Ring Energy Inc.
11/06/2025 | Press release | Distributed by Public on 11/06/2025 16:01
Quarterly Report for Quarter Ending September 30, 2025 (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 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.
Business Description and Plan of Operation
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.
•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.
•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.
•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.
•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.
2025 Developments and Highlights
Lime Rock Acquisition
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.
Drilling and Completion
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%.
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%.
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%.
The table below sets forth our drilling and completion activities for the nine months ended September 30, 2025.
| Quarter | Area | Wells Drilled | Wells Completed | |||||||||||||||||
| 1Q 2025 | Northwest Shelf (Horizontal) | 4 | 4 | |||||||||||||||||
| Central Basin Platform (Vertical) | 3 | 3 | ||||||||||||||||||
| Total | 7 | 7 | ||||||||||||||||||
| 2Q 2025 | Central Basin Platform (Horizontal) | 1 | 1 | |||||||||||||||||
| Central Basin Platform (Vertical) | 1 | 1 | ||||||||||||||||||
| Total | 2 | 2 | ||||||||||||||||||
| 3Q 2025 | Central Basin Platform (Horizontal) | 4 | 4 | |||||||||||||||||
| Central Basin Platform (Vertical) | 1 | 1 | ||||||||||||||||||
| Total | 5 | 5 | ||||||||||||||||||
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.
(1) Total does not include the SWD well(s) drilled and completed in the [ ].
Market Conditions and Commodity Prices
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.
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.
Ceiling Test
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.
Natural Gas Takeaway Capacity
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.
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, 2025 and 2024
| For the Three Months Ended | ||||||||||||||||||||||||||
| September 30, 2025 | September 30, 2024 | Change | % Change | |||||||||||||||||||||||
| Net sales: | ||||||||||||||||||||||||||
| Oil | $ | 78,884,753 | $ | 90,416,363 | $ | (11,531,610) | (13) | % | ||||||||||||||||||
| Natural gas | (2,253,323) | (3,859,603) | 1,606,280 | 42 | % | |||||||||||||||||||||
| Natural gas liquids | 1,969,906 | 2,687,623 | (717,717) | (27) | % | |||||||||||||||||||||
| Total sales | $ | 78,601,336 | $ | 89,244,383 | $ | (10,643,047) | (12) | % | ||||||||||||||||||
| Net production: | ||||||||||||||||||||||||||
| Oil (Bbls) | 1,226,537 | 1,214,788 | 11,749 | 1 | % | |||||||||||||||||||||
| Natural gas (Mcf) | 1,853,599 | 1,705,027 | 148,572 | 9 | % | |||||||||||||||||||||
| Natural gas liquids (Bbls) | 377,141 | 350,975 | 26,166 | 7 | % | |||||||||||||||||||||
|
Total production (Boe)(1)
|
1,912,611 | 1,849,934 | 62,677 | 3 | % | |||||||||||||||||||||
| Average sales price: | ||||||||||||||||||||||||||
| Oil (per Bbl) | $ | 64.32 | $ | 74.43 | $ | (10.11) | (14) | % | ||||||||||||||||||
| Natural gas (per Mcf) | (1.22) | (2.26) | 1.04 | 46 | % | |||||||||||||||||||||
| Natural gas liquids (Bbl) | 5.22 | 7.66 | (2.44) | (32) | % | |||||||||||||||||||||
| Total per Boe | $ | 41.10 | $ | 48.24 | $ | (7.14) | (15) | % | ||||||||||||||||||
(1) Boe is calculated using six Mcf of natural gas as the equivalent of one barrel of oil.
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.
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.
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.
