Ring Energy Inc.
11/05/2026 | Press release | Distributed by Public on 11/05/2026 15:55
Quarterly Report for Quarter Ending September 30, 2026 (Form 10-Q)
Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our accompanying condensed financial statements and the notes to those condensed financial statements included elsewhere in this Quarterly Report. The following discussion includes forward-looking statements that reflect our plans, estimates and beliefs and our actual results could differ materially from those discussed in these forward-looking statements as a result of many factors, including those discussed under "Risk Factors," "Forward Looking Statements" and elsewhere in this Quarterly Report.
Overview
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.
Business Description and Plan of Operation
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.
Our operating strategy is centered on the following priorities:
•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.
•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.
•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.
•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.
2026 Developments and Operational Highlights
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.
During the second quarter of 2026, the Company drilled a total of seven wells and completed a total of four wells. Specifically, in the Northwest Shelf the Company drilled and completed one 1.5-mile horizontal well and one 1-mile horizontal well in Yoakum County, with a working interest of approximately 98% and 100%, respectively. In the Central Basin Platform, the Company drilled and completed one 1.5-mile horizontal well in Andrews County with a working interest of approximately 99%, and one 1.5-mile horizontal well in Crane County with a working interest of approximately 96%. The latter of these two wells, while completed, was not put on pump until the third quarter of 2026 and did not contribute significant volumes in the second quarter of 2026. Also in Crane County, the Company drilled three 2-mile horizontal wells, each with a working interest of 100%, and was in the process of drilling one SWD well. The three 2-mile horizontal wells represent the first laterals of this length drilled by the Company in an area that has been historically developed with vertical wells. All four of these wells are to be completed during the third quarter of 2026.
During the third quarter of 2026, the Company drilled a total of eight and completed a total of seven horizontal producing wells. Additionally, the Company completed the SWD well that was in the process of being drilled at the end of the second quarter. In the Central Basin Platform in Andrews County, the Company drilled and completed two 1.5-mile horizontal wells, both with a working interest of approximately 99%. In the Central Basin Platform in Crane County, the Company drilled six and completed five 2-mile horizontal wells, each with a working interest of 100%.
| Quarter | Area | Wells Drilled | Wells Completed |
Drilled Uncompleted ("DUC")
|
||||||||||||||||||||||
| 1Q 2026 | Northwest Shelf (Horizontal) | 5 | 5 | - | ||||||||||||||||||||||
|
Central Basin Platform (Horizontal) (1)
|
- | 1 | - | |||||||||||||||||||||||
| Central Basin Platform (Vertical) | 1 | 1 | - | |||||||||||||||||||||||
| Total | 6 | 7 | - | |||||||||||||||||||||||
| 2Q 2026 | Northwest Shelf (Horizontal) | 2 | 2 | - | ||||||||||||||||||||||
| Central Basin Platform (Horizontal) | 5 | 2 | 3 | |||||||||||||||||||||||
| Total | 7 | 4 | 3 | |||||||||||||||||||||||
| 3Q 2026 | Central Basin Platform (Horizontal) | 8 | 7 | 4 | ||||||||||||||||||||||
|
Total (2)
|
8 | 7 | 4 | |||||||||||||||||||||||
(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.
(2) The total does not include the SWD well that was completed in the third quarter of 2026.
Market Conditions and Commodity Price Risk Management
Our financial results are significantly affected by crude oil and natural gas prices, which are influenced by factors beyond our control, including domestic and global supply and demand, geopolitical and macroeconomic conditions, and regional transportation and processing constraints. Commodity prices have historically been volatile and may continue to fluctuate significantly.
During the third quarter of 2026, the Company benefited from higher realized oil prices compared with the prior year period. However, realized settlements on crude oil derivative contracts partially offset the benefit of higher oil prices, resulting in realized losses of approximately $12.3 million during the quarter. The Company's commodity derivative portfolio is designed to reduce exposure to commodity price volatility, support cash flow and liquidity, and satisfy applicable hedging requirements under its Credit Facility.
Natural gas prices in the Permian Basin remained challenged during the quarter due in part to regional transportation, processing and takeaway constraints, which adversely affected the Company's realized natural gas prices. The Company continues to monitor commodity market conditions and its commodity price risk management strategy in light of anticipated production, capital allocation priorities, balance sheet considerations and requirements under the Credit Facility.
Ceiling Test
The Company performs a ceiling test at the end of each reporting period to evaluate its oil and natural gas properties for potential non-cash impairment under the full cost method of accounting. The ceiling test is based on estimated future net revenues from proved reserves using the applicable twelve-month average commodity prices, discounted at an annual rate of 10% and is affected by changes in commodity prices, operating costs, reserve estimates, reserve additions and tax attributes.
No impairment was recorded for the three months ended September 30, 2026. For the nine months ended September 30, 2026, the Company recorded a non-cash impairment charge of $162.1 million, primarily as a result of lower oil prices reducing the present value of estimated future net revenues.
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, cannot be reasonably estimated at this time.
Inflation
Inflation has increased costs associated with our capital program and production operations. We have experienced increases in the costs of many of the materials, supplies, equipment and services used in our operations and we expect inflation to continue based on current economic circumstances, including tariffs, trade wars, and supply chain disruptions. We continue to closely monitor costs and take all reasonable steps to mitigate the inflationary effect on our cost structure and also work to enhance our efficiency to minimize additional cost increases where possible.
