Item 7. Management’s Discussion and Analysis
Item 7: 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 financial statements and the notes to those financial statements included elsewhere in this Annual 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 Annual 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 of Texas. Our drilling operations target the oil and liquids rich producing formations in the Northwest Shelf and the Central Basin Platform, in the Permian Basin in Texas.
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 shareholders.
• 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 assets, 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. During the three months ended December 31, 2025, the Company made net paydowns of $8 million on its revolving line of credit, resulting in the outstanding long-term debt balance of $420 million.
• Employ industry leading drilling and completion techniques . Ring’s executive team intends to continue 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 shareholders. Our executive team, with its extensive experience in the Permian Basin, has many relationships with operators and service providers in the region.
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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 paid on December 31, 2025, and (iii) 6,452,879 shares of common stock (the "LRR Shares"). On March 31, 2025, in connection with the closing of the Lime Rock Acquisition, the Company and Lime Rock entered into a customary registration rights agreement relating to the LRR Shares. On May 2, 2025, a registration statement on Form S-3 with respect to the resale of the LRR Shares was declared effective by the SEC.
Credit Agreement
On June 18, 2025, the Company as borrower, Bank of America, N. A. as the Administrative Agent and Issuing Bank (“Bank of America”), and the lenders party thereto (the “Lenders”) entered into the Third Amended and Restated Credit Agreement (the “Credit Agreement”) which amended and restated that certain Second Amended and Restated Credit Agreement dated as of August 31, 2022, by and among the Company, Truist Bank, as administrative agent, and the lenders party thereto, as amended by that certain First Amendment to Second Amended and Restated Credit Agreement, dated as of February 12, 2024 (the “Existing Credit Agreement”). All of the obligations under the Credit Agreement, and the guarantees of those obligations, are secured by substantially all of the Company’s assets. Among other things, the Credit Agreement changed the administrative agent from Truist Bank to Bank of America; reduced the borrowing base and aggregate elected commitment from $600 million to $585 million; extended the maturity date of the Credit Agreement from August 31, 2026 to June 18, 2029; reduced the applicable margin pricing grid by 25 basis points; and made certain administrative changes to the Existing Credit Agreement.
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%. Finally, the Company began drilling one 1.5-mile horizontal well (with a working interest of 100%) in the Northwest Shelf in Yoakum County.
In the fourth quarter of 2025, the Company finished drilling and completed the aforementioned 1.5-mile horizontal well in the Northwest Shelf. The Company drilled and completed two additional 1-mile horizontal wells in the Central Basin Platform, one in Andrews County and one in Crane County (both with a working interest of 100%). Also in Crane County the Company drilled and completed one vertical well (with a working interest of 100%).
In summary, for 2025, the Company drilled and completed 12 horizontal wells and 6 vertical wells. The table below sets forth our drilling and completion activities for 2025 by quarter, and full year total through December 31, 2025.
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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
4Q 2025 Northwest Shelf (Horizontal) 1 1
Central Basin Platform (Horizontal) 2 2
Central Basin Platform (Vertical) 1 1
Total 4 4
FY 2025
Northwest Shelf (Horizontal) 5 5
Central Basin Platform (Horizontal) 7 7
Central Basin Platform (Vertical) 6 6
Total 18 18
(1) First quarter total and full year total do not include one SWD well completed in the Central Basin Platform
(2) Note that the DUC wells represent period-end counts rather than period-to-date totals.
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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 continued 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 prices, the Company recognized a non-cash impairment charge of $108.8 million during the year ended December 31, 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 for its natural gas production. This has resulted in negative natural gas prices at times, whereby the seller is actually paying the purchaser to take the gas. We experienced negative realized gas prices for all of 2024 and 2025 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.
