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Item 7. Management’s Discussion and Analysis

2024-03-07 compared with 2023-03-09 · 200 added, 186 removed, 171 unchanged (69% of the section changed)

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The following discussion includes forward-looking statements that reflect our plans, estimates, and beliefs and our actual results could differ materially from those discussed in these forward-looking statements as a result of many factors, including those discussed under “Risk Factors,” "Forward Looking Statements," and elsewhere in this Annual Report.

Ring is a growth oriented independent 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.

Our primary drilling operations target the oil and liquids rich producing formations in the Northwest Shelf, the Central Basin Platform, and the Delaware Basin all of which are part of the Permian Basin.

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.

Our drilling operations target the oil and liquids rich producing formations in the Northwest Shelf and the Central Basin Platform, in the Permian Basin in Texas.

Business Description and Plan of Operation

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We intend to continue evaluating potential transactions to acquire strategic producing assets with attractive acreage positions that can provide competitive returns for our shareholders.

• Growing production and reserves by developing our oil-rich resource base through conventional and horizontal drilling .

In an effort to maximize its value and resources potential, Ring intends to drill and develop its acreage base in both the Northwest Shelf and Central Basin Platform assets, allowing Ring to execute on its plan of operating within its generated cash flow.

• Reduction of long-term debt and deleveraging of asset.

Ring intends to reduce its long-term debt primarily through the use of excess cash flow and potentially through the sale of non-core assets.

The Company believes that with its attractive field level margins, it is positioned to maximize the value of its assets and deleverage its balance sheet.

The Company also believes through potential accretive acquisitions and strategic asset dispositions, it can accelerate the strengthening of its balance sheet.

During the three months ended December 31, 2023, the Company made net paydowns of $3 million on its revolving line of credit, resulting in the outstanding long-term debt balance of $425 million.

• Employ industry leading drilling and completion techniques .

Ring’s executive team intends to utilize new and innovative technological advancements for completion optimization, comprehensive geological evaluation, and reservoir engineering analysis to generate value and to build future development opportunities.

These technological advancements have led to a low-cost structure that helps maximize the returns generated by our drilling programs.

• Pursue strategic acquisitions with attractive upside potential.

Ring has a history of acquiring leasehold positions that it believes to have additional resource potential that meet its targeted returns on invested capital and comparable to its existing inventory of drilling locations.

We pursue an acquisition strategy designed to increase reserves at attractive finding costs and complement existing core properties.

Management intends to continue to pursue strategic acquisitions and structure the potential transactions financially, so they improve our balance sheet metrics and are accretive to shareholders.

Our executive team, with its extensive experience in the Permian Basin, has many relationships with operators and service providers in the region.

2023 Developments and Highlights

Stronghold Acquisition

On July 1, 2022, Ring, as buyer, and Stronghold Energy II Operating, LLC, a Delaware limited liability company (“Stronghold OpCo”) and Stronghold Energy II Royalties, LP, a Delaware limited partnership (“Stronghold RoyaltyCo”, together with Stronghold OpCo, collectively, “Stronghold”), as seller, entered into a purchase and sale agreement (the “Purchase Agreement”).

Pursuant to the Purchase Agreement, Ring acquired (the “Stronghold Acquisition”) interests in oil and gas leases and related property of Stronghold consisting of approximately 37,000 net acres located in the Central Basin Platform of the Texas Permian Basin.

On August 31, 2022, Ring completed the Stronghold Acquisition.

The fair value of consideration paid to Stronghold was approximately $394.0 million, of which $165.9 million, net of customary purchase price adjustments, was paid in cash at closing, $15.0 million was paid in cash after the six-month anniversary of the closing date of the Stronghold Acquisition.

Shortly after closing, approximately $4.5 million was paid for inventory and vehicles and approximately $1.8 million was paid for August oil derivative settlements for certain novated hedges.

The cash portion of the consideration was funded primarily from borrowings under a new fully committed revolving credit facility (the “Credit Facility”) underwritten by Truist Securities, Citizens Bank, N.A., KeyBanc Capital Markets Inc., and Mizuho Bank, Ltd.

The borrowing base of the $1.0 billion Credit Facility was increased from $350.0 million to $600.0 million at the closing of the Stronghold Acquisition.