Results of Operations
Oil, Natural Gas, and Natural Gas Liquids Revenues for the Three Months Ended September 30, 2026 and 2025
| For the Three Months Ended | ||||||||||||||||||||||||||
| September 30, 2026 | September 30, 2025 | Change | % Change | |||||||||||||||||||||||
| Net sales: | ||||||||||||||||||||||||||
| Oil | $ | 98,726,711 | $ | 78,884,753 | $ | 19,841,958 | 25 | % | ||||||||||||||||||
| Natural gas | (568,258) | (2,253,323) | 1,685,065 | 75 | % | |||||||||||||||||||||
| Natural gas liquids | 4,185,209 | 1,969,906 | 2,215,303 | 112 | % | |||||||||||||||||||||
| Total sales | $ | 102,343,662 | $ | 78,601,336 | $ | 23,742,326 | 30 | % | ||||||||||||||||||
| Net production: | ||||||||||||||||||||||||||
| Oil (Bbls) | 1,179,247 | 1,226,537 | (47,290) | (4) | % | |||||||||||||||||||||
| Natural gas (Mcf) | 1,896,728 | 1,853,599 | 43,129 | 2 | % | |||||||||||||||||||||
| Natural gas liquids (Bbls) | 403,060 | 377,141 | 25,919 | 7 | % | |||||||||||||||||||||
|
Total production (Boe)(1)
|
1,898,428 | 1,912,611 | (14,183) | (1) | % | |||||||||||||||||||||
| Average sales price: | ||||||||||||||||||||||||||
| Oil (per Bbl) | $ | 83.72 | $ | 64.32 | $ | 19.40 | 30 | % | ||||||||||||||||||
| Natural gas (per Mcf) | (0.30) | (1.22) | 0.92 | 75 | % | |||||||||||||||||||||
| Natural gas liquids (Bbl) | 10.38 | 5.22 | 5.16 | 99 | % | |||||||||||||||||||||
| Total per Boe | $ | 53.91 | $ | 41.10 | $ | 12.81 | 31 | % | ||||||||||||||||||
(1) Boe is calculated using six Mcf of natural gas as the equivalent of one barrel of oil.
Oil sales. Oil sales increased approximately $19.8 million from $78.9 million to $98.7 million, driven by a price variance of approximately $22.9 million from an increase in the average realized price per barrel from $64.32 to $83.72 as a result of higher oil commodity prices. This was offset by a volume variance of approximately $(3.0) million from a decrease in sales volume from 1,226,537 barrels to 1,179,247 barrels. The decrease in volume of (47,290) barrels was attributed to natural production declines from our assets.
Natural gas sales. Natural gas sales increased approximately $1.7 million from a negative $2.3 million to a negative $0.6 million. Our natural gas sales volumes increased from 1,853,599 Mcf to 1,896,728 Mcf, and the average realized price per Mcf increased from $(1.22) to $(0.30). 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, 2026, gross revenues were $1.70 per Mcf and fees were $(2.00) per Mcf, compared to gross revenues of $0.84 per Mcf and fees of $(2.06) per Mcf for the three months ended September 30, 2025. This resulted in a net realized price of $(0.30) per Mcf for the three months ended September 30, 2026 compared to $(1.22) per Mcf for the three months ended September 30, 2025.
Natural gas liquids sales. NGL sales increased approximately $2.2 million from $2.0 million to $4.2 million. NGL sales volumes for the three months ended September 30, 2026 were 403,060 barrels compared to 377,141 barrels for the comparable period in 2025. The average realized price per barrel of NGLs was $10.38 for the three months ended September 30, 2026 compared to $5.22 for the three months ended September 30, 2025, due to stronger market conditions. Specifically, the gross realized price per NGL barrel was $22.82 and the average fees per barrel were $(12.44), resulting in a net realized price of $10.38 for the three months ended September 30, 2026, while the gross realized price per NGL barrel was $17.52 and the average fees per barrel were $(12.30), resulting in a net realized price of $5.22 for the same period in 2025.
Oil, Natural Gas, and Natural Gas Liquids Revenues for the Nine Months Ended September 30, 2026 and 2025
| For the Nine Months Ended | ||||||||||||||||||||||||||
| September 30, 2026 | September 30, 2025 | Change | % Change | |||||||||||||||||||||||
| Net sales: | ||||||||||||||||||||||||||
| Oil | $ | 285,098,930 | $ | 238,168,279 | $ | 46,930,651 | 20 | % | ||||||||||||||||||
| Natural gas | (14,043,727) | (4,794,987) | (9,248,740) | (193) | % | |||||||||||||||||||||
| Natural gas liquids | 9,641,612 | 6,922,010 | 2,719,602 | 39 | % | |||||||||||||||||||||
| Total sales | $ | 280,696,815 | $ | 240,295,302 | $ | 40,401,513 | 17 | % | ||||||||||||||||||
| Net production: | ||||||||||||||||||||||||||
| Oil (Bbls) | 3,438,217 | 3,633,739 | (195,522) | (5) | % | |||||||||||||||||||||
| Natural gas (Mcf) | 5,350,899 | 5,172,603 | 178,296 | 3 | % | |||||||||||||||||||||
| Natural gas liquids (Bbls) | 1,129,052 | 1,009,881 | 119,171 | 12 | % | |||||||||||||||||||||
|
Total production (Boe)(1)
|
5,459,086 | 5,505,721 | (46,635) | (1) | % | |||||||||||||||||||||
| Average sales price: | ||||||||||||||||||||||||||
| Oil (per Bbl) | $ | 82.92 | $ | 65.54 | $ | 17.38 | 27 | % | ||||||||||||||||||
| Natural gas (per Mcf) | (2.62) | (0.93) | (1.69) | (182) | % | |||||||||||||||||||||
| Natural gas liquids (Bbl) | 8.54 | 6.85 | 1.69 | 25 | % | |||||||||||||||||||||
| Total per Boe | $ | 51.42 | $ | 43.64 | $ | 7.78 | 18 | % | ||||||||||||||||||
(1) Boe is calculated using six Mcf of natural gas as the equivalent of one barrel of oil.
Oil sales. Oil sales increased approximately $46.9 million from $238.2 million to $285.1 million, with a price variance of $59.7 million from an increase in the average realized price per barrel from $65.54 to $82.92 as a result of higher oil commodity prices. This was offset by a volume variance of $(12.8) million due to a decrease in sales volume from 3,633,739 barrels to 3,438,217 barrels. The decrease in volume of 195,522 barrels was attributable to natural production declines in our assets.
Natural gas sales. Natural gas sales decreased approximately $9.2 million from a negative $4.8 million to a negative $14.0 million. The natural gas sales volume increased from 5,172,603 Mcf to 5,350,899 Mcf, and the average realized price per Mcf decreased from $(0.93) to $(2.62). Of the increase in volume of 178,296 Mcf, an increase of 133,316 was due to wells acquired and drilled in the Lime Rock acquisition area, and an increase of 44,980 was from 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 nine months ended September 30, 2026, gross revenues were $(0.54) per Mcf and fees were $(2.08) per Mcf, compared to gross revenues of $1.17 per Mcf and fees of $(2.10) per Mcf for the nine months ended September 30, 2025. This resulted in a net realized price of $(2.62) for the nine months ended September 30, 2026 compared to $(0.93) per Mcf for the nine months ended September 30, 2025.