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Results of Operations
For the years ended December 31, 2025 2024 2023
Net production:
Oil (Bbls) 4,841,164 4,861,628 4,579,942
Natural gas (Mcf) 6,980,958 6,423,674 6,339,158
Natural gas liquids (Bbls) 1,387,818 1,258,814 976,852
Net sales:
Oil $ 307,553,614 $ 363,971,394 $ 349,044,863
Natural gas (9,297,614) (9,265,335) 334,175
Natural gas liquids 8,922,072 11,621,355 11,676,963
Average sales price:
Oil (per Bbl) $ 63.53 $ 74.87 $ 76.21
Natural gas (per Mcf) (1.33) (1.44) 0.05
Natural gas liquids (Bbl) 6.43 9.23 11.95
Production costs and expenses:
Lease operating expenses $ 79,353,806 $ 78,310,949 $ 70,158,227
Gathering, transportation and processing costs 585,087 506,333 457,573
Ad valorem taxes 7,906,586 8,069,064 6,757,841
Oil and natural gas production taxes 14,312,232 16,116,565 18,135,336
Other costs and operating expenses:
Depreciation, depletion and amortization $ 96,414,150 $ 98,702,843 $ 88,610,291
Ceiling test impairment 108,825,446 — —
Asset retirement obligation accretion 1,490,255 1,380,298 1,425,686
Operating lease expense 700,362 700,362 541,801
General and administrative expense ("G&A")
31,928,576 29,640,300 29,188,755
Share-based compensation 6,135,957 5,506,017 8,833,425
G&A excluding share-based compensation
25,792,619 24,134,283 20,355,330
Other income (expense):
Interest income $ 290,879 $ 491,946 $ 257,155
Interest (expense) (40,430,929) (43,311,810) (43,926,732)
Gain (loss) on derivative contracts 31,658,839 (2,365,917) 2,767,162
Gain (loss) on disposal of assets 446,400 89,693 (87,128)
Other income 189,294 106,656 198,935
Benefit from (Provision for) Income Taxes $ 7,452,746 $ (20,440,954) $ (125,242)
Year Ended December 31, 2025 Compared to Year Ended December 31, 2024
Oil sales . Oil sales decreased approximately $56.4 million to $307.6 million in 2025 from $364.0 million in 2024. This was due to a price variance of approximately $(54.9) million from a decrease in the average realized per barrel oil price to $63.53 in 2025 from $74.87 in 2024. Also impacting the oil sales was a volume variance of approximately $(1.5) million from a decrease in sales volumes to 4,841,164 barrels of oil in 2025 from 4,861,628 barrels of oil in 2024,
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primarily driven by natural asset decline, offset by production from wells within the assets acquired with the Lime Rock Acquisition (closed in March 2025) and organic growth from workovers, new drills, and other capital expenditures.
Natural gas sales. Natural gas sales remained essentially constant, with approximately $(9.3) million in 2025 and $(9.3) million in 2024. The average realized per Mcf gas price increased to $(1.33) in 2025 from $(1.44) in 2024. The positive change in price was due to an increase in the average gross realized price that was higher than the increase in the average fees. In 2025, the average gross realized price for natural gas was $0.75 per Mcf, and the average fees per Mcf were $(2.08), bringing the net average price to $(1.33) per Mcf. In 2024, the average gross realized price for natural gas was $0.29 per Mcf, and the average fees per Mcf were $(1.73), bringing the net average price to (1.44) per Mcf. The natural gas sales volume increased to 6,980,958 Mcf in 2025 from 6,423,674 Mcf in 2024.
NGL sales. NGL sales decreased approximately $2.7 million to $8.9 million in 2025 from $11.6 million in 2024, due to a price variance of approximately $(3.9) million, as the average realized price per barrel of NGLs was $6.43 in 2025 compared to $9.23 in 2024. This was due to a reduction in the gross realized price per NGL barrel to $18.84 in 2025 compared to $20.00 in 2024 coupled with a growth in the average fees per barrel to $(12.41) in 2025 compared to $(10.77) in 2024. Offsetting this decrease to sales was a volume variance of approximately $1.2 million, as volumes were 1,387,818 barrels of NGLs in 2025 compared to 1,258,814 barrels in 2024, with 82% of the increase in barrels due to the assets acquired in the Lime Rock Acquisition in March 2025.
Lease operating expenses. Our total lease operating expenses (“LOE”) increased approximately $1.0 million to $79.4 million in 2025 from $78.3 million in 2024 and decreased on a Boe basis to $10.73 in 2025 from $10.89 in 2024. These per Boe amounts are calculated by dividing our total LOE by our total volume sold, in Boe. LOE increased due to additional expenses from the assets acquired with the Lime Rock Acquisition (closed in March 2025) which contributed to a 3% increase in production of 201,422 Boe. Specifically, the Company experienced increases of $4.7 million for electrical/utilities costs, $0.7 million for environmental sustainability and cleanup, $0.7 million for communications, and $0.5 million for compressor rentals. This was offset by reductions in costs including $3.1 million for workover expense, $1.0 million for chemicals and treating, $0.6 million for pumping unit repairs, $0.5 million for hot oil paraffin control, $0.2 million for supplies, and $0.2 million for insurance costs.
