What changed in this filing

/stocks — the workspaceLOADING

Item 7. Management’s Discussion and Analysis

2026-03-04 compared with 2025-03-05 · 163 added, 158 removed, 221 unchanged (59% of the section changed)

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• 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.

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.

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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.

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 2024, in the Northwest Shelf, the Company drilled and completed two 1-mile horizontal wells (one with a working interest of 99.5% and the other with a working interest of 100%).

In the Central Basin Platform, the Company drilled and completed nine wells, all with a working interest of 100%.

Specifically, in our Andrews County

acreage the Company drilled and completed three 1-mile horizontal wells, in the Ector County acreage the Company drilled three vertical wells, and in the Crane County acreage the Company drilled and completed three vertical wells.

Additionally, within the Central Basin Platform, the Company drilled and completed one salt water disposal ("SWD") well in Crane County.

In the second quarter of 2024, in the Central Basin Platform, the Company drilled and completed eleven wells, all with a working interest of 100%.

Specifically, in our Andrews County acreage the Company drilled and completed five 1-mile horizontal wells, in the Ector County acreage the Company drilled three vertical wells, and in the Crane County acreage the Company drilled and completed three vertical wells.

During the third quarter of 2024, in the Northwest Shelf in Yoakum County, the Company drilled and completed two 1-mile horizontal wells, each with a working interest of 100%, and one 1.5-mile horizontal well with a working interest of approximately 94.2%.

Meanwhile, in the Central Basin Platform, the Company drilled and completed six vertical wells, all with a working interest of 100%, three in Ector County and three in Crane County.

Finally, in the Central Basin Platform in Andrews County, the Company drilled four 1-mile horizontal wells, all with a working interest of 100%.

Two of these wells were completed.

The remaining two wells were completed in the fourth quarter of 2024.

In the fourth quarter of 2024, the Company completed and placed on production the two aforementioned 1-mile horizontal wells in the Central Basin Platform.

The Company completed two additional 1-mile horizontal wells in the Central Basin Platform in Andrews County (both with a working interest of 100%).

On the southern side of the Central Basin Platform, the Company drilled and completed one vertical well in its Crane County acreage and three vertical wells in its Ector County acreage (each with a working interest of 100%).

Also in Crane County the Company drilled three 1-mile horizontal wells (each with a working interest of 100%), completing the first two in the fourth quarter, and the last well will be completed in 2025.

In summary, for 2024, the Company drilled 22 horizontal wells, 22 vertical wells, and one SWD well, completing all but one horizontal well.

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.

Quarter Area Wells Drilled Wells Completed Drilled Uncompleted ("DUC") (2)

Quarter Area Wells Drilled Wells Completed

1Q 2025 Northwest Shelf (Horizontal) 4 4

Central Basin Platform (Horizontal) 3 3 —

Central Basin Platform (Vertical) 3 3

2Q 2024 Northwest Shelf (Horizontal) — — —

Central Basin Platform (Horizontal) 5 5 —

2Q 2025 Central Basin Platform (Horizontal) 1 1

Central Basin Platform (Vertical) 1 1

Total 11 11 —

3Q 2024 Northwest Shelf (Horizontal) 3 3 —

Central Basin Platform (Horizontal) 4 2 2

3Q 2025 Central Basin Platform (Horizontal) 4 4

Central Basin Platform (Vertical) 1 1

Total 13 11 2

4Q 2025 Northwest Shelf (Horizontal) 1 1

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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 continued to demonstrate commodity price volatility and we believe oil and natural gas prices will continue to be volatile for the foreseeable future.

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.

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 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.

If these depressed or inverted natural gas prices return to the region, our natural gas revenues will continue to be negatively impacted.

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 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.

In addition, the attempts to reduce inflation by the U.S.

Federal Reserve have resulted in increased interest rates on debt, contributed to debt and equity market volatility, and increased substantially our interest expense.

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

The following table sets forth selected operating data for the periods indicated:

For the years ended December 31, 2025 2024 2023

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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

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Other income 189,294 106,656 198,935

Provision for Income Taxes $ (20,440,954) $ (125,242) $ (8,408,724)

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 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,

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 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.

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.

Year Ended December 31, 2024 Compared to Year Ended December 31, 2023

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.

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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 year-over-year.

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 to $0.07 in 2024 from $0.07 in 2023.

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.

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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 property coupled with a 1.6 million reduction in the amortization base (Boe).

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

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.

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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, which was substantially completed in September 2023.

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) .

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Gain (loss) on disposal of assets.

Gain (loss) on disposal of assets increased $176,821 to a gain $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 primarily from selling multiple leased vehicles during 2024, as opposed to a loss on disposal of assets primarily from selling multiple company owned vehicles during 2023.

