per Mcf, compared to gross revenues of $(0.50) per Mcf and fees of $(1.76) per Mcf for the three months ended September 30, 2024. This resulted in a net realized price of $(1.22) per Mcf for the three months ended September 30, 2025 compared to $(2.26) per Mcf for the three months ended September 30, 2024.
Current wording
Natural gas sales. Natural gas sales decreased approximately $4.0 million from a negative $0.3 million to a negative $4.3 million. The natural gas sales volume increased from 1,615,196 Mcf to 1,689,512 Mcf, and the average realized price per Mcf decreased from $(0.19) to $(2.54). Of the increase in volume of 74,316 Mcf, an increase of 146,522 was due to the Lime Rock acquisition, offset by a decrease of 72,206 for our legacy assets. The price decrease was driven by lower market conditions. The realized revenue pricing includes the impact of gas plant processing fees that were netted from revenue. For the three months ended March 31, 2026, gross revenues were $(0.48) per Mcf and fees were $(2.06) per Mcf, compared to gross revenues of $1.86 per Mcf and fees of $(2.05) per Mcf for the three months ended March 31, 2025. This resulted in a net realized price of $(2.54) for the three months ended March 31, 2026 compared to $(0.19) per Mcf for the three months ended March 31, 2025.
Previous wording
Natural gas liquids sales. NGL sales slightly decreased by approximately $1.6 million from $8.5 million to $6.9 million. NGL sales volumes for the nine months ended September 30, 2025 were 1,009,881 barrels compared to 919,225 barrels for the comparable period in 2024. Of the increase in volume of 90,656 barrels, 61,303 was due to the Lime Rock Acquisition while the remaining 29,353 was from legacy assets. The average realized price per barrel decreased by $2.44 to $6.85 for the nine months ended September 30, 2025 compared to $9.29 for the nine months ended September 30, 2024, attributable to lower prices. Specifically, the gross realized price per NGL barrel was $19.53 and the average fees per barrel was $(12.68), resulting in a net realized price of $6.85 for the nine months ended September 30, 2025, while the gross realized price per barrel was $19.64 and the average fees per barrel was $(10.35), resulting in a net realized price of $9.29 for the same period in 2024.
Current wording
Natural gas liquids sales. NGL sales decreased approximately $1.1 million from $2.9 million to $1.8 million. NGL sales volumes for the three months ended March 31, 2026 were 355,173 barrels compared to 299,366 barrels for the comparable period in 2025. Of the increase in volume of 55,807 barrels, an increase of 40,450 was due to the Lime Rock acquisition, and an increase of 15,357 was from legacy assets. The average realized price per barrel decreased by $4.69 to $4.96 for the three months ended March 31, 2026 compared to $9.65 for the three months ended March 31, 2025, due to lower prices. Specifically, the gross realized price per NGL barrel was $17.42 and the average fees per barrel was $(12.46), resulting in a net realized price of $4.96 for the three months ended March 31, 2026, while the gross realized price per barrel was $22.64 and the average fees per barrel was $(12.99), resulting in a net realized price of $9.65 for the same period in 2025.
Previous wording
Lease operating expenses. Our total LOE increased from $58.0 million to $60.4 million and LOE per Boe increased from $10.77 to $10.98. Total LOE increased in accordance with a 2% increase in production of 123,160 Boe, as a result of the additional production and well count from the Lime Rock Acquisition as well as new wells drilled and completed in our development program. The primary cost driver for the period was an increase in electricity of $3.8 million. Other cost increases included environmental sustainability and cleanup of $1.0 million, communications of $0.6 million, contract and lease services of $0.5 million, and salt water disposal of $0.1 million. This was offset by reductions in LOE costs from workovers of $2.1 million, salaries of $0.6 million, hot oil paraffin control of $0.4 million, non-operated costs of $0.3 million and $0.2 million of pumping unit repairs.