Gathering, transportation and processing costs. Our total GTP costs increased by $78,754 to $585,087 in 2025 from $506,333 in 2024 and slightly increased on a Boe basis to $0.08 in 2025 from $0.07 in 2024. The increase in costs was $107,637 in gas processing costs, offset by a reduction of $28,883 from NGL processing costs.
Ad valorem taxes. Our total ad valorem taxes decreased approximately $0.2 million to $7.9 million in 2025 from $8.1 million in 2024 and decreased on a Boe basis to $1.07 in 2025 from $1.12 in 2024. Ad valorem taxes decreased due to $1.2 million lower taxes in Yoakum County and $1.1 million for the reversal of the waste emissions charge ("WEC") that was recognized in 2024. This was offset by tax increases of $2.0 million in Andrews County, primarily from properties acquired in the Lime Rock Acquisition, and $0.1 million in Ector County.
Oil and natural gas production taxes . Oil and natural gas production taxes as a percentage of oil and natural gas sales increased to 4.66% in 2025 from 4.40% during 2024. In 2024, an accrual of $1.2 million was made for estimated severance tax refunds expected, which lowered the average rate for 2024. As of December 31, 2024, $0.9 million of the estimated refund was received. Excluding this refund, the overall average percentage of production taxes to oil and gas sales in 2024 was 4.7%, which is in line with the historical rates.
Depreciation, depletion and amortization . Our depreciation, depletion and amortization expense decreased approximately $2.3 million to $96.4 million in 2025 from $98.7 million in 2024, with $2.2 million of the decrease from reduced depletion on our oil and natural gas properties and $0.1 million from a reduction in amortization of financing lease assets. The $2.2 million decrease in depletion on oil and gas properties is due to a decreased average expense per unit of $12.86 in 2025 from $13.52 in 2024. Produced Boe increased by 201,422 in 2025; however, the reduced expense per unit resulted in lower depletion costs year over year. While average costs of property increased from the Lime Rock Acquisition and other capital well work, the asset impairment in 2025 resulted in a 5% increase in average estimated costs of property change year over year compared to an 11% increase in the amortization base (Boe).
Ceiling test impairment. During 2025, 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 $108.8 million.
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Asset retirement obligation accretion. Our asset retirement obligation (“ARO”) accretion increased by $109,957 to $1,490,255 in 2025 from $1,380,298 in 2024. The primary drivers in this increase of ARO accretion were the wells acquired in the Lime Rock Acquisition, which closed in March 2025, as well as new wells drilled in 2025. This was offset by wells plugged and abandoned and sold in 2025.
Operating lease expense. Our operating lease expense was consistent year over year, as the Company experienced no changes in its office leases.
General and administrative expenses (including share-based compensation) . General and administrative expenses increased approximately $2.3 million to $31.9 million in 2025 from $29.6 million in 2024. The increase was primarily related to an increase of $2.5 million in salaries, wages, and bonuses, $0.6 million in share-based compensation, and $0.6 million in other professional fees. This was offset by reductions of $0.5 million in environmental sustainability costs, $0.5 million in legal fees, $0.4 million in additional costs capitalized, and $0.1 million in credit loss expense.
Interest income. Interest income decreased by $201,067 to $290,879 in 2025 from $491,946 in 2024. This was driven by a reduction of $184,997 in sweep accounts interest income and $16,070 for severance tax refund interest income.
Interest expense . Interest expense decreased approximately $2.9 million to $40.4 million in 2025 from $43.3 million in 2024. The decrease was primarily due to a 1% decrease in the average interest rate on the Company's long-term credit facility, which was 8.2% in 2025 and 9.2% in 2024, notwithstanding the increase in the Company's average amounts drawn on the same. Other reductions included lower deferred financing costs and interest on royalty suspense. This was offset by an increase in deferred cash payment accretion related to the Lime Rock Acquisition.