The remaining consideration consisted of 21,339,986 shares of Ring common stock and 153,176 shares of newly created Series A Convertible Preferred Stock, par value $0.001 (“Preferred Stock”) which was converted into 42,548,892 shares of common stock on October 27, 2022.

Please see "Note 12 - STOCKHOLDERS' EQUITY" for further discussion.

In addition, Ring assumed $24.8 million of derivative liabilities,$1.7 million of items in suspense and $14.5 million in asset retirement obligations.

Drilling, Completion, and Recompletion

In the first quarter of 2022, we contracted a rig for our horizontal drilling program and began operations on January 31st.

We drilled and completed three 1-mile horizontal wells and one 1.5-mile horizontal well in the Central Basin Platform.

We then moved the rig to the Northwest Shelf and drilled two 1-mile horizontal wells.

All wells drilled in the first quarter had a working interest of 100%.

In the second quarter of 2022, we drilled a total of nine wells, completed seven wells, and began the completion process on four wells, all in the Northwest Shelf.

The first wells completed were the two 1-mile horizontal wells, which were drilled in the first quarter.

Next, we drilled and completed two 1-mile horizontal wells with a working interest of

100%, two 1.5-mile horizontal wells with a working interest of approximately 98.7% and one 1-mile horizontal well with a working interest of approximately 75.4%.

We also drilled and began the completion process on an additional four 1-mile horizontal wells.

Two of the wells have a working interest of 100%, one has a working interest of approximately 87.9%, and the fourth has a working interest of 75%.

In the third quarter of 2022, we completed and placed on production the four aforementioned 1-mile horizontal wells in the Northwest Shelf, which were drilled in the second quarter.

Next, we drilled and completed two 1.5-mile horizontal wells and one 1-mile horizontal well in the Central Basin Platform and two 1-mile horizontal wells in the Northwest Shelf, each with a working interest of 100%.

During the last month of the quarter, we drilled and began the completion process on three 1-mile horizontal wells in the Northwest Shelf, two with a working interest of 99.7% and one with a working interest of 100%.

In total, during the third quarter of 2022, we drilled eight, completed nine, and began the completion process on three horizontal wells.

With the addition of the Stronghold Acquisition assets in the Central Basin Platform, we also performed three vertical well re-completions.

In the fourth quarter of 2022, we completed and placed on production the three aforementioned 1-mile horizontal wells in the Northwest Shelf.

Next, we drilled and completed two 1-mile horizontal wells with a working interest of 100%, also in the Northwest Shelf.

To complete the 2022 horizontal drilling program, we drilled and completed two 1.5-mile horizontal wells in the Central Basin Platform.

In addition to the horizontal wells, we performed nine more vertical well re-completions and drilled and completed five new vertical wells on the Stronghold Acquisition assets located in Crane County, Texas, of the Central Basin Platform, all with a working interest of 100%.

In summary, for 2022, we drilled and completed 27 horizontal wells and 5 vertical wells, along with 12 vertical well re-completions on the Stronghold Acquisition assets.

The table below sets forth our drilling and completion activities for 2022 by quarter through December 31, 2022.

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.

The table below sets forth our drilling and completion activities for 2023 by quarter, and full year total through December 31, 2023.

Quarter Area Wells Drilled Wells Completed Recompletions

1Q 2022 Central Basin Platform (Horizontal) 4 4 —

1Q 2023 Northwest Shelf (Horizontal) 4 4 —

Central Basin Platform (Horizontal) — — —

Central Basin Platform (Vertical) 3 3 6

Northwest Shelf 2 — —

2Q 2022 Central Basin Platform (Horizontal) — — —

2Q 2023 Northwest Shelf (Horizontal) 4 4 —

Central Basin Platform (Horizontal) — — —

Central Basin Platform (Vertical) 2 2 3

Northwest Shelf 9 7 —

3Q 2022 Central Basin Platform (Horizontal) 3 3 —

3Q 2023 Northwest Shelf (Horizontal) 5 2 —

Central Basin Platform (Horizontal) 3 3 —

Central Basin Platform (Vertical) 3 3 —

Northwest Shelf 5 6 —

4Q 2022 Central Basin Platform (Horizontal) 2 2 —

4Q 2023 Northwest Shelf (Horizontal) 1 4 —

Central Basin Platform (Horizontal) 3 3 —

Central Basin Platform (Vertical) 3 3 —

Northwest Shelf 2 5 —

Northwest Shelf (Horizontal) 14 14 —

Central Basin Platform (Horizontal) 6 6 —

Central Basin Platform (Vertical) 11 11 9

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

Market Conditions and Commodity Prices

Our financial results depend on many factors, particularly the price of crude oil and natural gas and our ability to market our production on economically attractive terms.

Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials and other factors.

Commodity prices are affected by many factors outside of our control, including changes in market supply and demand both domestically and world wide, which are impacted by many factors.

As a result, we cannot accurately predict future commodity prices, and therefore, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our drilling program, production volumes, or revenues.

The improvement of oil and natural gas prices experienced in 2022 continues 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 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.

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.

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 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

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Ad valorem taxes 6,757,841 4,670,617 2,276,463

Production taxes 17,125,982 9,123,420 5,228,090

Oil and natural gas production taxes 18,135,336 17,125,982 9,123,420

Other costs and operating expenses:

Depreciation, depletion and amortization expense $ 55,740,767 $ 37,167,967 $ 43,010,660

Ceiling test impairment — — 277,501,943

Depreciation, depletion and amortization $ 88,610,291 $ 55,740,767 $ 37,167,967

Asset retirement obligation accretion 1,425,686 983,432 744,045

Operating lease expense 541,801 363,908 523,487

General and administrative expense

(excluding stock-based compensation) 19,933,092 13,649,782 11,509,888

Stock-based compensation expense 7,162,231 2,418,323 5,364,162

General and administrative expense ("G&A")

29,188,755 27,095,323 16,068,105

Share-based compensation 8,833,425 7,162,231 2,418,323

G&A excluding share-based compensation

20,355,330 19,933,092 13,649,782

Other income (expense):

Interest income 257,155 4 1

Interest (expense) $ (43,926,732) $ (23,167,729) $ (14,490,474)

Gain (loss) on derivative contracts 2,767,162 (21,532,659) (77,853,141)

Deposit forfeiture income — — 5,500,000

Loss on disposal of assets

Other income 198,935 — —

Provision for Income Taxes

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

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

Oil sales increased approximately $139.5 million from $181.5 million in 2021 to $321.1 million in 2022.

The oil sales increase was the result of 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.

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 2023from 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 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.

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.

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.

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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 natural gas liquids) beginning July 1, 2022.

Natural gas liquids sales.

Natural gas liquids 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 of NGLs compared to zero barrels in 2021, due to the Company’s change in reporting presentation for its natural gas products, which are presented on a three-stream basis beginning July 1, 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 lease operating expenses (“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 lease operating expenses by our total volume sold, in Boe.

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 gathering, transportation and processing costs (“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.

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.

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Asset retirement obligation accretion.

Our asset retirement obligation (“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 the year.

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

Operating lease expense.

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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 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.

Benefit from (Provision for) income taxes .

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

Net income (loss) .

The Company had a 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 natural gas liquids 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.

Year Ended December 31, 2021 Compared to Year Ended December 31, 2020

Oil and natural gas sales .

Oil and natural gas sales revenue increased from 2020 levels by approximately $83.3 million to $196.3 million in 2021.

Oil sales increased approximately $72.4 million and natural gas sales increased approximately $10.9 million.

The oil sales increase was the result of an increase in the average realized per barrel oil price from $38.95 in 2020 to $67.56 in 2021, slightly offset by a decrease in sales volume from 2,801,528 barrels of oil in 2020 to 2,686,940 barrels of oil in 2021.

These per barrel amounts are calculated by dividing revenue from oil sales by the volume of oil sold, in barrels.

Despite the few months of shut in or curtailed production due to oil price destabilizing from the COVID-19 pandemic, volumes in 2020 significantly benefited from the large amount of capital expenditures incurred in the previous year.

Likewise, the lower capital expenditures in 2020 resulted in a negative impact to 2021 volumes due to natural well declines.

Capital expenditures in 2021 helped offset declines, but not enough to overcome the full impact from the reduced capital expenditures in 2020.

The natural gas sales volume increased slightly from 2,494,502 Mcf in 2020 to 2,535,188 Mcf in 2021 and the average realized per Mcf gas price increased from $1.57 in 2020 to $5.83 in 2021.