Current wording
Lease operating expenses. Our total LOE decreased from $19.7 million to $18.1 million and LOE per Boe decreased from $11.89 to $10.41. Total LOE decreased despite a 5% increase in production of 86,322 Boe, as a result of the additional production and well count from the Lime Rock acquisition as well as new wells drilled and completed in our development program. The primary cost drivers for the period were decreases in contract and lease services of $1.0 million, chemicals of $0.9 million, equipment rentals of $0.5 million, location repairs and environmental sustainability of $0.3 million, non-op of $0.2 million, and contract pumping services of $0.1 million. This was offset by increases in LOE costs from salt water disposal of $0.5 million, salaries of $0.4 million, and workovers of $0.4 million.
Previous wording
Ad valorem taxes. Our total ad valorem taxes remained flat at $5.6 million and decreased on a per Boe basis from $1.05 to $1.02. A decrease in ad valorem taxes of $0.5 million was from the reversal of the 2024 methane tax accrual for the waste emissions charge ("WEC"), which was repealed by Congress on March 14, 2025. There was also a decrease in the Yoakum County estimates of approximately $0.9 million. These decreases were offset by increases of $1.3 million in Andrews County due primarily to the Lime Rock Acquisition and increases in the Ector County estimates of $0.1 million.
Current wording
Ad valorem taxes. Our total ad valorem taxes increased $0.7 million from $1.5 million to $2.2 million and increased on a per Boe basis from $0.93 to $1.26. An increase in ad valorem taxes of $0.5 million was from the reversal made in the first quarter of 2025 for the 2024 methane tax accrual for the waste emissions charge ("WEC"), which was repealed by Congress on March 14, 2025, with no similar reversal made in 2026. There was also an increase of $0.6 million in Andrews County due primarily to the Lime Rock acquisition. Offsetting these increases was a decrease in the Yoakum County estimates of approximately $0.4 million.
Previous wording
Oil and natural gas production taxes. Oil and natural gas production taxes as a percentage of oil and natural gas sales were 4.71% for the three months ended September 30, 2024 and decreased to 4.67% for the three months ended September 30, 2025. Both percentages are in line with historical rates.
Current wording
Oil and natural gas production taxes. Oil and natural gas production taxes as a percentage of oil and natural gas sales were 4.53% for the three months ended March 31, 2025 and increased to 4.82% for the three months ended March 31, 2026. The overall average percentage of production taxes to oil and gas sales was consistent period over period.
Previous wording
Depreciation, depletion and amortization. Our depreciation, depletion and amortization decreased approximately $0.7 million from $74.2 million to $73.4 million, with substantially all of the reduction from lower depletion. The decrease in depletion was primarily due to a a price variance of $(2.4) million, from a lower depletion expense per Boe, due to an increase in the amortization base. Offsetting this, depletion had a volume variance of $1.7 million from a increase of 123,160 in Boe produced. Our average depreciation, depletion and amortization per Boe decreased from $13.78 per Boe to $13.33 per Boe.
Current wording
Depreciation, depletion and amortization. Our depreciation, depletion and amortization decreased approximately $1.2 million from $22.6 million to $21.4 million, with substantially all of the reduction from lower depletion. The decrease in depletion was primarily due to a price variance of $(2.3) million, from a lower depletion expense per Boe, due to an increase in the amortization base. Offsetting this, depletion had a volume variance of approximately $1.2 million from a increase of 86,322 in Boe produced. Our average depreciation, depletion and amortization per Boe decreased from $13.66 per Boe to $12.29 per Boe.
Previous wording
Ceiling test impairment. As a result of the lower oil prices impacting the present value of estimated future net revenues, the Company incurred a ceiling test impairment on its oil and natural gas properties of $72.9 million.
Current wording
Ceiling test impairment. As a result of the lower oil prices impacting the present value of estimated future net revenues, the Company incurred a ceiling test impairment on its oil and natural gas properties of $162.1 million.
Previous wording
Asset retirement obligation accretion. Our ARO accretion increased by $42,150 from $1,057,213 to $1,099,363 primarily as a result of newly acquired and drilled wells, offset by those plugged and abandoned and sold.
Current wording
Asset retirement obligation accretion. Our ARO accretion increased by $68,947 from $326,549 to $395,496 primarily as a result of newly acquired and drilled wells, offset by those plugged and abandoned and sold.
Previous wording
Interest income. Interest income decreased from $143,704 to $74,253 as a result of $71,848 in lower earnings on excess cash balances in bank sweep accounts, offset by an increase of $2,397 in severance tax interest receipts.