Gain (loss) on derivative contracts. During 2025, the Company recognized a gain on derivative contracts of approximately $31.7 million. During 2024, the Company incurred a loss on derivative contracts of approximately $2.4 million. For the derivative contract settlements, the Company recorded a realized gain of $5.5 million during 2025 and a realized loss of $5.2 million during 2024. The change of approximately $10.6 million in the realized derivative settlements was $14.1 million from realized oil derivative settlements and $(3.5) million from realized natural gas derivative settlements. For the marked-to-market contracts, the Company recorded an unrealized gain of $26.2 million during 2025 and an unrealized gain of $2.8 million during 2024. This change of approximately $23.4 million in unrealized derivatives was from $16.5 million in favorable derivative portfolio changes and futures pricing for marked-to-market oil derivative contracts, as well as $6.9 million favorable changes to the marked-to-market natural gas derivative contract balance.
Gain (loss) on disposal of assets. Gain (loss) on disposal of assets increased $356,707 to a gain of $446,400 in 2025 from a gain of $89,693 in 2024. The increase was primarily the result of an increase of $349,442 from the sale of leased vehicles and an increase of $7,265 from the sale of owned vehicles.
Other income. Other income increased $82,638 to $189,294 in 2025 from $106,656 in 2024. The increase was primarily due to income of $150,770 from a pipeline easement lease, offset by a reduction of $68,132 in income from the Company's charge card rebate program.
Benefit from (provision for) income taxes . The provision for income taxes changed to a benefit of $7,452,746 for 2025 from a provision of $20,440,954 for 2024, primarily driven by the change from pre-tax book income in 2024 to a pre-tax book loss in 2025, impacted by the ceiling test impairment recognized in 2025.
Net income (loss) . The Company recognized a net loss of $34,731,199 in 2025 compared to net income of $67,470,314 in 2024. The decrease in income associated with operations was due to the reduction in commodity pricing, which reduced revenues as well as led to the ceiling test impairment recognized. Lessening this impact was the gain on derivative contracts, which was positive in terms of both unrealized and realized gains.
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Year Ended December 31, 2024 Compared to Year Ended December 31, 2023
Oil sales . Oil sales increased approximately $14.9 million to $364.0 million in 2024 from $349.0 million in 2023. The oil sales increased by a volume variance of approximately $21.5 million from an increase in sales volumes to 4,861,628 barrels of oil in 2024 from 4,579,942 barrels of oil in 2023, primarily driven by production from wells within the assets acquired with the Founders Acquisition (closed in August 2023). Other impacts to revenue volumes include organic growth from workovers, new drills, and other capital expenditures, offset by divestitures completed and natural asset decline. The volume variance was offset by a negative price variance of approximately $(6.5) million from a decrease in the average realized per barrel oil price to $74.87 in 2024 from $76.21 in 2023.
Natural gas sales. Natural gas sales decreased approximately $9.6 million to $(9.3) million in 2024 from $0.3 million in 2023. The natural gas sales decreased by a negative price variance of approximately $(9.6) million, as the average realized per Mcf gas price decreased to $(1.44) in 2024 from $0.05 in 2023. The significant reduction in realized natural gas prices was driven by a lower market index price. In 2024, the average gross realized price for natural gas was $0.29 per Mcf, and the average fees per Mcf were $(1.73), bringing the net average price to $(1.44) per Mcf. In 2023, the average gross realized price for natural gas was $1.67 per Mcf, and the average fees per Mcf were $(1.62), bringing the net average price to 0.05 per Mcf. This was only slightly offset by the volume variance as the volume increased to 6,423,674 Mcf in 2024 from 6,339,158 Mcf in 2023.
NGL sales. NGL sales decreased approximately $0.1 million to $11.6 million in 2024 from $11.7 million in 2023. NGL sales had a volume variance of approximately $3.4 million, as volumes were 1,258,814 barrels of NGLs in 2024 compared to 976,852 barrels in 2023, with 36% of the increase in barrels due to the assets acquired in the Founders Acquisition in 2023. Offsetting this increase to sales was a negative price variance of approximately $(3.4) million, as the average realized price per barrel of NGLs was $9.23 in 2024 compared to $11.95 in 2023. This was due to a reduction in the gross realized price per NGL barrel to $20.00 in 2024 compared to $21.16 in 2023 coupled with a growth in the average fees per barrel to $(10.77) in 2024 compared to $(9.20) in 2023.