Natural gas liquids sales. NGL sales increased approximately $2.7 million from $6.9 million to $9.6 million. NGL sales volumes for the nine months ended September 30, 2026 were 1,129,052 barrels compared to 1,009,881 barrels for the comparable period in 2025. Of the increase in volume of 119,171 barrels, an increase of 52,748 was due to wells acquired and drilled in the Lime Rock acquisition area, and an increase of 66,423 was from legacy assets. The average realized price per barrel increased by $1.69 to $8.54 for the nine months ended September 30, 2026 compared to $6.85 for the nine months ended September 30, 2025, due to higher commodity prices. Specifically, the gross realized price per NGL barrel was $20.98 and the average fees per barrel was $(12.44), resulting in a net realized price of $8.54 for the nine months ended September 30, 2026, while the gross realized price per barrel was $19.53 and the average fees per barrel was $(12.68), resulting in a net realized price of $6.85 for the same period in 2025.
Production Costs for the Three Months Ended September 30, 2026 and 2025
| For the Three Months Ended | ||||||||||||||||||||||||||
| September 30, 2026 | September 30, 2025 | Change | % Change | |||||||||||||||||||||||
| Lease operating expenses ("LOE") | $ | 19,367,227 | $ | 20,518,472 | $ | (1,151,245) | (6) | % | ||||||||||||||||||
| Average LOE per Boe | $ | 10.20 | $ | 10.73 | $ | (0.53) | (5) | % | ||||||||||||||||||
| Gathering, transportation and processing costs ("GTP") | $ | 180,787 | $ | 126,569 | $ | 54,218 | 43 | % | ||||||||||||||||||
| Average GTP per Boe | $ | 0.10 | $ | 0.07 | $ | 0.03 | 43 | % | ||||||||||||||||||
| Ad valorem taxes | $ | 2,210,911 | $ | 2,446,565 | $ | (235,654) | (10) | % | ||||||||||||||||||
| Average Ad valorem taxes per Boe | $ | 1.16 | $ | 1.28 | $ | (0.12) | (9) | % | ||||||||||||||||||
| Oil and natural gas production taxes | $ | 4,584,698 | $ | 3,670,987 | $ | 913,711 | 25 | % | ||||||||||||||||||
| Average Production taxes per Boe | $ | 2.41 | $ | 1.92 | $ | 0.49 | 26 | % | ||||||||||||||||||
| Production taxes as a percentage of total sales | 4.48 | % | 4.67 | % | (0.19) | % | (4) | % | ||||||||||||||||||
Lease operating expenses. Our total lease operating expenses ("LOE") decreased from $20.5 million to $19.4 million and decreased on a per Boe basis from $10.73 to $10.20. These per Boe amounts are calculated by dividing our total lease operating expenses by our total volume sold, in Boe. Total LOE decreased from targeted cost reductions as well as a 1% decrease in production of 14,183 Boe. The primary cost drivers for the period were decreases of $0.5 million in location repairs and environmental sustainability, $0.5 million in equipment rentals, $0.4 million in contract and lease services, and $0.3 million in electricity costs, $0.3 million in non-operated costs and $0.2 million in supplies, tools and materials, and $0.1 million in pumping unit repairs, offset by increases of $0.6 million in chemicals and $0.5 million in workovers.
Gathering, transportation and processing costs. Our total gathering, transportation and processing costs ("GTP") increased from $126,569 to $180,787 and increased slightly on a per Boe basis from $0.07 to $0.10. The increase in GTP costs was due to an increase of $34,440 in gas processing costs as well as an increase of $19,778 in NGL processing costs.
Ad valorem taxes. Our total ad valorem taxes decreased from $2.4 million to $2.2 million and decreased on a per Boe basis from $1.28 to $1.16. The $0.2 million decrease in ad valorem taxes was primarily from a decrease in Andrews County tax estimates.
Oil and natural gas production taxes. Oil and natural gas production taxes as a percentage of oil and natural gas sales were 4.67% for the three months ended September 30, 2025 and decreased to 4.48% for the three months ended September 30, 2026. Both percentages are in line with historical rates.
Production Costs for the Nine Months Ended September 30, 2026 and 2025
| For the Nine Months Ended | ||||||||||||||||||||||||||
| September 30, 2026 | September 30, 2025 | Change | % Change | |||||||||||||||||||||||
| Lease operating expenses ("LOE") | $ | 55,899,033 | $ | 60,442,005 | $ | (4,542,972) | (8) | % | ||||||||||||||||||
| Average LOE per Boe | $ | 10.24 | $ | 10.98 | $ | (0.74) | (7) | % | ||||||||||||||||||
| Gathering, transportation and processing costs ("GTP") | $ | 399,738 | $ | 463,990 | $ | (64,252) | (14) | % | ||||||||||||||||||
| Average GTP per Boe | $ | 0.07 | $ | 0.08 | $ | (0.01) | (13) | % | ||||||||||||||||||
| Ad valorem taxes | $ | 6,615,608 | $ | 5,627,320 | $ | 988,288 | 18 | % | ||||||||||||||||||
| Average Ad valorem taxes per Boe | $ | 1.21 | $ | 1.02 | $ | 0.19 | 19 | % | ||||||||||||||||||
| Oil and natural gas production taxes | $ | 13,186,208 | $ | 11,088,049 | $ | 2,098,159 | 19 | % | ||||||||||||||||||
| Average Production taxes per Boe | $ | 2.42 | $ | 2.01 | $ | 0.41 | 20 | % | ||||||||||||||||||
| Production taxes as a percentage of total sales | 4.70 | % | 4.61 | % | 0.09 | % | 2 | % | ||||||||||||||||||
Lease operating expenses. Our total LOE decreased from $60.4 million to $55.9 million and LOE per Boe decreased from $10.98 to $10.24. Total LOE decreased from targeted reductions in costs as well as a 1% decrease in production of 46,635 Boe. The primary cost drivers for the period included decreases in equipment rentals of $1.4 million, electricity costs of $1.3 million, contract and lease services of $1.2 million, chemicals of $0.9 million, location repairs and environmental sustainability of $0.8 million, non-operated costs of $0.6 million, and other employee expenses of $0.2 million. This was offset by increases in LOE costs from workovers of $1.2 million and salt water disposal of $0.7 million.