Oil, Natural Gas, and Natural Gas Liquids Revenues for the Nine Months Ended September 30, 2025 and 2024
| For the Nine Months Ended | ||||||||||||||||||||||||||
| September 30, 2025 | September 30, 2024 | Change | % Change | |||||||||||||||||||||||
| Net sales: | ||||||||||||||||||||||||||
| Oil | $ | 238,168,279 | $ | 282,000,446 | $ | (43,832,167) | (16) | % | ||||||||||||||||||
| Natural gas | (4,794,987) | (7,650,645) | 2,855,658 | 37 | % | |||||||||||||||||||||
| Natural gas liquids | 6,922,010 | 8,537,067 | (1,615,057) | (19) | % | |||||||||||||||||||||
| Total sales | $ | 240,295,302 | $ | 282,886,868 | $ | (42,591,566) | (15) | % | ||||||||||||||||||
| Net production: | ||||||||||||||||||||||||||
| Oil (Bbls) | 3,633,739 | 3,673,356 | (39,617) | (1) | % | |||||||||||||||||||||
| Natural gas (Mcf) | 5,172,603 | 4,739,881 | 432,722 | 9 | % | |||||||||||||||||||||
| Natural gas liquids (Bbls) | 1,009,881 | 919,225 | 90,656 | 10 | % | |||||||||||||||||||||
|
Total production (Boe)(1)
|
5,505,721 | 5,382,561 | 123,160 | 2 | % | |||||||||||||||||||||
| Average sales price: | ||||||||||||||||||||||||||
| Oil (per Bbl) | $ | 65.54 | $ | 76.77 | $ | (11.23) | (15) | % | ||||||||||||||||||
| Natural gas (per Mcf) | (0.93) | (1.61) | 0.68 | 42 | % | |||||||||||||||||||||
| Natural gas liquids (Bbl) | 6.85 | 9.29 | (2.44) | (26) | % | |||||||||||||||||||||
| Total per Boe | $ | 43.64 | $ | 52.56 | $ | (8.92) | (17) | % | ||||||||||||||||||
(1) Boe is calculated using six Mcf of natural gas as the equivalent of one barrel of oil.
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.
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.
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.
Production Costs for the Three Months Ended September 30, 2025 and 2024
| For the Three Months Ended | ||||||||||||||||||||||||||
| September 30, 2025 | September 30, 2024 | Change | % Change | |||||||||||||||||||||||
| Lease operating expenses ("LOE") | $ | 20,518,472 | $ | 20,315,282 | $ | 203,190 | 1 | % | ||||||||||||||||||
| Average LOE per Boe | $ | 10.73 | $ | 10.98 | $ | (0.25) | (2) | % | ||||||||||||||||||
| Gathering, transportation and processing costs ("GTP") | $ | 126,569 | $ | 102,420 | $ | 24,149 | 24 | % | ||||||||||||||||||
| Average GTP per Boe | $ | 0.07 | $ | 0.06 | $ | 0.01 | 17 | % | ||||||||||||||||||
| Ad valorem taxes | $ | 2,446,565 | $ | 2,164,562 | $ | 282,003 | 13 | % | ||||||||||||||||||
| Average Ad valorem taxes per Boe | $ | 1.28 | $ | 1.17 | $ | 0.11 | 9 | % | ||||||||||||||||||
| Oil and natural gas production taxes | $ | 3,670,987 | $ | 4,203,851 | $ | (532,864) | (13) | % | ||||||||||||||||||
| Average Production taxes per Boe | $ | 1.92 | $ | 2.27 | $ | (0.35) | (15) | % | ||||||||||||||||||
| Production taxes as a percentage of total sales | 4.67 | % | 4.71 | % | (0.04) | % | (1) | % | ||||||||||||||||||
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.
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.
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.
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.
Production Costs for the Nine Months Ended September 30, 2025 and 2024
| For the Nine Months Ended | ||||||||||||||||||||||||||
| September 30, 2025 | September 30, 2024 | Change | % Change | |||||||||||||||||||||||
| Lease operating expenses ("LOE") | $ | 60,442,005 | $ | 57,984,733 | $ | 2,457,272 | 4 | % | ||||||||||||||||||
| Average LOE per Boe | $ | 10.98 | $ | 10.77 | $ | 0.21 | 2 | % | ||||||||||||||||||
| Gathering, transportation and processing costs ("GTP") | $ | 463,990 | $ | 376,103 | $ | 87,887 | 23 | % | ||||||||||||||||||
| Average GTP per Boe | $ | 0.08 | $ | 0.07 | $ | 0.01 | 14 | % | ||||||||||||||||||
| Ad valorem taxes | $ | 5,627,320 | $ | 5,647,469 | $ | (20,149) | - | % | ||||||||||||||||||
| Average Ad valorem taxes per Boe | $ | 1.02 | $ | 1.05 | $ | (0.03) | (3) | % | ||||||||||||||||||
| Oil and natural gas production taxes | $ | 11,088,049 | $ | 12,259,418 | $ | (1,171,369) | (10) | % | ||||||||||||||||||
| Average Production taxes per Boe | $ | 2.01 | $ | 2.28 | $ | (0.27) | (12) | % | ||||||||||||||||||
| Production taxes as a percentage of total sales | 4.61 | % | 4.33 | % | 0.28 | % | 6 | % | ||||||||||||||||||
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.