Lease operating expenses. Our total lease operating expenses (“LOE”) increased approximately $8.1 million to $78.3 million in 2024 from $70.2 million in 2023 and increased slightly on a Boe basis to $10.89 in 2024 from $10.61 in 2023. These per Boe amounts are calculated by dividing our total LOE by our total volume sold, in Boe. LOE increased due to the full year of expenses from the assets acquired with the Founders Acquisition (closed in August 2023) which contributed to a 9% increase in production of 577,733 Boe. Specifically, the Company experienced increases of $4.1 million for chemicals and treating, $1.8 million for electrical/utilities costs, $0.6 million for pumping unit repairs, $0.6 million for other employee costs, $0.4 million for environmental sustainability, and $0.4 million for insurance costs.
Gathering, transportation and processing costs. Our total GTP costs increased by $48,760 to $506,333 in 2024 from $457,573 in 2023 and remained unchanged on a Boe basis with $0.07 in 2024 and $0.07 in 2023. The increase in costs was $30,298 from NGL processing costs and $18,462 from gas processing costs.
Ad valorem taxes. Our total ad valorem taxes increased approximately $1.3 million to $8.1 million in 2024 from $6.8 million in 2023 and increased on a Boe basis to $1.12 in 2024 from $1.02 in 2023. Ad valorem taxes increased $1.1 million due to a full year of taxes for the properties acquired in the Founders Acquisition (i.e. Ector County), $0.1 million in Yoakum County, and $0.1 million in Andrews County, offset by a reduction of $0.5 million in Crane County. Additionally, we have accrued approximately $0.5 million for the waste emissions charge ("WEC") in place for the calendar year 2024.
Oil and natural gas production taxes . Oil and natural gas production taxes as a percentage of oil and natural gas sales decreased to 4.40% in 2024 from 5.02% during 2023. In 2024, an accrual of $1.2 million was made for estimated severance tax refunds expected, which lowered the average rate for 2024. As of December 31, 2024, $0.9 million of the estimated refund was received. Excluding this refund, the overall average percentage of production taxes to oil and gas sales in 2024 is 4.7%, which is in line with the historical rates.
Depreciation, depletion and amortization . Our depreciation, depletion and amortization expense increased approximately $10.1 million to $98.7 million in 2024 from $88.6 million in 2023, with $9.8 million of the increase from depletion on our oil and natural gas properties, $0.3 million from amortization of financing lease assets, and $0.04 million from depreciation of fixed assets. The increase in depletion was primarily due to a volume variance of $7.6 million was from an increase of 577,733 in Boe produced. Additionally, depletion experienced a price variance of $2.2 million, from a higher depletion expense per unit overall year over year, due to an $18.9 million increase in average estimated costs of
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property coupled with a 1.6 million reduction in the amortization base (Boe). Our average depreciation, depletion and amortization per Boe increased to $13.73 per Boe during 2024 from $13.40 per Boe during 2023.
Asset retirement obligation accretion. Our asset retirement obligation (“ARO”) accretion decreased by $45,388 to $1,380,298 in 2024 from $1,425,686 in 2023. The primary drivers in this reduction of ARO accretion were the sale of our operated New Mexico assets, which closed in September of 2023 and the divestiture of our Delaware Basin assets, which closed in May 2023, along with other wells sold. This was offset by additional ARO accretion from wells acquired in the Founders Acquisition, which closed in August 2023, as well as new wells drilled in 2024.
Operating lease expense. Our operating lease expense increased by $158,561 to $700,362 in 2024 from $541,801 in 2023 due to additional office space leased in The Woodlands office, substantially completed in September 2023.
General and administrative expenses (including share-based compensation) . General and administrative expenses increased approximately $0.5 million to $29.6 million in 2024 from $29.2 million in 2023. The increase was primarily related to an increase of $3.1 million increase in salaries, wages, and bonuses in 2024 coupled with the $0.6 million G&A costs reduction in 2023 related to the employee retention tax credit. This was offset by a $3.3 million reduction in share-based compensation.
Interest income. Interest income increased by $234,791 to $491,946 in 2024 from $257,155 in 2023. This was driven by the increase of $239,797 in sweep accounts interest income and $25,834 for severance tax refund interest income, offset by a decrease of $29,042 from the employee retention tax credit interest income of 2023, as well as $1,798 from the interest earned on the escrow deposit made for the Founders Acquisition in 2023.