Gathering, transportation and processing costs. Our total GTP decreased $64,252 from $463,990 to $399,738 and decreased on a per Boe basis from $0.08 to $0.07. The decrease in GTP costs was due to a reduction of $83,474 in gas processing costs offset by an increase of $19,222 in NGL processing costs.
Ad valorem taxes. Our total ad valorem taxes increased $1.0 million from $5.6 million to $6.6 million and increased on a per Boe basis from $1.02 to $1.21. 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 $0.4 million in Andrews County due primarily to the Lime Rock acquisition as well as a $0.1 million increase from Crane County tax estimates. Offsetting these increases was a decrease in the Yoakum County tax estimates of approximately $0.1 million.
Oil and natural gas production taxes. Oil and natural gas production taxes as a percentage of oil and natural gas sales were 4.61% for the nine months ended September 30, 2025 and increased to 4.70% for the nine months ended September 30, 2026. The overall average percentage of production taxes to oil and gas sales was consistent period over period.
Other Costs and Operating Expenses for the Three Months Ended September 30, 2026 and 2025
| For the Three Months Ended | ||||||||||||||||||||||||||
| September 30, 2026 | September 30, 2025 | Change | % Change | |||||||||||||||||||||||
| Depreciation, depletion and amortization (DD&A): | ||||||||||||||||||||||||||
| Depletion | $ | 20,616,930 | $ | 24,902,199 | $ | (4,285,269) | (17) | % | ||||||||||||||||||
| Depreciation | 72,479 | 105,933 | (33,454) | (32) | % | |||||||||||||||||||||
| Amortization of financing lease assets | 211,324 | 217,213 | (5,889) | (3) | % | |||||||||||||||||||||
| Total depreciation, depletion and amortization | $ | 20,900,733 | $ | 25,225,345 | $ | (4,324,612) | (17) | % | ||||||||||||||||||
| Depletion per Boe | $ | 10.86 | $ | 13.02 | $ | (2.16) | (17) | % | ||||||||||||||||||
| Depreciation, depletion and amortization per Boe | $ | 11.01 | $ | 13.19 | $ | (2.18) | (17) | % | ||||||||||||||||||
| Ceiling test impairment | - | 72,912,330 | (72,912,330) | (100) | % | |||||||||||||||||||||
| Asset retirement obligation ("ARO") accretion | $ | 405,729 | $ | 390,563 | $ | 15,166 | 4 | % | ||||||||||||||||||
| Operating lease expense | $ | 124,187 | $ | 175,091 | $ | (50,904) | (29) | % | ||||||||||||||||||
| General and administrative expense ("G&A"): | ||||||||||||||||||||||||||
| G&A excluding share-based compensation | $ | 6,549,559 | $ | 6,521,171 | $ | 28,388 | - | % | ||||||||||||||||||
| Share-based compensation | 2,497,039 | 1,618,600 | 878,439 | 54 | % | |||||||||||||||||||||
| Total general and administrative expense | $ | 9,046,598 | $ | 8,139,771 | $ | 906,827 | 11 | % | ||||||||||||||||||
| G&A per Boe | $ | 4.77 | $ | 4.26 | $ | 0.51 | 12 | % | ||||||||||||||||||
| G&A excluding Share-based compensation, per Boe | $ | 3.45 | $ | 3.41 | $ | 0.04 | 1 | % | ||||||||||||||||||
Depreciation, depletion and amortization. Our depreciation, depletion and amortization decreased from $25.2 million to $20.9 million, with $4.3 million of the reduction from lower depletion. The decrease in depletion was the result of a price variance of $(4.1) million, due to a lower depletion rate per Boe, driven by a decrease in the total estimated costs of property from the impairment recognized in the last quarter of 2025 and the first quarter of 2026, coupled with an increase in the amortization base (total Boe). Also impacting the lower depletion was a volume variance of $(0.2) million from a decrease of 14,183 in Boe produced. Our average depreciation, depletion and amortization per Boe decreased from $13.19 per Boe to $11.01 per Boe.
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 during the three months ended September 30, 2025 of $72.9 million.
Asset retirement obligation accretion. Our asset retirement obligation ("ARO") accretion increased from $390,563 to $405,729 as a result of newly acquired and drilled wells, offset by those plugged and abandoned and sold.
Operating lease expense. Our operating lease expense costs decreased $50,904 from $175,091 to $124,187 due to the Woodlands expansion space lease being combined with the total Woodlands office lease.
General and administrative expense. General and administrative ("G&A") expense increased from $8.1 million to approximately $9.0 million. The approximate $0.9 million cost increase was primarily driven by an increase of $0.9
million in stock compensation, $0.6 million in other professional fees, $0.2 million in legal-attorney fees, and $0.2 million in employee health insurance offset by a decrease of $1.0 million in salaries and bonuses, which was impacted by the separation of a former executive in the third quarter of 2025.