The price increase was driven by a steady increase in NGL prices and a 92% increase in the underlying Henry Hub gas price, which included the impact of Winter Storm Uri in 2021.

These per Mcf amounts are calculated by dividing revenue from gas sales by the volume of gas sold, in Mcf.

Natural gas sales volumes in 2021 were positively impacted by higher volumes associated with reservoir de-pressurization at the Northwest Shelf properties which were partially offset by purchaser inability to receive gas volumes at certain times throughout the year due to downtime or mechanical issues effecting efficiencies with their facilities.

Lease operating expenses.

Our total lease operating expenses (“LOE”) increased slightly from $29,753,413 in 2020 to $30,312,399 in 2021 and increased on a Boe basis from $9.25 in 2020 to $9.75 in 2021.

These per Boe amounts are calculated by dividing our total lease operating expenses by our total volume sold, in Boe.

LOE increased due to the higher amount of activity in 2021 compared to the lack of activity resulting from the oil price destabilization due to the COVID-19 pandemic in 2020.

Gathering, transportation and processing costs.

Our total gathering, transportation and processing costs (“GTP”) increased slightly from $4,090,238 in 2020 to $4,333,232 in 2021 and increased on a Boe basis from $1.27 in 2020 to $1.39 in 2021.

GTP costs increased due to the higher gas volumes processed in the Northwest Shelf.

Ad valorem taxes.

Our total ad valorem taxes decreased from $3,125,222 in 2020 to $2,276,463 in 2021 and decreased on a Boe basis from $0.97 in 2020 to $0.73 in 2021.

Ad valorem taxes decreased due to the Company’s compliance department’s annual detailed review of each property’s current production, ownership, and lease operating expenses, which resulted in cost savings for the taxes assessed.

Oil and natural gas production taxes .

Oil and natural gas production taxes as a percentage of oil and natural gas sales were 4.63% during 2020 and increased to 4.65% in 2021.

The slight increase was due to higher Texas gas revenue which is taxed at 7.5%.

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 decreased from $43,010,660 in 2020 to $37,167,967 in 2021.

The decrease was the result of an increase in our total reserves and an average decrease of total property cost from the impairment in 2020, resulting in a reduction to our average depreciation, depletion and amortization rate from $13.37 per Boe during 2020 to $11.95 per Boe during 2021.

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

Ceiling Test Write-Down.

The Company did not record a ceiling test write-down during 2021.

The ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve-month period as of December 31, 2021, adjusted for market differentials, per SEC guidelines.

The Company recorded a non-cash write-down of the carrying value of its proved oil and natural gas properties of $277,501,943 for the year ended December 31, 2020 as a result of ceiling test limitations, which was reflected as ceiling test impairments in the accompanying Statements of Operations.

The primary reason for the write-down was a reduction in the oil price used for calculating the reserves from $52.19 in 2019 to $36.04 in 2020.

Asset retirement obligation accretion.

Our asset retirement obligation (“ARO”) accretion decreased from $906,616 in 2020 to $744,045 in 2021.

This was a result of the reduction of ARO liabilities from the sale of certain assets in the first quarter of 2021 and plugging activities conducted throughout the year.

Operating lease expense.

Our operating lease expense decreased from $1,196,372 in 2020 to $523,487 in 2021 due to the month to month leases for office equipment and compressors used in our operations on which we 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 are recorded as short-term lease costs and amounts included in Lease operating expenses.

The Company terminated its Oklahoma lease as of March 31, 2021 and negotiated a reduction to its Midland office lease.

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

General and administrative expenses decreased from $16,874,050 in 2020 to $16,068,105 in 2021.

The decrease was primarily related to a $2,945,839 reduction in share-based compensation, offset by increases in salaries, accounting expenses, and non-recurring costs associated with investor relations.

Interest expense .

Interest expense decreased from $17,617,614 in 2020 to $14,490,474 in 2021.

The decrease was the result of having lower amounts outstanding on our credit facility throughout 2021.

Gain (loss) on derivative contracts.

During 2020, the Company recorded a gain on derivative contracts of $21,366,068.

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

The significant change was due to the rise of crude oil prices during 2021, which was above the fixed price of the contracts.

Deposit forfeiture income .

During 2021, the Company did not earn deposit forfeiture income.

During 2020, the Company received $5,500,000 in non-refundable deposits from the intended buyer regarding the attempted divestiture of the Company’s Delaware assets.