Interest expense . Interest expense decreased approximately $0.6 million to $43.3 million in 2024 from $43.9 million in 2023. The decrease was primarily the result of the deferred cash payment accretion of $0.6 million which was incurred in 2023, which was not required in 2024. Other changes include reductions in interest from our long-term credit facility, offset by an increase of interest on royalty suspense and deferred financing costs.
Gain (loss) on derivative contracts. During 2024, the Company incurred a loss on derivative contracts of approximately $2.4 million. During 2023, the Company recorded a gain on derivative contracts of approximately $2.8 million. For the derivative contract settlements, the Company recorded a realized loss of $5.2 million during 2024 and a realized loss of $9.1 million during 2023. The decrease of $3.9 million in the realized loss was $1.1 million from realized oil derivative settlements and $2.8 million from realized natural gas derivative settlements. For the marked-to-market contracts, the Company recorded an unrealized gain of $2.8 million during 2024 and an unrealized gain of $11.9 million during 2023. This change of approximately $9.0 million in unrealized derivatives was from $2.6 million in unfavorable derivative portfolio changes and futures pricing for marked-to-market oil derivative contracts, as well as $6.4 million unfavorable changes to the marked-to-market natural gas derivative contract balance.
Gain (loss) on disposal of assets. Gain (loss) on disposal of assets increased $176,821 to a gain of $89,693 in 2024 from a loss of $87,128 in 2023. The increase was primarily the result of the Company recognizing a gain on disposal of assets from selling multiple leased vehicles during 2024, compared with a loss on disposal of assets primarily from selling multiple company owned vehicles during 2023.
Other income. Other income decreased $92,279 to $106,656 in 2024 from $198,935 in 2023. The decrease primarily resulted from the termination of The Woodlands office operating lease in 2023. Offsetting this reduction was a higher bank rebate related to the use of a vendor payment program earned in 2024 compared to 2023.
Provision for income taxes . The provision for income taxes changed to a provision of $20,440,954 for 2024 from a provision of $125,242 for 2023. 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 2024, taking into account all applicable tax rates and laws.
Net income . The Company achieved net income of $67,470,314 in 2024 compared to net income of $104,864,641 in 2023. The decrease in income associated with operations was due to increased LOE costs, ad valorem taxes, and depletion, depreciation, and amortization costs. This was offset by increased oil sales and also lower production taxes as a result of prior period refunds. A change in derivatives position from gain to loss further caused the reduction of net income. The 2024 income tax provision was a significant change from year to year impacting the overall decrease in net income realized by the Company.
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Liquidity and Capital Resources
Financing of Operations. We have historically funded our operations through cash available from operations and from equity offerings of our stock. Our primary source of cash in 2025 was from funds generated from the sale of oil and natural gas production. These cash flows were primarily used to fund our capital expenditures and pay down our debt balance. We believe the combination of the sources of capital discussed will continue to be adequate to meet our short and long-term liquidity needs.
Credit Facility. On June 18, 2025, the Company, as borrower, Bank of America, N.A. as the Administrative Agent and Issuing Bank, and the lenders party thereto (the "Lenders") entered into that certain Third Amended and Restated Credit Agreement (the "Credit Agreement"), with a maximum borrowing base of $1 billion secured by substantially all of the assets of the Company and a maturity date of June 2029.
The Credit Agreement has a borrowing base of $585 million, which is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time. The borrowing base is redetermined semi-annually each May and November. The borrowing base is subject to reduction in certain circumstances such as the sale or disposition of certain oil and gas properties of the Company and cancellation of certain hedging positions.
The Credit Agreement permits the Company to declare restricted payments (including dividends) for its equity owners, subject to certain limitations, including (a) (i) no default or event of default has occurred or will occur upon such payments, (ii) the pro forma Leverage Ratio (outstanding debt to adjusted earnings before interest, income tax expense, depreciation, depletion and amortization, exploration expenses, and all other non-cash charges acceptable to the Administrative Agent) does not exceed 2.00 to 1.00, (iii) the amount of such payments does not exceed Available Free Cash Flow (as defined in the Credit Agreement), and (iv) the Borrowing Base Utilization Percentage (as defined in the Credit Agreement) is not greater than 80%; or (b) (i) no default or event of default has occurred or will occur upon such payments, (ii) the pro forma Leverage Ratio does not exceed 1.50 to 1.00, and (iii) the Borrowing Base Utilization Percentage is not greater than 75%.