Other Costs and Operating Expenses for the Nine Months Ended September 30, 2026 and 2025
| For the Nine Months Ended | ||||||||||||||||||||||||||
| September 30, 2026 | September 30, 2025 | Change | % Change | |||||||||||||||||||||||
| Depreciation, depletion and amortization (DD&A): | ||||||||||||||||||||||||||
| Depletion | $ | 61,588,426 | $ | 72,381,413 | $ | (10,792,987) | (15) | % | ||||||||||||||||||
| Depreciation | 214,912 | 309,211 | (94,299) | (30) | % | |||||||||||||||||||||
| Amortization of financing lease assets | 618,233 | 720,618 | (102,385) | (14) | % | |||||||||||||||||||||
| Total depreciation, depletion and amortization | $ | 62,421,571 | $ | 73,411,242 | $ | (10,989,671) | (15) | % | ||||||||||||||||||
| Depletion per Boe | $ | 11.28 | $ | 13.15 | $ | (1.87) | (14) | % | ||||||||||||||||||
| Depreciation, depletion and amortization per Boe | $ | 11.43 | $ | 13.33 | $ | (1.90) | (14) | % | ||||||||||||||||||
| Ceiling test impairment | $ | 162,086,257 | $ | 72,912,330 | $ | 89,173,927 | 122 | % | ||||||||||||||||||
| Asset retirement obligation ("ARO") accretion | $ | 1,203,169 | $ | 1,099,363 | $ | 103,806 | 9 | % | ||||||||||||||||||
| Operating lease expense | $ | 474,368 | $ | 525,272 | $ | (50,904) | (10) | % | ||||||||||||||||||
| General and administrative expense ("G&A"): | ||||||||||||||||||||||||||
| G&A excluding share-based compensation | $ | 18,268,163 | $ | 19,236,869 | $ | (968,706) | (5) | % | ||||||||||||||||||
| Share-based compensation | 6,171,443 | 4,661,397 | 1,510,046 | 32 | % | |||||||||||||||||||||
| Total general and administrative expense | $ | 24,439,606 | $ | 23,898,266 | $ | 541,340 | 2 | % | ||||||||||||||||||
| G&A per Boe | $ | 4.48 | $ | 4.34 | $ | 0.14 | 3 | % | ||||||||||||||||||
| G&A excluding Share-based compensation, per Boe | $ | 3.35 | $ | 3.49 | $ | (0.14) | (4) | % | ||||||||||||||||||
Depreciation, depletion and amortization. Our depreciation, depletion and amortization decreased approximately $11.0 million from $73.4 million to $62.4 million, with $10.8 million of the reduction from lower depletion. The decrease in depletion was primarily due to a price variance of $(10.2) million, from a lower depletion expense per Boe, due to reduction in the total estimated costs of property from the impairment recognized in the last quarter of 2025 and the first quarter of 2026, coupled with an increase in the amortization base (total Boe). Adding to this was a volume variance of approximately $(0.6) million from a decrease of 46,635 in Boe produced. Our average depreciation, depletion and amortization per Boe decreased from $13.33 per Boe to $11.43 per Boe.
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 during the nine months ended September 30, 2026 and $72.9 million during the nine months ended September 30, 2025.
Asset retirement obligation accretion. Our ARO accretion increased by $103,806 from $1,099,363 to $1,203,169 due to additional ARO accretion associated with properties acquired, as well as newly drilled wells, offset by those plugged and abandoned and sold.
Operating lease expense. Our operating lease expense costs decreased $50,904 from $525,272 to $474,368 due to the Woodlands expansion space lease being combined with the total Woodlands office lease.
General and administrative expense. G&A expense increased approximately $0.5 million from $23.9 million to $24.4 million, with the $0.5 million cost increase impacted by an increase of $1.5 million in stock compensation, $0.8 million in other professional fees, and $0.1 million in allowance for credit losses, offset by a decrease of $1.9 million in salaries and bonuses, which was impacted by the separation of a former executive in the third quarter of 2025.
Other Income (Expense) for the Three Months Ended September 30, 2026 and 2025
| For the Three Months Ended | ||||||||||||||||||||||||||
| September 30, 2026 | September 30, 2025 | Change | % Change | |||||||||||||||||||||||
| Interest income | $ | 108,728 | $ | 74,253 | $ | 34,475 | 46 | % | ||||||||||||||||||
| Interest expense: | ||||||||||||||||||||||||||
| Interest on revolving line of credit | $ | 6,675,690 | $ | 8,933,960 | $ | (2,258,270) | (25) | % | ||||||||||||||||||
| Fees associated with revolving line of credit | 285,535 | 179,056 | 106,479 | 59 | % | |||||||||||||||||||||
| Amortization of deferred financing costs | 673,731 | 693,625 | (19,894) | (3) | % | |||||||||||||||||||||
| Interest on financing lease liabilities | 22,582 | 24,330 | (1,748) | (7) | % | |||||||||||||||||||||
| Interest paid for notes payable | 23,172 | 25,710 | (2,538) | (10) | % | |||||||||||||||||||||
| Deferred cash payment accretion | - | 195,639 | (195,639) | (100) | % | |||||||||||||||||||||
| Other interest | 15,133 | - | 15,133 | 100 | % | |||||||||||||||||||||
| Total interest expense | $ | 7,695,843 | $ | 10,052,320 | $ | (2,356,477) | (23) | % | ||||||||||||||||||
| Gain (loss) on derivative contracts: | ||||||||||||||||||||||||||
| Realized gain (loss): | ||||||||||||||||||||||||||
| Crude oil | $ | (12,326,980) | $ | 2,065,490 | $ | (14,392,470) | (697) | % | ||||||||||||||||||
| Natural gas | 149,385 | 520,740 | (371,355) | (71) | % | |||||||||||||||||||||
| Total realized gain (loss) | $ | (12,177,595) | $ | 2,586,230 | $ | (14,763,825) | (571) | % | ||||||||||||||||||
| Unrealized gain (loss): | ||||||||||||||||||||||||||
| Crude oil | $ | (40,095,482) | $ | (3,526,149) | $ | (36,569,333) |
NM (1)
|
|||||||||||||||||||
| Natural gas | (927,203) | 1,384,224 | (2,311,427) | (167) | % | |||||||||||||||||||||
| Total unrealized gain (loss) | $ | (41,022,685) | $ | (2,141,925) | $ | (38,880,760) |
NM (1)
|
|||||||||||||||||||
| Total gain (loss) on derivative contracts: | $ | (53,200,280) | $ | 444,305 | $ | (53,644,585) |
NM (1)
|
|||||||||||||||||||
| Gain (loss) on disposal of assets | $ | 52,331 | $ | 105,642 | $ | (53,311) | (50) | % | ||||||||||||||||||
| Other income | $ | - | $ | - | $ | - | - | % | ||||||||||||||||||
(1) Not meaningful.
Interest income. Interest income increased from $74,253 to $108,728 as a result of $46,394 in increased interest on severance tax refund receipts, offset by $11,919 in lower earnings on excess cash balances in bank sweep accounts.
Interest expense. Interest expense decreased from $10.1 million to $7.7 million primarily due to lower amounts outstanding on the Credit Facility, with a weighted average daily debt of approximately $372.2 million during the third quarter of 2026 compared to approximately $445.1 million during the third quarter of 2025, coupled with a reduction in interest rates, with a weighted average annual interest rate of 7.5% in the third quarter of 2026 compared to 8.2% in the third quarter of 2025. Also impacting the decrease in interest expense was a reduction in deferred cash payment accretion related to the Lime Rock acquisition which was closed in March 2025.