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.

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The 2024 income tax provision was a significant change from year to year impacting the overall decrease in net income realized by the Company.

Year Ended December 31, 2023 Compared to Year Ended December 31, 2022

Oil sales increased approximately $28.0 million to $349.0 million in 2023 from $321.1 million in 2022.

The oil sales increased by a volume variance of approximately $103.9 million from a significant increase in sales volumes to 4,579,942 barrels of oil in 2023 from 3,459,840 barrels of oil in 2022, with approximately 19% of the increase in oil volumes related to the Founders Acquisition.

Other impacts to revenue volumes include organic growth from workovers, new drills, and other capital expenditures, offset by divestitures completed.

The volume variance was offset by a negative price variance of approximately $76.0 million from a decrease in the average realized per barrel oil price to $76.21 in 2023 from $92.80 in 2022.

Natural gas sales.

Natural gas sales decreased approximately $18.4 million to $0.3 million in 2023 from $18.7 million in 2022.

The natural gas sales decreased by a negative price variance of approximately $28.6 million, as the average realized per Mcf gas price decreased to $0.05 in 2023 from $4.57 in 2022.

The significant reduction in realized natural gas prices was driven by a lower market index price.

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.

In 2022, the average gross realized price for natural gas was $6.32 per Mcf, and the average fees per Mcf were $(1.75), bringing the net average price to $4.57 per Mcf.

This was partially offset by a volume variance of approximately $10.3 million as the volume increased to 6,339,158 Mcf in 2023 from 4,088,642 Mcf in 2022.

NGL sales increased approximately $4.2 million to $11.7 million in 2023 from $7.5 million in 2022.

NGL sales had a volume variance of approximately $12.2 million, as volumes were 976,852 barrels of NGLs in 2023 compared to 371,329 barrels in 2022.

The volumes increase was primarily due to the Company's change in reporting presentation for its natural gas productions, which were presented on a three-stream basis basis beginning July 1, 2022.

Offsetting this increase to sales was a negative price variance of approximately $8.0 million, as the average realized price per barrel of NGLs was $11.95 in 2023 compared to $20.18 in 2022.

Lease operating expenses.

Our total lease operating expenses (“LOE”) increased approximately $22.5 million to $70.2 million in 2023 from $47.7 million in 2022 and increased slightly on a Boe basis to $10.61 in 2023 from $10.57 in 2022.

These per Boe amounts are calculated by dividing our total LOE by our total volume sold, in Boe.

LOE increased primarily due to a 47% increase in production of 2,100,711 Boe year-over-year.

Specifically, the following cost increases accounted for the majority of the increase in LOE:

$7.5 million in LOE workover costs, $4.2 million in salaries and wages, $2.5 million in electrical/utilities costs, $1.6 million in equipment rental/services $1.3 million in supplies/materials, $1.2 million in contract services, and $1.0 million in chemicals/treating costs.

Gathering, transportation and processing costs.

Our total GTP costs decreased by $1,372,451 to $457,573 in 2023 from $1,830,024 in 2022 and decreased slightly on a Boe basis to $0.07 in 2023 from $0.41 in 2022.

In May 2022, a contract update with one of our largest natural gas processors altered the point of control of gas resulting in a change to the recording of those fees from expense to a netted reduction to revenues.

There remains only one contract with a natural gas processing entity in place where point of control of gas dictates requiring the fees be recorded as an expense.

Ad valorem taxes.

Our total ad valorem taxes increased approximately $2.1 million to $6.8 million in 2023 from $4.7 million in 2022 and decreased on a Boe basis to $1.02 in 2023 from $1.04 in 2022.

Ad valorem taxes increased due to a full year of taxes for the properties within counties acquired in the Stronghold Acquisition (i.e.

Crane County) as well as a partial year of taxes for properties within Ector County, acquired in the Founders Acquisition.

Additional increases were primarily in Yoakum County and Andrews County.

Oil and natural gas production taxes .

Oil and natural gas production taxes as a percentage of oil and natural gas sales increased to 5.02% in 2023 from 4.93% during 2022.

Overall, the percentage was consistent year over year.

Depreciation, depletion and amortization .

Our depreciation, depletion and amortization expense increased approximately $32.9 million to $88.6 million in 2023 from $55.7 million in 2022 due to an increase in our total estimated costs of property, resulting in a higher depletion expense per unit, as well as an increase of 2,100,711 in Boe produced.

Our average depreciation, depletion and amortization per Boe increased to $13.40 per Boe during 2023 from $12.35 per Boe during 2022.

Asset retirement obligation accretion.

Our asset retirement obligation (“ARO”) accretion increased by $442,254 to $1,425,686 in 2023 from $983,432 in 2022.