The reference rate in the Credit Agreement is the Secured Overnight Financing Rate ("SOFR"). The interest rate on each SOFR Loan will (i) be the adjusted term SOFR for the applicable interest period plus (ii) a margin between 2.75% and 3.75% (depending on the then-current level of borrowing base usage) plus (iii) a 0.10% SOFR adjustment. The annual interest rate on each base rate loan is (a) the greatest of (i) the Administrative Agent’s prime lending rate, (ii) the Federal Funds Rate (as defined in the Credit Agreement) plus 0.5% per annum, (iii) the adjusted term SOFR determined on a daily basis for an interest period of one month, plus 1.00% per annum and (iv) 1.00% per annum, plus (b) a margin between 1.75% and 2.75% per annum (depending on the then-current level of borrowing base usage).
The Credit Agreement contains certain covenants, which, among other things, require the maintenance of (i) a total Leverage Ratio of not more than 3.0 to 1.0 and (ii) a minimum ratio of Current Assets to Current Liabilities (as such terms are defined in the Credit Agreement) of 1.0 to 1.0. The Credit Agreement also contains other customary affirmative and negative covenants and events of default. The Company is required to maintain on a rolling 24 months basis, hedging transactions in respect of crude oil and natural gas, on not less than 50% of the projected production from its proved, developed, and producing oil and gas. However, on any hedge testing date, (a) if the borrowing base utilization is less than 25% and the Leverage Ratio is not greater than 1.25 to 1.00, the required hedging percentage for months 13 through 24 of the rolling 24 month period provided for will be 0% from such hedge testing date to the next succeeding hedge testing date and (b) if the borrowing base utilization percentage is equal to or greater than 25%, but less than 50% and the Leverage Ratio is not greater than 1.25 to 1.00, the required hedging percentage for months 13 through 24 of the rolling 24 month period provided for will be 25% from such hedge testing date to the next succeeding hedge testing date.
As of December 31, 2025, $420 million was outstanding on the Credit Facility and the Company was in compliance with all covenants in the Credit Agreement.
Cash Flows. Historically, primary sources of cash have been from operations, equity offerings and borrowings on the Credit Facility. During 2025, 2024, and 2023 we had net cash provided by operating activities of $150.8 million, $194.4 million, and $198.2 million, respectively. These amounts differed from the Company's income (loss) from operations of $(34.3) million, $132.9 million, and $145.8 million, respectively, for the years ended December 31, 2025, 2024, and 2023, with the difference primarily resulting from the non-cash depletion, depreciation and amortization booked as well as the non-cash ceiling test impairment booked in 2025. During the three years ended December 31, 2025, we financed $12.3 million through proceeds from the sale of common stock. During 2025, 2024, and 2023, the Company had a
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net draw of $35.0 million, a net repayment of $40.0 million, and a net draw of $10.0 million on the Credit Facility, respectively. We used cash to fund our capital expenditures and development aggregating $571.2 million over the three years ended December 31, 2025. Additionally, during 2025, 2024 and 2023, we used cash of $196.8 million, $170.0 million and $215.0 million, respectively, to reduce the outstanding balance on our Credit Facility. As of December 31, 2025, we had cash on hand of $0.9 million and negative working capital of $38.9 million, compared to cash on hand of $1.9 million and negative working capital of $54.6 million as of December 31, 2024 and cash on hand of $0.3 million and negative working capital of $57.9 million as of December 31, 2023.
Contractual Obligations. Our material cash commitments from known contractual and other obligations consist primarily of obligations for debt and related interest, operating and finance leases, ARO and other obligations as part of normal operations. Certain amounts included in our contractual obligations as of December 31, 2025 are based on our estimates and assumptions about these obligations, including their duration, anticipated actions by third parties and other factors.
The Company maintains a Credit Facility which currently has a $585 million borrowing base. The outstanding balance on that Credit Facility as of December 31, 2025 was $420 million, which will require repayment or refinancing at or prior to maturity in June 2029. Refer to "NOTE 9 — REVOLVING LINE OF CREDIT" in the notes to the financial statements for more information on the Credit Facility.