Current wording
Interest income. Interest income decreased $19,529 from $90,058 to $70,529, as a result of $41,747 in lower earnings on excess cash balances in bank sweep accounts, offset by an increase of $22,218 in severance tax interest receipts.
Previous wording
Interest expense. Interest expense decreased by approximately $1.9 million from $33.2 million to $31.3 million as a result of lower interest rates, with a weighted average annual interest rate of 8.3% during the nine months ended September 30, 2025 compared to 9.3% during the nine months ended September 30, 2024. Offsetting this impact was higher amounts outstanding on our Credit Facility, with a weighted average daily debt of approximately $431.8 million during the nine months ended September 30, 2025 compared to approximately $418.5 million during the nine months ended September 30, 2024. Further offsetting this was the increase in deferred cash payment accretion from the Lime Rock Acquisition.
Current wording
Interest expense. Interest expense decreased by approximately $0.9 million from $9.5 million to $8.6 million, primarily due to a decrease in the amortization of deferred financing costs as a result of the amendment and restatement of the credit agreement in the second quarter of 2025. Interest on the Credit Facility decreased due to lower interest rates, with a weighted average annual interest rate of 7.3% during the three months ended March 31, 2026 compared to 8.3% during the three months ended March 31, 2025. Offsetting this impact was higher amounts outstanding on our Credit Facility, with a weighted average daily debt of approximately $430.4 million during the three months ended March 31, 2026 compared to approximately $393.3 million during the three months ended March 31, 2025.
Previous wording
Gain (loss) on derivative contracts. We recorded a gain on derivative contracts of $0.4 million for the three months ended September 30, 2025 compared to a gain on derivative contracts of $24.7 million for the three months ended September 30, 2024. For the derivative contract settlements, we recorded a realized gain of $2.6 million for the three months ended September 30, 2025 and a realized loss of $1.9 million for the three months ended September 30, 2024. The change of $4.5 million in the realized gain (loss) was primarily a result of more favorable settlements of crude oil derivative contracts during the current year. For the marked-to-market contracts, we recorded an unrealized loss of $2.1 million for the three months ended September 30, 2025 and an unrealized gain of $26.6 million for the three months ended September 30, 2024. The change in position was primarily due to the changes in crude oil futures prices.
Current wording
Gain (loss) on derivative contracts. We recorded a loss on derivative contracts of $82.2 million for the three months ended March 31, 2026 and a loss on derivative contracts of $0.9 million for the three months ended March 31, 2025. For the derivative contract settlements, we recorded a realized loss of $5.3 million for the three months ended March 31, 2026 compared with a realized loss of $0.6 million for the three months ended March 31, 2025. The change of $4.7 million in the realized derivative gain (loss) was primarily a result of less favorable settlements of crude oil derivative contracts during the current year. For the marked-to-market contracts, we recorded an unrealized loss of $77.0 million for the three months ended March 31, 2026 and an unrealized loss of $0.4 million for the three months ended March 31, 2025. This negative change in unrealized derivatives primarily reflects changes in the crude oil forward curve during the quarter, including a late quarter increase in forward prices, which reduced the fair value of the Company's outstanding crude oil derivative positions.
Previous wording
Gain (loss) on disposal of assets. The Company's gain on disposal of assets increased by $295,852 from $89,693 to $385,545 with $288,587 of the increase from the sale of leased vehicles as well as $7,265 from more favorable sales of Company owned vehicles.
Current wording
Gain (loss) on disposal of assets. The Company's gain on disposal of assets decreased by $124,610 from $124,610 to $— with $131,584 of the decrease from the sale of leased vehicles offset by $6,974 from selling owned vehicles.
Previous wording
Other income. Other income increased $134,026 from $25,686 to $159,712 due to an increase in income of $150,770 from a pipeline easement lease, offset by a reduction of $16,744 in income from the Company's charge card rebate program.
Current wording
Other income. Other income decreased $3,105 from $8,942 to $5,837 due to a reduction of $3,105 in income from the Company's charge card rebate program.