This was due to a full year of accretion on the assets acquired in the

Stronghold Acquisition, a partial year of accretion on the assets acquired in the Founders Acquisition, and new wells drilled during 2023, offset by wells sold during 2023.

Operating lease expense.

Our operating lease expense increased by $177,893 to $541,801 in 2023 from $363,908 in 2022 due to a full year of the Midland office lease additional space, which was amended effective October 1, 2022, as well as a quarter's impact of The Woodlands office lease additional space, which was substantially completed on September 27, 2023.

General and administrative expenses (including share-based compensation) .

General and administrative expenses increased approximately $2.1 million to $29.2 million in 2023 from $27.1 million in 2022.

The increase was primarily related to a $2.2 million increase in salaries, wages, and bonuses, a $1.7 million increase in share-based compensation, $0.6 million in additional legal fees, $0.5 million in higher software costs, $0.1 million in engineering costs, and $0.1 million in accounting, tax, and audit fees.

These cost increases were partially offset by a reduction of $2.0 million in transaction costs and a $0.6 million reduction in G&A costs from the Employee Retention Tax Credit.

Interest income.

Interest income increased by $257,151 to $257,155 in 2023 from $4 in 2022.

The 2023 interest income consisted of $226,315 from depositing excess cash balances in bank sweep accounts beginning in May 2023, $29,042 from interest earned on the Employee Retention Tax Credit, and $1,798 from interest earned on the escrow deposit made for the Founders Acquisition.

Interest expense .

Interest expense increased approximately $20.8 million to $43.9 million in 2023 from $23.2 million in 2022.

The increase was the result of a combination of higher interest rates, with a weighted average interest rate of 8.8% in 2023 and 5.8% in 2022, and having higher amounts outstanding on our credit facility throughout 2023, with a weighted average daily debt of approximately $422.5 million in 2023 compared to approximately $344.0 million in 2022.

Gain (loss) on derivative contracts.

During 2023, the Company incurred a gain on derivative contracts of approximately $2.8 million.

During 2022, the Company recorded a loss on derivative contracts of approximately $21.5 million.

For the derivative contract settlements, the Company recorded a realized loss of $9.1 million during 2023 and a realized loss of $62.5 million during 2022.

The decrease of $53.4 million in the realized loss was $50.5 million from realized oil derivative settlements and $2.9 million from realized natural gas derivative settlements.

For the marked-to-market contracts, the Company recorded an unrealized gain of $11.9 million during 2023 and an unrealized gain of $41.0 million during 2022.

This change of $29.1 million in unrealized derivatives was from $31.1 million in favorable derivative portfolio changes and futures pricing for marked-to-market oil derivative contracts, offset by $1.9 million unfavorable changes to the marked-to-market natural gas derivative contract balance.

Loss on disposal of assets.

During 2023, the Company recognized a loss on disposal of assets of $87,128 from selling multiple company owned vehicles.

Other income.

During 2023, the Company's other income of $198,935 primarily resulted from the termination of The Woodlands office operating lease as of May 31, 2023, along with a bank rebate related to the use of a vendor payment program.

Provision for income taxes .

The provision for income taxes changed to a provision of $125,242 for 2023 from a provision of $8,408,724 for 2022.

The current year change in the Company's federal tax provision was the result of a full valuation allowance release on federal taxes in 2023 with state tax activity recognized.

The Company achieved net income of $104,864,641 in 2023 compared to net income of $138,635,025 in 2022 compared.

The decrease in net income was due to increased LOE costs, depletion, depreciation, and amortization costs, and interest expense and lower natural gas revenues.

This was offset by increased oil and NGL revenues in addition to a more favorable derivative contract portfolio in comparison with the year-end commodity futures prices.

Liquidity and Capital Resources

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Credit Facility.

On July 1, 2014, the Company entered into a Credit Agreement with SunTrust Bank (now Truist Bank), as lender, issuing bank and administrative agent for several banks and other financial institutions and lenders (the “Administrative Agent”), (which was amended several times) that provided for a maximum borrowing base of $1 billion with security consisting of substantially all of the assets of the Company.

In April 2019, the Company amended and restated the Credit Agreement with the Administrative Agent (as amended and restated, the “Amended Credit Facility”).

On August 31, 2022, the Company modified its Amended Credit Facility through that certain Second Amended and Restated Credit Agreement (the "Second Credit Agreement"), extending the maturity date of the facility to August 2026 and the syndicate was modified to add five lenders, replacing five lenders.

On February 12, 2024, the Company, Truist Bank as the Administrative Agent and Issuing Bank, and the lenders party thereto (the "Lenders") entered into an amendment (the "Amendment") to the Second Credit Agreement.