With the cancellation of that agreement, the non-refundable deposits were recognized as income on our Statements of Operations.

Benefit from (Provision for) income taxes .

The benefit from (provision for) income taxes changed from a benefit of $6,001,176 for 2020 to a provision of $90,342 for 2021.

The change was primarily the result of a full valuation allowance on federal taxes in 2021 with only state tax activity recognized.

Net income (loss) .

The Company had a net loss of ($253,411,828) in 2020 compared to net income of $3,322,892 in 2021.

The change in net income (loss) was primarily the result of the ceiling test write-down in 2020.

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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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, extending the maturity date of the facility to August 2026.

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.

The borrowing base is redetermined semi-annually on each May 1 and November 1.

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.

The syndicate was modified to add five lenders, replacing five exiting lenders.

Rather than Eurodollar loans, the reference rate on the Second Amended and Restated Credit Agreement is the Standard Overnight Financing Rate (“SOFR”).

Beginning on the June 30, 2023 financial statements and compliance certification delivery date, the Second Amended and Restated Credit Agreement will allow for the Company to declare dividends for its equity owners, subject to certain limitations.

These limitations include (i) no default or event of default has occurred or will occur upon such payments, (ii) the pro forma Leverage Ratio, as defined in the Second Amended and Restated Credit Agreement, does not exceed 2.00 to 1.00, (iii) the amount of such payments does not exceed Available Free Cash Flow, (iv) the Borrowing Base Utilization Percentage is not greater than 80%, and (v) a Responsible Officer certifies that the other four conditions are satisfied.

Rather than Eurodollar loans, the reference rate on 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 Amended and Restated 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 Amended and Restated Credit Agreement contains certain covenants, which, among other things, require the maintenance of (i) a total 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) 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 Amended and Restated Credit Agreement) of 1.0 to 1.0.

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 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.

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 shall be 0% from such hedge testing date to the next succeeding hedge testing date.

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 shall be 25% from such hedge testing date to the next succeeding hedge testing date.

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

As of December 31, 2022, $415,000,000 was outstanding on the Credit Facility.

The Company is in compliance with all covenants contained in the Second Amended and Restated Credit Agreement as of December 31, 2022.

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.

Equity Offering.

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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, as shown in our Statements of Stockholders' Equity.

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

Of the aforementioned 6,800,000 Common Warrants, all remained outstanding as of December 31, 2021 and 2022.

Of the aforementioned 23,004,300 Common Warrants, 442,600 were exercised and common stock was issued in 2021 and 10,253,907 were exercised and common stock was issued in 2022, as shown in our Statements of Stockholders' Equity.

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 Statements 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.

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.

Historically, our primary sources of cash have been from operations, equity offerings and borrowings on our Credit Facility.

During 2022, 2021, and 2020 we had cash inflow from operations of $197.0 million, $72.7 million, and $72.2 million, respectively.

During the three years ended December 31, 2022, we financed $28.0 million through proceeds from the sale of stock.

During 2022, 2021, and 2020, we had proceeds from drawdowns on our Credit Facility of $636.0 million, $60.2 million, and $26.5 million, respectively.

Historically, primary sources of cash have been from operations, equity offerings and borrowings on the Credit Facility.

During 2023, 2022, and 2021 we had net cash provided by operating activities of $198.2 million, $197.0 million, and $72.7 million, respectively.

During the three years ended December 31, 2023, we financed $20.9 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.

Additionally, during 2022, 2021 and 2020, we used $511.0 million, $83.2 million and $80.0 million, respectively, to reduce the outstanding balance on our Credit Facility.

Additionally, during 2023, 2022 and 2021, we used cash of $215.0 million, $511.0 million and $83.2 million, respectively, to reduce the outstanding balance on our Credit Facility.

As of December 31, 2023, we had cash on hand of $0.3 million and negative working capital of $57.9 million, compared to cash on hand of $3.7 million and negative working capital of $78.6 million as of December 31, 2022 and cash on hand of $2.4 million and negative working capital of $46.9 million as of December 31, 2021.

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The Company maintains a Credit Facility which currently has a $600 million borrowing base.

The outstanding balance on that Credit Facility as of December 31, 2022 is $415.0 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, 2023 was $425.0 million, which will require repayment or refinancing at or prior to maturity in August 2026.