Previous wording
Provision for income taxes. The provision for income taxes changed from a provision of $10.1 million for the three months ended September 30, 2024 to a benefit of $12.8 million for the three months ended September 30, 2025. The provision for income taxes was calculated using the annual effective tax rate method based on our estimated earnings and estimated state and federal income taxes due for 2025, taking into account all applicable tax rates and laws.
Current wording
Provision for income taxes. The provision for income taxes changed from a provision of $3.0 million for the three months ended March 31, 2025 to a benefit of $12.0 million for the three months ended March 31, 2026. The provision for income taxes was calculated using the annual effective tax rate method based on our estimated earnings and estimated state and federal income taxes due for 2026, taking into account all applicable tax rates and laws.
Previous wording
As of September 30, 2025, we had cash on hand of $0.3 million, compared to $1.9 million as of December 31, 2024. We strive to keep our cash balance as low as possible to minimize our outstanding debt and associated interest. At certain times we reflect a zero book balance while utilizing the float on outstanding checks. We had net cash provided by operating activities for the nine months ended September 30, 2025 of $106.2 million, compared to net cash provided by operating activities of $147.1 million for the same period in 2024, which was primarily due to lower year to date revenues, which resulted in less cash received from purchasers. We had net cash used in investing activities of $144.2 million for the nine months ended September 30, 2025, compared to net cash used in investing activities of $113.2 million for the same period in 2024, driven by the payments made for the Lime Rock Acquisition in 2025, with no comparable payments made in 2024. This increase in acquisition payments was offset by a reduction in payments to develop oil and natural gas properties. Net cash provided by financing activities was $36.5 million for the nine months ended September 30, 2025 and net cash used in financing activities was $34.3 million for the nine months ended September 30, 2024, during which time $43.0 million was the net borrowing and $33.0 million was the net paydown of principal on our Credit Facility, respectively.
Current wording
As of March 31, 2026, we had cash on hand of $1.0 million, compared to $0.9 million as of December 31, 2025. We strive to keep our cash balance as low as possible to minimize our outstanding debt and associated interest. At certain times we reflect a zero book balance while utilizing the float on outstanding checks. We had net cash provided by operating activities for the three months ended March 31, 2026 of $25.9 million, compared to net cash provided by operating activities of $28.4 million for the same period in 2025, which was primarily due to lower year to date revenues, which resulted in less cash received from purchasers. We had net cash used in investing activities of $31.0 million for the three months ended March 31, 2026, compared to net cash used in investing activities of $102.6 million for the same period in 2025, driven by the payments made for the Lime Rock acquisition in 2025, with no comparable payments made to date in 2026. Payments to develop oil and natural gas properties grew slightly and the Company sold non-operated working interests in 2026, as reflected in proceeds from divestiture of oil and natural gas properties. Net cash provided by financing activities was $5.3 million for the three months ended March 31, 2026 and net cash provided by financing activities was $73.5 million for the three months ended March 31, 2025, during which time $6.0 million was the net borrowing and $75.0 million was the net borrowing of principal on our Credit Facility, respectively.
Previous wording
As of September 30, 2025, $428 million was outstanding on our Credit Facility and we were in compliance with all of the covenants under the Credit Facility. The Credit Facility matures in June 2029. The borrowing base under our Credit Facility is $585 million. The borrowing base is redetermined semi-annually each May and November. See "NOTE 8 — REVOLVING LINE OF CREDIT" in the Notes to the condensed financial statements for more information on our Credit Facility.
Current wording
As of March 31, 2026, $426 million was outstanding on our Credit Facility and we were in compliance with all of the covenants under the Credit Facility. The Credit Facility matures in June 2029. The borrowing base under our Credit Facility is $585 million. The borrowing base is redetermined semi-annually each May and November. See "NOTE 8 — REVOLVING LINE OF CREDIT" in the Notes to the condensed financial statements for more information on our Credit Facility.
Rearranged current paragraphs (1)
Current report — wording carried from elsewhere
As a result of the ceiling test, driven by a decrease in the twelve month average commodity price over the past few months, the Company recognized a non-cash impairment charge of $162.1 million for the three months ended March 31, 2026. Depending on market conditions, the Company's discounted future net revenues could continue to decline, which may trigger additional non-cash impairments recognized in future periods. Estimating potential future non-cash impairments is complex due to numerous factors affecting the ceiling test calculation, including but not limited to future prices, operating costs, upward or downward reserve revisions, reserve additions, and tax attributes. The amount of any additional non-cash impairment, if any, is not estimable at this time given the uncertainty of these factors.