Gain (loss) on derivative contracts. We recorded a loss on derivative contracts of $53.2 million for the three months ended September 30, 2026 compared to a gain on derivative contracts of $0.4 million for the three months ended September 30, 2025. For the derivative contract settlements, we recorded a realized loss of $12.2 million for the three months ended September 30, 2026 and a realized gain of $2.6 million for the three months ended September 30, 2025. The change of $14.8 million in the realized 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 $41.0 million for the three months ended September 30, 2026 and an unrealized loss of $2.1 million for the three months ended September 30, 2025. The change in position was primarily due to the changes in crude oil futures prices.
Gain (loss) on disposal of assets. The Company's gain on disposal of assets decreased by $53,311 from $105,642 during the three months ended September 30, 2025 to $52,331 during the three months ended September 30, 2026, with the reduction of $53,311 from the sale of leased vehicles.
Other Income (Expense) for the Nine Months Ended September 30, 2026 and 2025
| For the Nine Months Ended | ||||||||||||||||||||||||||
| September 30, 2026 | September 30, 2025 | Change | % Change | |||||||||||||||||||||||
| Interest income | $ | 327,797 | $ | 233,969 | $ | 93,828 | 40 | % | ||||||||||||||||||
| Interest expense: | ||||||||||||||||||||||||||
| Interest on revolving line of credit | $ | 21,795,556 | $ | 26,364,419 | $ | (4,568,863) | (17) | % | ||||||||||||||||||
| Fees associated with revolving line of credit | 694,146 | 666,904 | 27,242 | 4 | % | |||||||||||||||||||||
| Amortization of deferred financing costs | 2,058,721 | 3,768,292 | (1,709,571) | (45) | % | |||||||||||||||||||||
| Interest on financing lease liabilities | 72,129 | 80,709 | (8,580) | (11) | % | |||||||||||||||||||||
| Interest paid for notes payable | 39,319 | 42,876 | (3,557) | (8) | % | |||||||||||||||||||||
| Deferred cash payment accretion | - | 385,310 | (385,310) | (100) | % | |||||||||||||||||||||
| Other interest | 15,133 | - | 15,133 | 100 | % | |||||||||||||||||||||
| Total interest expense | $ | 24,675,004 | $ | 31,308,510 | $ | (6,633,506) | (21) | % | ||||||||||||||||||
| Gain (loss) on derivative contracts: | ||||||||||||||||||||||||||
| Realized gain (loss): | ||||||||||||||||||||||||||
| Crude oil | $ | (38,002,808) | $ | 1,858,524 | $ | (39,861,332) |
NM (1)
|
|||||||||||||||||||
| Natural gas | 2,090,122 | 851,955 | 1,238,167 | 145 | % | |||||||||||||||||||||
| Total realized gain (loss) | $ | (35,912,686) | $ | 2,710,479 | $ | (38,623,165) |
NM (1)
|
|||||||||||||||||||
| Unrealized gain (loss): | ||||||||||||||||||||||||||
| Crude oil | $ | (80,531,788) | $ | 10,961,216 | $ | (91,493,004) | (835) | % | ||||||||||||||||||
| Natural gas | 4,737,695 | 491,874 | 4,245,821 | 863 | % | |||||||||||||||||||||
| Total unrealized gain (loss) | $ | (75,794,093) | $ | 11,453,090 | $ | (87,247,183) | (762) | % | ||||||||||||||||||
| Total gain (loss) on derivative contracts: | $ | (111,706,779) | $ | 14,163,569 | $ | (125,870,348) | (889) | % | ||||||||||||||||||
| Gain (loss) on disposal of assets | $ | 156,481 | $ | 385,545 | $ | (229,064) | (59) | % | ||||||||||||||||||
| Other income | $ | 15,437 | $ | 159,712 | $ | (144,275) | (90) | % | ||||||||||||||||||
(1) Not meaningful.
Interest income. Interest income increased $93,828 from $233,969 to $327,797, as a result of increase of $68,612 in interest on severance tax refund receipts as well as $25,216 in higher earnings on excess cash balances in bank sweep accounts.
Interest expense. Interest expense decreased by approximately $6.6 million from $31.3 million to $24.7 million, due to lower interest rates, with a weighted average annual interest rate of 7.4% during the nine months ended September 30, 2026 compared to 8.3% during the nine months ended September 30, 2025, as well as lower amounts outstanding on our Credit Facility, with a weighted average daily debt of approximately $405.6 million during the nine months ended September 30, 2026 compared to approximately $431.8 million during the nine months ended September 30, 2025. Also impacting the reduction in interest expense was 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.
Gain (loss) on derivative contracts. We recorded a loss on derivative contracts of $111.7 million for the nine months ended September 30, 2026 and a gain on derivative contracts of $14.2 million for the nine months ended September 30, 2025. For the derivative contract settlements, we recorded a realized loss of $35.9 million for the nine months ended September 30, 2026 compared with a realized gain of $2.7 million for the nine months ended September 30, 2025. The change of $38.6 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 $75.8 million for the nine months ended September 30, 2026 and an unrealized gain of $11.5 million for the nine months ended September 30, 2025. This negative change in unrealized derivatives primarily reflects changes in the crude oil forward pricing curve.
Gain (loss) on disposal of assets. The Company's gain on disposal of assets decreased by $229,064 from $385,545 to $156,481 with $259,180 of the decrease from the sale of leased vehicles offset by a positive $30,116 from selling owned vehicles.
Other income. Other income decreased $144,275 from $159,712 to $15,437 due to a reduction of $150,770 from a pipeline easement lease and a reduction of $3,105 in income from the Company's charge card rebate program, offset by an increase of $9,600 in income from a ranching lease.
Benefit from (Provision for) Income Taxes: for the Three Months Ended September 30, 2026 and 2025
| For the Three Months Ended | ||||||||||||||||||||||||||
| September 30, 2026 | September 30, 2025 | Change | % Change | |||||||||||||||||||||||
| Benefit from (Provision for) Income Taxes: | ||||||||||||||||||||||||||
| Deferred federal income tax benefit (provision) | $ | (1,571,208) | $ | 12,558,220 | $ | (14,129,428) | (113) | % | ||||||||||||||||||
| Current state income tax benefit (provision) | 124,460 | (39,816) | 164,276 | 413 | % | |||||||||||||||||||||
| Deferred state income tax benefit (provision) | 58,791 | 282,543 | (223,752) | (79) | % | |||||||||||||||||||||
| Benefit from (Provision for) Income Taxes | $ | (1,387,957) | $ | 12,800,947 | $ | (14,188,904) | (111) | % | ||||||||||||||||||
Provision for income taxes. The provision for income taxes changed from a benefit of $12.8 million for the three months ended September 30, 2025 to a provision of $1.4 million for the three months ended September 30, 2026, due to the decrease in pre-tax book loss for the three months ended September 30, 2026, netted against the recording of the valuation allowance. 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.
