What changed in this filing

/stocks — the workspaceLOADING

Item 7. Management’s Discussion and Analysis

2025-03-05 compared with 2024-03-07 · 147 added, 139 removed, 232 unchanged (55% of the section changed)

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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 and is engaged in oil and natural gas development, production, acquisition, and exploration activities currently focused in the Permian Basin of Texas.

(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.

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2024 Developments and Highlights

Drilling, Completion, and Recompletion

In the first quarter of 2023, in the Northwest Shelf, the Company drilled and completed two 1-mile horizontal wells (each with a working interest of 100%), and two 1.5-mile horizontal wells (one with a working interest of approximately 99.8% and the other with a working interest of approximately 75.4%).

Next, in its Crane County acreage

within the Central Basin Platform, the Company drilled and completed three vertical wells (each with a working interest of 100%) and performed six vertical well recompletions (each with a working interest of 100%).

In the second quarter of 2023, in the Northwest Shelf, the Company drilled and completed two 1.5-mile horizontal wells (one with a working interest of 100% and the other with a working interest of approximately 75.4%) and two 1-mile horizontal wells (both with a working interest of approximately 91.1%).

Additionally, in its Crane County acreage within the Central Basin Platform, the Company drilled and completed two vertical wells (each with a working interest of 100%) and performed three vertical well recompletions (each with a working interest of 100%).

During the third quarter of 2023, the Company drilled and completed two 1-mile horizontal wells (one with a working interest of 100% and the other with a working interest of 75%) in the Northwest Shelf, and three 1.5-mile horizontal wells (each with a working interest of 100%) in the Central Basin Platform.

Additionally, in its Crane County acreage within the Central Basin Platform, the Company drilled and completed three vertical wells (each with a working interest of 100%).

Lastly, the Company drilled and began the completion process on three 1-mile horizontal wells in the Northwest Shelf (each with a working interest of 100%).

In the fourth quarter of 2023, the Company completed and placed on production the three aforementioned 1-mile horizontal wells in the Northwest Shelf.

Additionally, the Company drilled and completed one saltwater disposal (SWD) well in the Northwest Shelf (with a working interest of 100%), and completed the 2023 horizontal drilling program with one 1.5-mile horizontal well in the Northwest Shelf (with a working interest of approximately 97.7%), as well as two 1-mile horizontal wells and one 1.5-mile horizontal well (each with a working interest of 100%) in the Central Basin Platform.

In its Crane County acreage within the Central Basin Platform, the Company drilled and completed three vertical wells (each with a working interest of 100%).

In summary, for 2023, the Company drilled and completed 20 horizontal wells, 11 vertical wells, and 1 SWD well.

In addition, the Company performed 9 vertical well recompletions.

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.

The table below sets forth our drilling and completion activities for 2024 by quarter, and full year total through December 31, 2024.

Quarter Area Wells Drilled Wells Completed Recompletions

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

1Q 2024 Northwest Shelf (Horizontal) 2 2 —

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Central Basin Platform (Vertical) 6 6 —

Total 11 11 —

3Q 2024 Northwest Shelf (Horizontal) 3 3 —

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Central Basin Platform (Vertical) 6 6 —

Total 13 11 2

4Q 2024 Northwest Shelf (Horizontal) — — —

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Central Basin Platform (Vertical) 22 22 —

(1) Fourth quarter total and full year total do not include one SWD well completed in the Northwest Shelf.

(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.

Market Conditions and Commodity Prices

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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 2022 and 2023 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 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.

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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 continue in the region, our natural gas revenues will continue to be negatively impacted.

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.

Inflation has increased costs associated with our capital program and production operations.

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Gain (loss) on derivative contracts (2,365,917) 2,767,162 (21,532,659)

Loss on disposal of assets

Gain (loss) on disposal of assets 89,693 (87,128) —

Other income 106,656 198,935 —

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

$ (125,242) $ (8,408,724) $ (90,342)

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 $103.9 million from a significant increase in sales volumes to 4,579,942 barrels of oil in 2023from 3,459,840 barrels of oil in 2022, with approximately 19% of the increase in oil

volumes related to the Founders Acquisition.