Rearranged previous paragraphs (13)
Previous report — wording carried elsewhere
Oil, Natural Gas, and Natural Gas Liquids Revenues for the Nine Months Ended September 30, 2025 and 2024
Previous report — wording carried elsewhere
(1) Boe is calculated using six Mcf of natural gas as the equivalent of one barrel of oil.
Previous report — wording carried elsewhere
Natural gas sales. Natural gas sales increased approximately $2.9 million from a negative $7.7 million to a negative $4.8 million. The natural gas sales volume increased from 4,739,881 Mcf to 5,172,603 Mcf, and the average realized price per Mcf increased from $(1.61) to $(0.93). Of the increase in volume of 432,722 Mcf, an increase of 267,104 was due to the Lime Rock Acquisition, with the remaining increase of 165,618 from our legacy assets. The price increase was driven by more favorable market conditions. The realized revenue pricing includes the impact of gas plant processing fees that were netted from revenue. For the nine months ended September 30, 2025, gross revenues were $1.17 per Mcf and fees were $(2.10) per Mcf, compared to gross revenues of $0.09 per Mcf and fees of $(1.70) per Mcf for the nine months ended September 30, 2024. This resulted in a net realized price of $(0.93) for the nine months ended September 30, 2025 compared to $(1.61) per Mcf for the nine months ended September 30, 2024.
Previous report — wording carried elsewhere
Production Costs for the Nine Months Ended September 30, 2025 and 2024
Previous report — wording carried elsewhere
Other Costs and Operating Expenses for the Nine Months Ended September 30, 2025 and 2024
Previous report — wording carried elsewhere
Ceiling test impairment. As a result of the lower oil prices impacting the present value of estimated future net revenues, the Company incurred a ceiling test impairment on its oil and natural gas properties of $72.9 million.
Previous report — wording carried elsewhere
Operating lease expense. Our operating lease expense costs were the same period over period.
Previous report — wording carried elsewhere
Gain (loss) on disposal of assets. The Company's gain on disposal of assets increased by $105,642 from $— during the three months ended September 30, 2024 to $105,642 during the three months ended September 30, 2025, with all of the increase from the sale of leased vehicles.
Previous report — wording carried elsewhere
Other Income (Expense) for the Nine Months Ended September 30, 2025 and 2024
Previous report — wording carried elsewhere
Interest income. Interest income decreased $133,212 from $367,181 to $233,969, as a result of $142,976 in lower earnings on excess cash balances in bank sweep accounts, offset by an increase of $9,764 in severance tax interest receipts.
Previous report — wording carried elsewhere
Gain (loss) on derivative contracts. We recorded a gain on derivative contracts of $14.2 million for the nine months ended September 30, 2025 and a gain on derivative contracts of $3.9 million for the nine months ended September 30, 2024. For the derivative contract settlements, we recorded a realized gain of $2.7 million for the nine months ended September 30, 2025 compared with a realized loss of $5.9 million for the nine months ended September 30, 2024. The change of $8.6 million in the realized derivative gain (loss) was primarily a result of more favorable settlements of crude oil derivative contracts during the current year. For the marked-to-market contracts, we recorded an unrealized gain of $11.5 million for the nine months ended September 30, 2025 and an unrealized gain of $9.8 million for the nine months ended September 30, 2024. This positive change in unrealized derivatives primarily was due to the changes in natural gas futures prices on derivative contracts in the Company's portfolio.
Previous report — wording carried elsewhere
Benefit from (Provision for) Income Taxes: for the Nine Months Ended September 30, 2025 and 2024
Previous report — wording carried elsewhere
Provision for income taxes. The provision for income taxes changed from a provision of $18.6 million for the nine months ended September 30, 2024 to a benefit of $3.7 million for the nine months ended September 30, 2025. The provision for income taxes was calculated using the annual effective tax rate method based on our estimated earnings and estimated state and federal income taxes due for 2025, taking into account all applicable tax rates and laws.