The Company leases office spaces in The Woodlands, Texas and Midland, Texas. The Woodlands office is currently under a 71-month (five years and 11-month) lease for its office space, effective May 9, 2023. The Midland office is currently under a five-year lease for its office space, effective October 1, 2022 and ending September 30, 2027. Future lease payments for operating leases aggregate $1,497,380.
The Company has financing leases for vehicles with varying maturity dates through 2028. Future lease payments for financing leases aggregate $1,428,999.
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 December 31, 2025, the Company had no off-balance sheet financing arrangements.
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Critical Accounting Policies and Estimates
Our discussion of financial condition and results of operations is based upon the information reported in our financial statements. The preparation of these statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, weather, politics, global economics, mechanical problems, general business conditions, and other factors. Our significant accounting policies, as well as considerations of recent accounting pronouncements, are detailed in "NOTE 1 — ORGANIZATION, BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES" to our financial statements included in this Annual Report. We have outlined below certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management.
Oil and Natural Gas Reserve Quantities. Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. Reserve quantities and future cash flows included in this Annual Report are prepared in accordance with guidelines established by the SEC and FASB. The accuracy of our reserve estimates is a function of: the quality and quantity of available data; the interpretation of that data; the accuracy of various mandated economic assumptions; and the judgments of the persons preparing the estimates.
Our proved reserve information included in this Annual Report was prepared and determined by Cawley, Gillespie & Associates, Inc., independent petroleum engineers. Because these estimates depend on many assumptions, all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered. We continually make revisions to reserve estimates throughout the year as additional properties are acquired. We make changes to depletion rates and impairment calculations in the same period that changes to the reserve estimates are made.
All capitalized costs of oil and natural gas properties, including the estimated future costs to develop proved reserves and estimated future costs to plug and abandon wells and costs of site restoration, less the estimated salvage value of equipment associated with the oil and natural gas properties, are amortized on the unit-of-production method using estimates of proved reserves as determined by independent petroleum engineers. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined.
Ceiling Test of Oil and Natural Gas Properties . Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly utilizing the average of prices in effect on the first day of the month for the preceding twelve-month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10%, plus the lower of cost or market value of unproved properties, less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depletion, depreciation and amortization (“DD&A”) rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling.
During the year ended December 31, 2025, the Company recorded non-cash write-downs of the carrying value of the Company’s proved oil and natural gas properties as a result of ceiling test limitations of approximately $108.8 million, which is reflected as ceiling test impairment in the accompanying Statements of Operations. The Company did not have any write-downs related to the full cost ceiling limitation during the years ended December 31, 2024 or 2023.
Our estimates of reserves and future cash flow as of December 31, 2025 and 2024 were prepared using an average price equal to the unweighted arithmetic average of the first day of the month price for each month within the 12-month periods ended December 31, 2025 and 2024, respectively, in accordance with SEC guidelines. As of December 31, 2025, our reserves were based on an SEC average price of $61.82 per Bbl of WTI oil posted and $3.387 per MMBtu Henry Hub natural gas. As of December 31, 2024, our reserves were based on an SEC average price of $71.96 per Bbl of WTI oil
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posted and $2.130 per MMBtu Henry Hub natural gas. Prices are adjusted by local field and lease level differentials and are held constant for life of reserves in accordance with SEC guidelines. Continuing downward trends in SEC pricing could impact the Company's discounted future net revenues, resulting in non-cash impairments in future periods. Due to the complexity and uncertainty in numerous factors affecting the ceiling test calculation, including future prices, operating costs, upward or downward reserve revisions, the amount is not estimable.
Income Taxes. Deferred income taxes are provided on differences between the tax basis of assets and liabilities and their carrying amounts in the financial statements, and tax carryforwards. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is settled. Since our tax returns are filed after the financial statements are prepared, estimates are required in valuing tax assets and liabilities. We record adjustments to the actual values in the period the Company files its tax returns.
In assessing the Company's deferred tax assets, we consider whether a valuation allowance should be recorded for some or all of the deferred tax assets which may not be realized. The ultimate realization of deferred tax assets is assessed at each reporting period and is dependent upon the generation of future taxable income and the Company's ability to utilize net operating loss carryforwards during the periods in which the temporary differences become deductible. We also consider the reversal of deferred tax liabilities and available tax planning strategies. As of December 31, 2025 and 2024, the Company did not carry a valuation allowance against its federal and state deferred tax assets.
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