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 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 year-over-year.

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.

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 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, which was 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 $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.

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.

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.

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.

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Gathering, transportation and processing costs.

Our total gathering, transportation and processing costs (“GTP”) 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.

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.

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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.

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.

well as a quarter's impact of The Woodlands office lease additional space, which was substantially completed on September 27, 2023.

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) .

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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.

Year Ended December 31, 2022 Compared to Year Ended December 31, 2021

Oil sales increased approximately $139.5 million from $181.5 million in 2021 to $321.1 million in 2022 due to an increase in the average realized per barrel oil price from $67.56 in 2021 to $92.80 in 2022 and an increase in sales volume from 2,686,940 barrels of oil in 2021 to 3,459,840 barrels of oil in 2022.

The increased average realized per barrel oil price was a result of the significantly higher oil price during the first eight months of 2022.

The increased sales volumes were a direct result of assets acquired in the Stronghold Acquisition, which resulted in higher volumes for the last four months of 2022, as well as organic growth from capital expenditures that were $78.0 million greater in 2022 than in 2021.

Natural gas sales.

Natural gas sales increased approximately $3.9 million from $14.8 million in 2021 to $18.7 million in 2022.

The natural gas sales volume increased from 2,535,188 Mcf in 2021 to 4,088,642 Mcf in 2022 and the average realized per Mcf gas price decreased from $5.83 in 2021 to $4.57 in 2022.

The sales volume increase was due to

the aforementioned increase in capital expenditures as well as the Stronghold Acquisition, which closed August 31, 2022.

The price decrease was driven by the Company's change in reporting presentation from two-stream (oil and natural gas) to three-stream (oil, natural gas and NGLs) beginning July 1, 2022.

NGL sales increased approximately $7.5 million from $0.0 million in 2021 to $7.5 million in 2022.

NGL sales volumes in were 371,329 barrels compared to zero barrels in 2021, due to the Company’s change in reporting presentation for its natural gas products, which were presented on a three-stream basis beginning July 1, 2022.

The average realized price per barrel of NGLs was $20.18 in 2022.

Lease operating expenses.

Our total LOE increased from $30,312,399 in 2021 to $47,695,351 in 2022 and increased on a Boe basis from $9.75 in 2021 to $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 45% increase in production of 1,403,502 Boe year-over-year, as well as increased costs for goods and services due to increased Permian activity.

Gathering, transportation and processing costs.

Our total GTP decreased from $4,333,232 in 2021 to $1,830,024 in 2022 and decreased on a Boe basis from $1.39 in 2021 to $0.41 in 2022.

GTP costs decreased due to costs classified as a reduction to oil and natural gas sales revenues, due to a natural gas processing entity beginning to take control of transportation at the wellhead beginning May 1, 2022.

Ad valorem taxes.

Our total ad valorem taxes increased from $2,276,463 in 2021 to $4,670,617 in 2022 and increased on a Boe basis from $0.73 in 2021 to $1.04 in 2022.

Ad valorem taxes increased primarily due to the increase in taxed commodity prices from the prior year, as well as $783,159 for the properties acquired in the Stronghold Acquisition.

Oil and natural gas production taxes .

Oil and natural gas production taxes as a percentage of oil and natural gas sales were 4.65% during 2021 and increased to 4.93% in 2022.

Overall, the percentage was consistent year over year, with a slight increase due to proportionately higher gas revenues which are taxed at a higher rate.

Production taxes vary from state to state.

Therefore, these taxes are likely to vary in the future depending on the mix of production we generate from various states (currently only Texas and New Mexico), and on the possibility that any state may raise its production tax rates.

Depreciation, depletion and amortization .

Our depreciation, depletion and amortization expense increased from $37,167,967 in 2021 to $55,740,767 in 2022 due to an increase in our total estimated costs of property as well as an increase of 1,403,502 in Boe produced.

Our average depreciation, depletion and amortization per Boe increased from $11.95 per Boe during 2021 to $12.35 per Boe during 2022.

These per Boe amounts are calculated by dividing our total depreciation, depletion and amortization expense by our total Boe volumes sold.