Benefit from (Provision for) Income Taxes: for the Nine Months Ended September 30, 2026 and 2025
| For the Nine Months Ended | ||||||||||||||||||||||||||
| September 30, 2026 | September 30, 2025 | Change | % Change | |||||||||||||||||||||||
| Benefit from (Provision for) Income Taxes: | ||||||||||||||||||||||||||
| Deferred federal income tax benefit (provision) | $ | 8,589,134 | $ | 3,965,817 | $ | 4,623,317 | 117 | % | ||||||||||||||||||
| Current state income tax benefit (provision) | (30,776) | (323,670) | 292,894 | 90 | % | |||||||||||||||||||||
| Deferred state income tax benefit (provision) | 954,052 | 10,198 | 943,854 |
NM (1)
|
||||||||||||||||||||||
| Benefit from (Provision for) Income Taxes | $ | 9,512,410 | $ | 3,652,345 | $ | 5,860,065 | 160 | % | ||||||||||||||||||
(1) Not meaningful
Provision for income taxes. The provision for income taxes changed from a benefit of $3.7 million for the nine months ended September 30, 2025 to a benefit of $9.5 million for the nine months ended September 30, 2026 due to the change in the valuation allowance and the ceiling test impairment booked. 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.
Liquidity and Capital Resources
Cash Flows
As of September 30, 2026, we had cash on hand of $1.5 million, compared to $0.9 million as of December 31, 2025. We actively manage our cash to optimize liquidity and minimize outstanding debt and associated interest costs. 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, 2026 of $129.7 million, compared to net cash provided by operating activities of $106.2 million for the same period in 2025, which was due to higher year to date revenues, which resulted in more cash received from purchasers, offset by higher realized derivative losses. We had net cash used in investing activities of $122.8 million for the nine months ended September 30, 2026, compared to net cash used in investing activities of $144.2 million for the same period in 2025, driven by the payments made for the Lime Rock acquisition in 2025, with no comparable acquisition made to date in 2026. Capital expenditures for the development of oil and natural gas properties grew significantly and the Company sold non-operated working interests and non-core assets in 2026, as reflected in proceeds from divestiture of oil and natural gas properties. Net cash used in financing activities was $6.4 million for the nine months ended September 30, 2026 and net cash provided by financing activities was $36.5 million for the nine months ended September 30, 2025, during which time $70.0 million was the net paydown and $43.0 million was the net borrowing of principal on our Credit Facility, respectively.
We will continue to focus on maximizing cash flow in 2026 through a combination of cost monitoring and prudent capital allocation, which will include prioritizing our capital to projects we believe will provide high rates of return in the current commodity price environment. We will continue our pursuit of acquisitions and business combinations, seeking opportunities that we believe will provide high margin properties with attractive returns at current commodity prices, ultimately pushing to reduce our debt level and maximize our liquidity.
Availability of Capital Resources under Credit Facility
As of September 30, 2026, $350 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.
Equity Offering
In May 2026, the Company completed an underwritten public offering of 44,444,445 shares of common stock at a public offering price of $1.35 per share and gross proceeds of $60.0 million. In June 2026, the underwriters exercised an option to purchase an additional 6,666,666 shares of common stock at a public offering price of $1.35 per share and gross proceeds of $9.0 million. The sale of common stock resulted in total gross proceeds of $69.0 million and net proceeds of $64.5 million, after deducting underwriting fees and offering expenses.
Derivative Financial Instruments
The following table reflects the contracts outstanding as of September 30, 2026 (quantities are in barrels (Bbl) for the oil derivative contracts and in million British thermal units (MMBtu) for the natural gas derivative contracts):
| Oil Hedges (WTI) | Q4 2026 | Q1 2027 | Q2 2027 | Q3 2027 | Q4 2027 | Q1 2028 | Q2 2028 | Q3 2028 | |||||||||||||||||||||||||||||||||||||||
| Swaps: | |||||||||||||||||||||||||||||||||||||||||||||||
| Hedged volume (Bbl) | 529,000 | 509,500 | 492,000 | 432,000 | 412,963 | - | - | - | |||||||||||||||||||||||||||||||||||||||
| Weighted average swap price | $ | 65.34 | $ | 62.82 | $ | 60.45 | $ | 61.80 | $ | 57.59 | $ | - | $ | - | $ | - | |||||||||||||||||||||||||||||||
| Two-way collars: | |||||||||||||||||||||||||||||||||||||||||||||||
| Hedged volume (Bbl) | 368,000 | 272,935 | - | 32,910 | 33,435 | 430,080 | 415,580 | 402,614 | |||||||||||||||||||||||||||||||||||||||
| Weighted average put price | $ | 65.00 | $ | 64.97 | $ | - | $ | 60.00 | $ | 60.00 | $ | 55.59 | $ | 57.50 | $ | 60.00 | |||||||||||||||||||||||||||||||
| Weighted average call price | $ | 80.00 | $ | 98.45 | $ | - | $ | 72.30 | $ | 72.30 | $ | 66.02 | $ | 73.02 | $ | 77.21 | |||||||||||||||||||||||||||||||
| Swaps: WTI NYMEX Rolls | |||||||||||||||||||||||||||||||||||||||||||||||
| Hedged volume (BBL) | 455,000 | - | - | - | - | - | - | - | |||||||||||||||||||||||||||||||||||||||
| Weighted average swap price | $ | 5.71 | $ | - | $ | - | $ | - | $ | - | $ | - | $ | - | $ | - | |||||||||||||||||||||||||||||||
| Gas Hedges (Henry Hub) | Q4 2026 | Q1 2027 | Q2 2027 | Q3 2027 | Q4 2027 | Q1 2028 | Q2 2028 | Q3 2028 | |||||||||||||||||||||||||||||||||||||||
| NYMEX Swaps: | |||||||||||||||||||||||||||||||||||||||||||||||
| Hedged volume (MMBtu) | 1,072,305 | 439,678 | 423,035 | 1,079,906 | 1,046,151 | 1,012,567 | 984,322 | 956,865 | |||||||||||||||||||||||||||||||||||||||
| Weighted average swap price | $ | 3.99 | $ | 4.02 | $ | 4.02 | $ | 3.86 | $ | 4.02 | $ | 3.77 | $ | 3.77 | $ | 3.77 | |||||||||||||||||||||||||||||||