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.
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.
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.
Other Costs and Operating Expenses for the Three Months Ended September 30, 2025 and 2024
| For the Three Months Ended | ||||||||||||||||||||||||||
| September 30, 2025 | September 30, 2024 | Change | % Change | |||||||||||||||||||||||
| Depreciation, depletion and amortization (DD&A): | ||||||||||||||||||||||||||
| Depletion | $ | 24,902,199 | $ | 25,302,058 | $ | (399,859) | (2) | % | ||||||||||||||||||
| Depreciation | 105,933 | 102,043 | 3,890 | 4 | % | |||||||||||||||||||||
| Amortization of financing lease assets | 217,213 | 258,022 | (40,809) | (16) | % | |||||||||||||||||||||
| Total depreciation, depletion and amortization | $ | 25,225,345 | $ | 25,662,123 | $ | (436,778) | (2) | % | ||||||||||||||||||
| Depletion per Boe | $ | 13.02 | $ | 13.68 | $ | (0.66) | (5) | % | ||||||||||||||||||
| Depreciation, depletion and amortization per Boe | $ | 13.19 | $ | 13.87 | $ | (0.68) | (5) | % | ||||||||||||||||||
| Ceiling test impairment | 72,912,330 | - | 72,912,330 | 100 | % | |||||||||||||||||||||
| Asset retirement obligation ("ARO") accretion | $ | 390,563 | $ | 354,195 | $ | 36,368 | 10 | % | ||||||||||||||||||
| Operating lease expense | $ | 175,091 | $ | 175,091 | $ | - | - | % | ||||||||||||||||||
| General and administrative expense ("G&A"): | ||||||||||||||||||||||||||
| General and administrative expense (excluding Share-based compensation) | $ | 6,521,171 | $ | 6,389,480 | $ | 131,691 | 2 | % | ||||||||||||||||||
| Share-based compensation | 1,618,600 | 32,087 | 1,586,513 | 4944 | % | |||||||||||||||||||||
| Total general and administrative expense | $ | 8,139,771 | $ | 6,421,567 | $ | 1,718,204 | 27 | % | ||||||||||||||||||
| G&A per Boe | $ | 4.26 | $ | 3.47 | $ | 0.79 | 23 | % | ||||||||||||||||||
| G&A excluding Share-based compensation, per Boe | $ | 3.41 | $ | 3.45 | $ | (0.04) | (1) | % | ||||||||||||||||||
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.
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.
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.
Operating lease expense. Our operating lease expense costs were the same period over period.
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.
Other Costs and Operating Expenses for the Nine Months Ended September 30, 2025 and 2024
| For the Nine Months Ended | ||||||||||||||||||||||||||
| September 30, 2025 | September 30, 2024 | Change | % Change | |||||||||||||||||||||||
| Depreciation, depletion and amortization (DD&A): | ||||||||||||||||||||||||||
| Depletion | $ | 72,381,413 | $ | 73,056,856 | $ | (675,443) | (1) | % | ||||||||||||||||||
| Depreciation | 309,211 | 306,752 | 2,459 | 1 | % | |||||||||||||||||||||
| Amortization of financing lease assets | 720,618 | 790,386 | (69,768) | (9) | % | |||||||||||||||||||||
| Total depreciation, depletion and amortization | $ | 73,411,242 | $ | 74,153,994 | $ | (742,752) | (1) | % | ||||||||||||||||||
| Depletion per Boe | $ | 13.15 | $ | 13.57 | $ | (0.42) | (3) | % | ||||||||||||||||||
| Depreciation, depletion and amortization per Boe | $ | 13.33 | $ | 13.78 | $ | (0.45) | (3) | % | ||||||||||||||||||
| Ceiling test impairment | $ | 72,912,330 | $ | - | $ | 72,912,330 | 100 | % | ||||||||||||||||||
| Asset retirement obligation ("ARO") accretion | $ | 1,099,363 | $ | 1,057,213 | $ | 42,150 | 4 | % | ||||||||||||||||||
| Operating lease expense | $ | 525,272 | $ | 525,272 | $ | - | - | % | ||||||||||||||||||
| General and administrative expense ("G&A"): | ||||||||||||||||||||||||||
| General and administrative expense (excluding Share-based compensation) | $ | 19,236,869 | $ | 17,770,626 | $ | 1,466,243 | 8 | % | ||||||||||||||||||
| Share-based compensation | 4,661,397 | 3,833,697 | 827,700 | 22 | % | |||||||||||||||||||||
| Total general and administrative expense | $ | 23,898,266 | $ | 21,604,323 | $ | 2,293,943 | 11 | % | ||||||||||||||||||
| G&A per Boe | $ | 4.34 | $ | 4.01 | $ | 0.33 | 8 | % | ||||||||||||||||||
| G&A excluding Share-based compensation, per Boe | $ | 3.49 | $ | 3.30 | $ | 0.19 | 6 | % | ||||||||||||||||||
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.