Asset retirement obligation accretion.

Our ARO accretion increased from $744,045 in 2021 to $983,432 in 2022.

This was a result of the 32 additional wells added from 2022 drilling activities as well as ARO accretion associated with the properties acquired in the Stronghold Acquisition, offset by wells plugged and abandoned during 2022.

Operating lease expense.

Our operating lease expense decreased from $523,487 in 2021 to $363,908 in 2022 due to the month to month leases for office equipment and compressors used in operations on which the Company had previously elected to apply ASU 2016-02.

The office equipment and compressors are not subject to ASU 2016-02 based on the agreement and nature of use.

The costs have been recorded as short-term lease costs and amounts included in lease operating expenses beginning in the second quarter of 2021.

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

General and administrative expenses increased from $16,068,105 in 2021 to $27,095,323 in 2022.

The increase was primarily related to a $4,743,908 increase in share-based compensation, as well as increases in salaries and bonuses, all attributed to a nearly doubled headcount from 2021 to 2022 to support our growth.

Other cost increases include software maintenance, rent, insurance, and environmental sustainability.

The 2022 expenses also included non-recurring acquisition-related costs of $2.1 million.

Interest expense .

Interest expense increased from $14,490,474 in 2021 to $23,167,729 in 2022.

The increase was the result of a combination of higher interest rates during the second half of 2022, with a weighted average interest rate of 5.8% in 2022 and 4.4% in 2021, and having higher amounts outstanding on our credit facility throughout 2022, with a weighted average daily debt of approximately $308.7 million in 2021 compared to approximately $344.0 million in 2022, particularly due to the additional debt incurred for the Stronghold Acquisition.

Gain (loss) on derivative contracts.

During 2022, the Company incurred a loss on derivative contracts of $21,532,659.

During 2021, the Company recorded a loss on derivative contracts of $77,853,141.

For the derivative contract settlements, the Company recorded a realized loss of $52,768,154 during 2021 and a realized loss of $62,525,954 during 2022, The increase of $9,757,800 in the realized loss was a result of the rise of crude oil prices during 2022, which was above the fixed prices of the derivative contracts.

For the marked-to-market contracts, the Company recorded an unrealized gain of $40,993,295 during 2022 and an unrealized loss of $25,084,987 during 2021.

This change in unrealized derivatives was due to the roll off of unfavorable contracts during 2022, as well as the Company's purchase of more favorable contracts during 2022.

Provision for income taxes .

The provision for income taxes changed from a provision of $90,342 for 2021 to a provision of $8,408,724 for 2022.

The current year federal tax expense was the result of certain existing deferred tax assets that will not be offset by existing deferred tax liabilities as a result of the 80% limitation on the utilization of net operating losses incurred after 2017.

The Company achieved net income of $3,322,892 in 2021 compared to net income of $138,635,025 in 2022.

The increase in net income was due primarily to the increase in oil, natural gas, and NGL revenues, as well as the reduction in derivative contract losses, offset by increases in lease operating expenses, depletion, general and administrative expenses, and interest expense.

Liquidity and Capital Resources

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Our primary source of cash in 2024 was from funds generated from the sale of oil and natural gas production.

These cash flows were primarily used to fund our capital expenditures.

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 July 1, 2014, the Company entered into a Credit Agreement with SunTrust Bank (now Truist), 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 “Credit Facility”).

On August 31, 2022, the Company modified its Credit Facility through a 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.

In conjunction with the Stronghold Acquisition, with the newly acquired assets put up for collateral, the Company established a borrowing base of $600 million.

The borrowing base is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time.

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.

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 or its subsidiaries and cancellation of certain hedging positions.

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

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%.

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The Second 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, 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, 2023, $425 million was outstanding on the Credit Facility and the Company was in compliance with all covenants contained in the Second Credit Agreement.

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.

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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.

purchase price of $0.70.

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

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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 Statements of Stockholders' Equity.

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);

as shown in our Statements of Stockholders' Equity.

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.

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During the three years ended December 31, 2024, we financed $20.5 million through proceeds from the sale of common stock.