| Two-way collars: | |||||||||||||||||||||||||||||||||||||||||||||||
| Hedged volume (MMBtu) | 128,000 | 717,000 | 694,000 | - | - | - | - | - | |||||||||||||||||||||||||||||||||||||||
| Weighted average put price | $ | 3.50 | $ | 3.99 | $ | 3.00 | $ | - | $ | - | $ | - | $ | - | $ | - | |||||||||||||||||||||||||||||||
| Weighted average call price | $ | 5.42 | $ | 5.21 | $ | 4.32 | $ | - | $ | - | $ | - | $ | - | $ | - | |||||||||||||||||||||||||||||||
| Gas Hedges (Henry Hub) | Q4 2028 | Q1 2029 | Q2 2029 | Q3 2029 | Q4 2029 | Q1 2030 | Q2 2030 | ||||||||||||||||||||||||||||||||||
| NYMEX Swaps: | |||||||||||||||||||||||||||||||||||||||||
| Hedged volume (MMBtu) | 931,539 | 908,117 | 886,933 | 866,585 | 846,134 | - | - | ||||||||||||||||||||||||||||||||||
| Weighted average swap price | $ | 3.77 | $ | 3.67 | $ | 3.67 | $ | 3.67 | $ | 3.67 | $ | - | $ | - | |||||||||||||||||||||||||||
| Gas Hedges (basis differential) | Q4 2026 | Q1 2027 | Q2 2027 | Q3 2027 | Q4 2027 | Q1 2028 | Q2 2028 | Q3 2028 | |||||||||||||||||||||||||||||||||||||||
| Waha basis swaps: | |||||||||||||||||||||||||||||||||||||||||||||||
| Hedged volume (MMBtu) | 411,451 | 196,372 | 480,325 | 464,360 | 449,846 | 435,403 | - | - | |||||||||||||||||||||||||||||||||||||||
|
Weighted average spread price (1)
|
$ | 1.81 | $ | 0.78 | $ | 0.78 | $ | 0.78 | $ | 0.78 | $ | 0.68 | $ | - | $ | - | |||||||||||||||||||||||||||||||
| El Paso Permian Basin basis swaps: | |||||||||||||||||||||||||||||||||||||||||||||||
| Hedged volume (MMBtu) | 788,851 | 960,307 | 636,710 | 615,547 | 596,306 | 577,163 | - | - | |||||||||||||||||||||||||||||||||||||||
|
Weighted average spread price (1)
|
$ | 1.92 | $ | 0.72 | $ | 0.67 | $ | 0.67 | $ | 0.67 | $ | 0.60 | $ | - | $ | - | |||||||||||||||||||||||||||||||
| Gas Hedges (basis differential) | Q4 2028 | Q1 2029 | Q2 2029 | Q3 2029 | Q4 2029 | Q1 2030 | Q2 2030 | ||||||||||||||||||||||||||||||||||
| Waha basis swaps: | |||||||||||||||||||||||||||||||||||||||||
| Hedged volume (MMBtu) | - | - | - | 259,975 | 253,840 | - | - | ||||||||||||||||||||||||||||||||||
|
Weighted average spread price (1)
|
$ | - | $ | - | $ | - | $ | 0.61 | $ | 0.71 | $ | - | $ | - | |||||||||||||||||||||||||||
| El Paso Permian Basin basis swaps: | |||||||||||||||||||||||||||||||||||||||||
| Hedged volume (MMBtu) | - | - | - | 606,610 | 592,294 | - | - | ||||||||||||||||||||||||||||||||||
|
Weighted average spread price (1)
|
$ | - | $ | - | $ | - | $ | 0.54 | $ | 0.64 | $ | - | $ | - | |||||||||||||||||||||||||||
(1) The gas basis swap hedges are calculated as the Henry Hub natural gas price less the fixed amount specified as the weighted average spread price above.
Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the accompanying Condensed Balance Sheets. Any gains or losses resulting from changes in fair value of outstanding derivative financial instruments and from the settlement of derivative financial instruments are recognized in earnings and included as a component of Other Income (Expense) in the accompanying Condensed Statements of Operations.
The use of derivative transactions involves the risk that the counterparties, which generally are financial institutions, will be unable to meet the financial terms of such transactions. At September 30, 2026, 100% of our derivative instruments were with lenders under our Credit Facility.
Effects of Inflation and Pricing
The oil and natural gas industry is cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry puts significant pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do associated costs. Material changes in prices impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, and the value of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money, and retain personnel. We anticipate business costs will vary in accordance with commodity prices for oil and natural gas, and the associated increase or decrease in demand for services related to production and exploration.
Off-Balance Sheet Financing Arrangements
As of September 30, 2026, we had no off-balance sheet financing arrangements.
Capital Resources for Future Acquisition and Development Opportunities
We continuously evaluate potential acquisitions and development opportunities. To the extent possible, we intend to acquire producing properties with lower-risk undeveloped drilling opportunities rather than properties with higher-risk exploratory opportunities. We do not intend to limit our evaluation to any one state, but we presently have no intention to acquire offshore properties or properties located outside of the United States.
The pursuit of and the acquisition of accretive oil and gas properties is highly competitive and may require substantially greater capital than we currently have available and obtaining additional capital may require that we obtain either short-term or long-term debt or sell our equity or both. Further, it may be necessary for us to retain outside consultants and others in our endeavors to locate desirable oil and gas properties.
The process of acquiring one or more additional oil and gas properties would impact our financial position, reduce our cash position and likely increase our debt levels. The types of costs that we may incur include the costs to retain consultants and investment bankers specializing in the purchase of oil and gas properties, obtaining petroleum engineering reports relative to the oil and gas properties that we are investigating, legal fees associated with any such acquisitions including title reports, SEC reporting expenses, and negotiating definitive agreements. Additionally, accounting fees may be incurred relative to obtaining and evaluating historical and pro forma information regarding oil and gas properties. Even though we may incur these costs, there is no assurance that we will ultimately be able to consummate additional acquisitions of oil and gas producing properties.
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