The Company leases office spaces in The Woodlands, Texas and Midland, Texas.

The Woodlands office is under a five-and-a-half-year lease beginning January 15, 2021.

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 Company has financing leases for vehicles with varying maturity dates through October 2025.

Future lease payments through October 2025 aggregate $1,900,595.

The Company has financing leases for vehicles with varying maturity dates through 2026.

Future lease payments for financing leases aggregate $2,006,453.

Subsequent Events

Stronghold acquisition - On February 28, 2023, as discussed in "Note 5 - ACQUISITIONS & DIVESTITURES," the deferred cash consideration of $15.0 million in cash was paid to Stronghold in accordance with terms set forth in the Purchase Agreement for the Stronghold Acquisition.

In addition on March 1, 2023, the holdback amount of approximately $8.3 million which was held in escrow in accordance with the terms set forth in the Purchase Agreement for the Stronghold Acquisition was distributed to Stronghold.

Common stock issued pursuant to warrant exercise - On February 2, 2023, the Company issued 2,517,427 shares of common stock pursuant to the exercise of Common Warrants with an exercise price of $0.80.

Gross and net proceeds were $2,013,942.

On March 1, 2023, the Company issued 2,000,000 shares of common stock pursuant to the exercise of Common Warrants with an exercise price of $0.80.

Gross and net proceeds were $1,600,000.

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

The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry puts extreme pressure on the economic stability and pricing structure within the industry.

The oil and natural gas industry is cyclical and the demand for goods and services of oil field companies, suppliers, and others associated with the industry puts significant pressure on the economic stability and pricing structure within the industry.

Typically, as prices for oil and natural gas increase, so do associated costs.

Material changes in prices impact the current revenue stream, estimates of future reserves, borrowing base calculations of bank loans and the value of properties in purchase and sale transactions.

Material changes in prices impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, and the value of properties in purchase and sale transactions.

Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money, and retain personnel.

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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 customer.

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.

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

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.

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Full Cost Method of Accounting.

We account for our oil and natural gas operations using the full cost method of accounting.

Under this method, all costs (internal or external) associated with property acquisition, exploration and development of oil and gas reserves are capitalized.

Costs capitalized include acquisition costs, geological and geophysical

expenditures, lease rentals on undeveloped properties and cost of drilling and equipping productive and non-productive wells.

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.

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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 2020, the Company recorded a non-cash write-down of the carrying value of the Company’s proved oil and natural gas properties as a result of a ceiling test limitation of approximately $277.5 million, which is reflected with ceiling test and other impairments in the accompanying Statements of Operations.

The Company did not have any write-downs related to the full cost ceiling limitation in 2021 or 2022.

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, 2022, our reserves are based on an SEC average price of $90.15 per Bbl of WTI oil posted and $6.358 per MMBtu Henry Hub natural gas.

As of December 31, 2021, our reserves are based on an SEC average price of $63.04 per Bbl of WTI oil posted and $3.598 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.

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.

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We make changes to depletion rates and impairment calculations in the same period that changes to the reserve estimates are made.

All capitalized costs of oil and natural gas properties, including estimated future costs to develop proved reserves and estimated future costs of site restoration, are amortized on the unit-of-production method using estimates of proved reserves as determined by independent engineers.

All capitalized costs of oil and natural gas properties, including the estimated future costs to develop proved reserves and estimated future costs to plug and abandon wells and costs of site restoration, less the estimated salvage value of equipment associated with the oil and natural gas properties, are amortized on the unit-of-production method using estimates of proved reserves as determined by independent petroleum engineers.

Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined.

Income Taxes.

Deferred income taxes are provided for the difference between the tax basis of assets and liabilities and the carrying amount in our financial statements.

Deferred income taxes are provided on differences between the tax basis of assets and liabilities and their carrying amounts in the financial statements, and tax carryforwards.

This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is settled.

Since our tax returns are filed after the financial

statements are prepared, estimates are required in valuing tax assets and liabilities.

Since our tax returns are filed after the financial statements are prepared, estimates are required in valuing tax assets and liabilities.

We record adjustments to the actual values in the period the Company files its tax returns.

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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.

We also consider the scheduled reversal of deferred tax liabilities and available tax planning strategies.

We also consider the reversal of deferred tax liabilities and available tax planning strategies.

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