During 2023, 2022, and 2021, the Company had a net draw of $10.0 million, a net draw of $125.0 million, and a net repayment of $23.0 million on the Credit Facility, respectively.

We primarily used this cash to fund our capital expenditures and development aggregating $596.9 million over the three years ended December 31, 2023.

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.

We used cash to fund our capital expenditures and development aggregating $700.3 million over the three years ended December 31, 2024.

Additionally, during 2024, 2023 and 2022, we used cash of $170.0 million, $215.0 million and $511.0 million, respectively, to reduce the outstanding balance on our Credit Facility.

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Future lease payments for financing leases aggregate $1,667,763.

Subsequent Events

Surety Bonds - On January 10, 2024, two insurance companies issued surety bonds on behalf of the Company, one for $250,000, an RRC required blanket performance bond to operate 100 wells or more in the State of Texas, and one for $2,000,000, an RRC required blanket plugging extension bond, each with zero collateral requirements.

The term for these two surety bonds ends on July 1, 2025 and can be renewed at that time.

First Amendment to Second Amended and Restated Credit Agreement - On February 12, 2024, the Company, Truist Bank ("Truist") as the Administrative Agent and Issuing Bank, and the lenders party thereto (the "Lenders") entered into an amendment (the "Amendment") to the Second Amended and Restated Credit Agreement dated August 31, 2022, by and among the Company, as Borrower, Truist as Administrative Agent and Issuing Bank, and the Lenders (together with all amendments or other modifications, the "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.

Effects of Inflation and Pricing

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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.

Revenue Recognition.

In January 2018, the Company adopted Accounting Standards Update (“ASU”) 2014-09 Revenues from Contracts with Customers (Topic 606) (“ASU 2014-09”).

The timing of recognizing revenue from the sale of produced crude oil and natural gas was not changed as a result of adopting ASU 2014-09.

The Company predominantly derives its revenue from the sale of produced crude oil and natural gas.

The contractual performance obligation is satisfied when the product is delivered to the purchaser.

Revenue is recorded in the month the product is delivered to the purchaser.

The Company receives payment from one to three months after delivery.

The transaction price includes variable consideration as product pricing is based on published market prices and reduced for contract specified differentials (quality, transportation and other variables from benchmark prices).

The guidance regarding ASU 2014-09 does not require that the transaction price be fixed or stated in the contract.

Estimating the variable consideration does not require significant judgment and Ring engages third party sources to validate the estimates.

Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration the Company expects to receive in exchange for those products.

See "Note 2 — REVENUE RECOGNITION" of our financial statements for additional information.

Full Cost Method of Accounting.

The Company uses the full cost method of accounting for oil and natural gas properties.

Under this method, all costs (direct and indirect) associated with acquisition, exploration, and development of oil and natural gas properties are capitalized.

Costs capitalized include acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties and costs of drilling and equipping productive and non-productive wells.

Drilling costs include directly related overhead costs.

All of our properties are located within the continental United States.

Write-down 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.

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.

The Company did not have any write-downs related to the full cost ceiling limitation during the years ended December 31, 2023, 2022, or 2021.

Our estimates of reserves and future cash flow as of December 31, 2023 and 2022 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, 2023 and 2022, respectively, in accordance with SEC guidelines.

As of December 31, 2023, our reserves were based on an SEC average price of $74.70 per Bbl of WTI oil posted and $2.637 per MMBtu Henry Hub natural gas.

As of December 31, 2022, our reserves were based on an SEC average price of $90.15 per Bbl of WTI oil posted and $6.358 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.

Oil and Natural Gas Reserve Quantities.

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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.

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.

The Company did not have any write-downs related to the full cost ceiling limitation during the years ended December 31, 2024, 2023, or 2022.

Our estimates of reserves and future cash flow as of December 31, 2024 and 2023 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, 2024 and 2023, 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, 2023, our reserves were based on an SEC average price of $74.70 per Bbl of WTI oil posted and $2.637 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.

Income Taxes.

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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 operation loss carryforwards during the periods in which the temporary differences become deductible.

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, 2024 and 2023, the Company did not carry a valuation allowance against its federal and state deferred tax assets.

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