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.
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.
Operating lease expense. Our operating lease expense costs were the same period over period.
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.
Other Income (Expense) for the Three Months Ended September 30, 2025 and 2024
| For the Three Months Ended | ||||||||||||||||||||||||||
| September 30, 2025 | September 30, 2024 | Change | % Change | |||||||||||||||||||||||
| Interest income | $ | 74,253 | $ | 143,704 | $ | (69,451) | (48) | % | ||||||||||||||||||
| Interest expense: | ||||||||||||||||||||||||||
| Interest on revolving line of credit | $ | 8,933,960 | $ | 9,209,180 | $ | (275,220) | (3) | % | ||||||||||||||||||
| Fees associated with revolving line of credit | 179,056 | 266,291 | (87,235) | (33) | % | |||||||||||||||||||||
| Amortization of deferred financing costs | 693,625 | 1,226,881 | (533,256) | (43) | % | |||||||||||||||||||||
| Interest on financing lease liabilities | 24,330 | 27,224 | (2,894) | (11) | % | |||||||||||||||||||||
| Interest paid for notes payable | 25,710 | 24,115 | 1,595 | 7 | % | |||||||||||||||||||||
| Deferred cash payment accretion | 195,639 | - | 195,639 | 100 | % | |||||||||||||||||||||
| Other interest | - | 552 | (552) | (100) | % | |||||||||||||||||||||
| Total interest expense | $ | 10,052,320 | $ | 10,754,243 | $ | (701,923) | (7) | % | ||||||||||||||||||
| Gain (loss) on derivative contracts: | ||||||||||||||||||||||||||
| Realized gain (loss): | ||||||||||||||||||||||||||
| Crude oil | $ | 2,065,490 | $ | (3,109,660) | $ | 5,175,150 | 166 | % | ||||||||||||||||||
| Natural gas | 520,740 | 1,226,895 | (706,155) | (58) | % | |||||||||||||||||||||
| Total realized gain (loss) | $ | 2,586,230 | $ | (1,882,765) | $ | 4,468,995 | 237 | % | ||||||||||||||||||
| Unrealized gain (loss): | ||||||||||||||||||||||||||
| Crude oil | $ | (3,526,149) | $ | 27,238,245 | $ | (30,764,394) | (113) | % | ||||||||||||||||||
| Natural gas | 1,384,224 | (623,855) | 2,008,079 | 322 | % | |||||||||||||||||||||
| Total unrealized gain (loss) | $ | (2,141,925) | $ | 26,614,390 | $ | (28,756,315) | (108) | % | ||||||||||||||||||
| Total gain (loss) on derivative contracts: | $ | 444,305 | $ | 24,731,625 | $ | (24,287,320) | (98) | % | ||||||||||||||||||
| Gain (loss) on disposal of assets | $ | 105,642 | $ | - | $ | 105,642 | 100 | % | ||||||||||||||||||
| Other income | $ | - | $ | - | $ | - | - | % | ||||||||||||||||||
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.
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.
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.
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.
Other Income (Expense) for the Nine Months Ended September 30, 2025 and 2024
| For the Nine Months Ended | ||||||||||||||||||||||||||
| September 30, 2025 | September 30, 2024 | Change | % Change | |||||||||||||||||||||||
| Interest income | $ | 233,969 | $ | 367,181 | $ | (133,212) | (36) | % | ||||||||||||||||||
| Interest expense: | ||||||||||||||||||||||||||
| Interest on revolving line of credit | $ | 26,364,419 | $ | 28,497,006 | $ | (2,132,587) | (7) | % | ||||||||||||||||||
| Fees associated with revolving line of credit | 666,904 | 751,216 | (84,312) | (11) | % | |||||||||||||||||||||
| Amortization of deferred financing costs | 3,768,292 | 3,670,096 | 98,196 | 3 | % | |||||||||||||||||||||
| Interest on financing lease liabilities | 80,709 | 89,963 | (9,254) | (10) | % | |||||||||||||||||||||
| Interest paid for notes payable | 42,876 | 40,481 | 2,395 | 6 | % | |||||||||||||||||||||
| Deferred cash payment accretion | 385,310 | - | 385,310 | 100 | % | |||||||||||||||||||||
| Other interest | - | 150,552 | (150,552) | (100) | % | |||||||||||||||||||||
| Total interest expense | $ | 31,308,510 | $ | 33,199,314 | $ | (1,890,804) | (6) | % | ||||||||||||||||||
| Gain (loss) on derivative contracts: | ||||||||||||||||||||||||||
| Realized gain (loss): | ||||||||||||||||||||||||||
| Crude oil | $ | 1,858,524 | $ | (9,921,757) | $ | 11,780,281 | 119 | % | ||||||||||||||||||
| Natural gas | 851,955 | 3,982,980 | (3,131,025) | (79) | % | |||||||||||||||||||||
| Total realized gain (loss) | $ | 2,710,479 | $ | (5,938,777) | $ | 8,649,256 | 146 | % | ||||||||||||||||||
| Unrealized gain (loss): | ||||||||||||||||||||||||||
| Crude oil | $ | 10,961,216 | $ | 12,552,517 | $ | (1,591,301) | (13) | % | ||||||||||||||||||
| Natural gas | 491,874 | (2,725,209) | 3,217,083 | 118 | % | |||||||||||||||||||||
| Total unrealized gain (loss) | $ | 11,453,090 | $ | 9,827,308 | $ | 1,625,782 | 17 | % | ||||||||||||||||||
| Total gain (loss) on derivative contracts: | $ | 14,163,569 | $ | 3,888,531 | $ | 10,275,038 | 264 | % | ||||||||||||||||||
| Gain (loss) on disposal of assets | $ | 385,545 | $ | 89,693 | $ | 295,852 | 330 | % | ||||||||||||||||||
| Other income | $ | 159,712 | $ | 25,686 | $ | 134,026 | 522 | % | ||||||||||||||||||
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.
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.
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.
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.
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.
Benefit from (Provision for) Income Taxes: for the Three Months Ended September 30, 2025 and 2024
| For the Three Months Ended | ||||||||||||||||||||||||||
| September 30, 2025 | September 30, 2024 | Change | % Change | |||||||||||||||||||||||
| Benefit from (Provision for) Income Taxes: | ||||||||||||||||||||||||||
| Deferred federal income tax benefit (provision) | $ | 12,558,220 | $ | (9,637,849) | $ | 22,196,069 | 230 | % | ||||||||||||||||||
| Current state income tax provision | (39,816) | (74,899) | 35,083 | 47 | % | |||||||||||||||||||||
| Deferred state income tax benefit (provision) | 282,543 | (375,206) | 657,749 | 175 | % | |||||||||||||||||||||
| Benefit from (Provision for) Income Taxes | $ | 12,800,947 | $ | (10,087,954) | $ | 22,888,901 | 227 | % | ||||||||||||||||||
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.
Benefit from (Provision for) Income Taxes: for the Nine Months Ended September 30, 2025 and 2024
| For the Nine Months Ended | ||||||||||||||||||||||||||
| September 30, 2025 | September 30, 2024 | Change | % Change | |||||||||||||||||||||||
| Benefit from (Provision for) Income Taxes: | ||||||||||||||||||||||||||
| Deferred federal income tax benefit (provision) | $ | 3,965,817 | $ | (17,617,436) | $ | 21,583,253 | 123 | % | ||||||||||||||||||
| Current state income tax provision | (323,670) | (329,917) | 6,247 | 2 | % | |||||||||||||||||||||
| Deferred state income tax benefit (provision) | 10,198 | (689,972) | 700,170 | 101 | % | |||||||||||||||||||||
| Benefit from (Provision for) Income Taxes | $ | 3,652,345 | $ | (18,637,325) | $ | 22,289,670 | 120 | % | ||||||||||||||||||
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.
Liquidity and Capital Resources
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.
We will continue to focus on maximizing cash flow in 2025 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, 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.
Derivative Financial Instruments
The following table reflects the contracts outstanding as of September 30, 2025 (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 2025 | Q1 2026 | Q2 2026 | Q3 2026 | Q4 2026 | Q1 2027 | Q2 2027 | Q3 2027 | ||||||||||||||||||||||||||||||||||||||||
| Swaps: | |||||||||||||||||||||||||||||||||||||||||||||||
| Hedged volume (Bbl) | 241,755 | 608,350 | 577,101 | 171,400 | 529,000 | 509,500 | 492,000 | 432,000 | |||||||||||||||||||||||||||||||||||||||
| Weighted average swap price | $ | 65.56 | $ | 67.95 | $ | 66.50 | $ | 62.26 | $ | 65.34 | $ | 62.82 | $ | 60.45 | $ | 61.80 | |||||||||||||||||||||||||||||||
| Two-way collars: | |||||||||||||||||||||||||||||||||||||||||||||||
| Hedged volume (Bbl) | 404,800 | - | - | 379,685 | - | - | - | - | |||||||||||||||||||||||||||||||||||||||
| Weighted average put price | $ | 60.00 | $ | - | $ | - | $ | 60.00 | $ | - | $ | - | $ | - | $ | - | |||||||||||||||||||||||||||||||
| Weighted average call price | $ | 75.68 | $ | - | $ | - | $ | 72.50 | $ | - | $ | - | $ | - | $ | - | |||||||||||||||||||||||||||||||
| Gas Hedges (Henry Hub) | |||||||||||||||||||||||||||||||||||||||||||||||
| Q4 2025 | Q1 2026 | Q2 2026 | Q3 2026 | Q4 2026 | Q1 2027 | Q2 2027 | Q3 2027 | ||||||||||||||||||||||||||||||||||||||||
| NYMEX Swaps: | |||||||||||||||||||||||||||||||||||||||||||||||
| Hedged volume (MMBtu) | 84,300 | 140,600 | 662,300 | 121,400 | 613,300 | - | - | 612,000 | |||||||||||||||||||||||||||||||||||||||
| Weighted average swap price | $ | 4.25 | $ | 4.20 | $ | 3.54 | $ | 4.22 | $ | 3.83 | $ | - | $ | - | $ | 3.74 | |||||||||||||||||||||||||||||||
| Two-way collars: | |||||||||||||||||||||||||||||||||||||||||||||||
| Hedged volume (MMBtu) | 495,500 | 694,500 | 139,000 | 648,728 | 128,000 | 717,000 | 694,000 | - | |||||||||||||||||||||||||||||||||||||||
| Weighted average put price | $ | 3.10 | $ | 3.50 | $ | 3.50 | $ | 3.10 | $ | 3.50 | $ | 3.99 | $ | 3.00 | $ | - | |||||||||||||||||||||||||||||||
| Weighted average call price | $ | 4.40 | $ | 5.11 | $ | 5.42 | $ | 4.24 | $ | 5.42 | $ | 5.21 | $ | 4.32 | $ | - | |||||||||||||||||||||||||||||||
| Oil Hedges (basis differential) | |||||||||||||||||||||||||||||||||||||||||||||||
| Q4 2025 | Q1 2026 | Q2 2026 | Q3 2026 | Q4 2026 | Q1 2027 | Q2 2027 | Q3 2027 | ||||||||||||||||||||||||||||||||||||||||
| Argus basis swaps: | |||||||||||||||||||||||||||||||||||||||||||||||
|
Hedged volume (Bbl)
|
183,000 | - | - | - | - | - | - | - | |||||||||||||||||||||||||||||||||||||||
|
Weighted average spread price (1)
|
$ | 1.00 | $ | - | $ | - | $ | - | $ | - | $ | - | $ | - | $ | - | |||||||||||||||||||||||||||||||
| Gas Hedges (basis differential) | |||||||||||||||||||||||||||||||||||||||||||||||
| Q4 2025 | Q1 2026 | Q2 2026 | Q3 2026 | Q4 2026 | Q1 2027 | Q2 2027 | Q3 2027 | ||||||||||||||||||||||||||||||||||||||||
| El Paso Permian Basin basis swaps: | |||||||||||||||||||||||||||||||||||||||||||||||
| Hedged volume (MMBtu) | 363,200 | - | - | - | - | 700,000 | - | - | |||||||||||||||||||||||||||||||||||||||
|
Weighted average spread price (2)
|
$ | 1.69 | $ | - | $ | - | $ | - | $ | - | $ | 0.74 | $ | - | $ | - | |||||||||||||||||||||||||||||||
(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.
(2) 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, 2025, 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, 2025, 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.
Ring Energy Inc. published this content on November 06, 2025, and is solely responsible for the information contained herein. Distributed via Edgar on November 06, 2025 at 22:02 UTC. If you believe the information included in the content is inaccurate or outdated and requires editing or removal, please contact us at [email protected]