Among other things, the Amendment amends the definition of Free Cash Flow so amounts used by the Company for acquisitions will no longer be subtracted from the calculation of Free Cash Flow.

The Second Credit Agreement has a borrowing base of $600 million, which is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time.

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.

Rather than Eurodollar loans, the reference rate in the Second Credit Agreement is the SOFR.

Also, the Second Credit Agreement permits the Company to declare dividends for its equity owners, subject to certain limitations, including (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, taxes, depreciation 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 Second Credit Agreement), and (iv) the Borrowing Base Utilization Percentage (as defined in the Second Credit Agreement) is not greater than 80%.

The interest rate on each SOFR Loan will be the adjusted term SOFR for the applicable interest period plus a margin between 3.0% and 4.0% (depending on the then-current level of borrowing base usage).

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 Second 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) 0.00% per annum, plus (b) a margin between 2.0% and 3.0% per annum (depending on the then-current level of borrowing base usage).

The Second 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 Second Credit Agreement) of 1.0 to 1.0.

The Second Credit Agreement also contains other customary affirmative and negative covenants and events of default.

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, if the borrowing base utilization is less than 25% at the hedge testing date 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 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, 2024, $385 million was outstanding on the Credit Facility and the Company was in compliance with all covenants in the Second Credit Agreement.

Equity Offering.

In October 2020, the Company closed on an underwritten public offering of (i) 9,575,800 Common Shares, (ii) 13,428,500 Pre-Funded Warrants and (iii) 23,004,300 Common Warrants at a combined purchase price of $0.70.

This includes a partial exercise of the over-allotment.

The Common Warrants have a term of five years and an exercise price of $0.80 per share.

Gross proceeds totaled $16,089,582.

Concurrently with the underwritten public offering, the Company closed on a registered direct offering of (i) 3,500,000 Common Shares, (ii) 3,300,000 Pre-Funded Warrants and (iii) 6,800,000 Common Warrants at a combined

purchase price of $0.70.

The Common Warrants have a term of five years and an exercise price of $0.80 per share.

Gross proceeds totaled $4,756,700.

Total gross proceeds from the 2020 underwritten public offering and the registered direct offering aggregated $20,846,282.

Total net proceeds for the Common Warrants exercised in 2020 aggregated $19,379,832.

The Common Shares of 9,575,800 and 3,500,000 were issued in 2020.

The Pre-Funded Warrants of 3,300,000 were exercised and common stock was issued in 2020.

The Pre-Funded Warrants of 13,428,500 were exercised and common stock was issued in 2021, as shown in our Statement of Stockholders' Equity.

Of the aforementioned 23,004,300 Common Warrants, 442,600 were exercised and common stock was issued in 2021;

10,253,907 were exercised and common stock was issued in 2022;

and 19,029,593 were exercised and common stock was issued in 2023 (4,517,427 exercised at $0.80 and 14,512,166 exercised at $0.62 - refer to NOTE 11 — STOCKHOLDERS' EQUITY), and no Common Warrants were exercised during 2024;

as shown in our Statement of Stockholders' Equity.

Issuance of Common Stock and Convertible Preferred Stock for Stronghold Acquisition.

As part of the consideration for the Stronghold Acquisition, on August 31, 2022 the Company issued 21,339,986 shares of common stock and 153,176 shares of newly created Series A Convertible Preferred Stock, which was converted into 42,548,892 shares of common stock on October 27, 2022.

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.

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 2024, 2023, and 2022, the Company had a net repayment of $40.0 million, a net draw of $10.0 million, and a net draw of $125.0 million on the Credit Facility, respectively.

During 2025, 2024, and 2023, the Company had a

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.

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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, 2024 was $385 million, which will require repayment or refinancing at or prior to maturity in August 2026.

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 was under a five-and-a-half-year lease beginning January 15, 2021;

however, effective as of May 31, 2023, The Woodlands office sub-lease was terminated.

On May 9, 2023, the Company entered into a 71-month (five years and 11-month) new lease for a larger amount of office space in The Woodlands, Texas.

The Midland office lease was amended effective October 1, 2022, with the revised five-year lease ending September 30, 2027.

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.

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Off-Balance Sheet Financing Arrangements

As of December 31, 2024, we had no off-balance sheet financing arrangements.

As of December 31, 2025, the Company had no off-balance sheet financing arrangements.

Critical Accounting Policies and Estimates

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the accuracy of various mandated economic assumptions;

• the judgments of the persons preparing the estimates.

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.

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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, 2024,

our reserves were based on an SEC average price of $71.96 per Bbl of WTI oil posted and $2.130 per MMBtu Henry Hub natural gas.

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

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.

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis