Item 7. Management’s Discussion and Analysis
Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our accompanying financial statements and the notes to those financial statements included elsewhere in this Annual Report. The following discussion includes forward-looking statements that reflect our plans, estimates, and beliefs and our actual results could differ materially from those discussed in these forward-looking statements as a result of many factors, including those discussed under “Risk Factors,” "Forward Looking Statements," and elsewhere in this Annual Report.
Overview
Ring Energy, Inc. (the "Company," "Ring," "we," "us," "our" and similar terms) is a growth oriented independent oil and natural gas exploration and production company based in The Woodlands, Texas engaged in oil and natural gas development, production, acquisition, and exploration activities currently focused in the Permian Basin of Texas. Our drilling operations target the oil and liquids rich producing formations in the Northwest Shelf and the Central Basin Platform, in the Permian Basin in Texas.
Business Description and Plan of Operation
The Company is focused on balancing the need to reduce long-term debt and further developing our oil and gas properties to maintain or grow our annual production. We intend to achieve both through proper allocation of cash flow generated by our operations and potentially through the sale of non-core assets. We intend to continue evaluating potential transactions to acquire strategic producing assets with attractive acreage positions that can provide competitive returns for our shareholders.
• Growing production and reserves by developing our oil-rich resource base through conventional and horizontal drilling . In an effort to maximize its value and resources potential, Ring intends to drill and develop its acreage base in both the Northwest Shelf and Central Basin Platform assets, allowing Ring to execute on its plan of operating within its generated cash flow.
• Reduction of long-term debt and deleveraging of asset. Ring intends to reduce its long-term debt primarily through the use of excess cash flow and potentially through the sale of non-core assets. The Company believes that with its attractive field level margins, it is positioned to maximize the value of its assets and deleverage its balance sheet. The Company also believes through potential accretive acquisitions and strategic asset dispositions, it can accelerate the strengthening of its balance sheet. During the three months ended December 31, 2024, the Company made net paydowns of $7 million on its revolving line of credit, resulting in the outstanding long-term debt balance of $385 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.
2024 Developments and Highlights
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
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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.
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Quarter Area Wells Drilled Wells Completed Drilled Uncompleted ("DUC") (2)
1Q 2024 Northwest Shelf (Horizontal) 2 2 —
Central Basin Platform (Horizontal) 3 3 —
Central Basin Platform (Vertical) 6 6 —
Total (1)
11 11 —
2Q 2024 Northwest Shelf (Horizontal) — — —
Central Basin Platform (Horizontal) 5 5 —
Central Basin Platform (Vertical) 6 6 —
Total 11 11 —
3Q 2024 Northwest Shelf (Horizontal) 3 3 —
Central Basin Platform (Horizontal) 4 2 2
Central Basin Platform (Vertical) 6 6 —
Total 13 11 2
4Q 2024 Northwest Shelf (Horizontal) — — —
Central Basin Platform (Horizontal) 5 6 1
Central Basin Platform (Vertical) 4 4 —
Total 9 10 1
FY 2024
Northwest Shelf (Horizontal) 5 5 —
Central Basin Platform (Horizontal) 17 16 1
Central Basin Platform (Vertical) 22 22 —
Total (1)
44 43 1
(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
Our financial results depend on many factors, particularly the price of crude oil and natural gas and our ability to market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand both domestically and world wide, which are impacted by many factors. As a result, we cannot accurately predict future commodity prices, and therefore, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our drilling program, production volumes, or revenues.
Average oil and natural gas prices received through 2024 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
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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
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.
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Results of Operations
The following table sets forth selected operating data for the periods indicated:
For the years ended December 31, 2024 2023 2022
Net production:
Oil (Bbls) 4,861,628 4,579,942 3,459,840
Natural gas (Mcf) 6,423,674 6,339,158 4,088,642
Natural gas liquids (Bbls) 1,258,814 976,852 371,329
Net sales:
Oil $ 363,971,394 $ 349,044,863 $ 321,062,672
Natural gas (9,265,335) 334,175 18,693,631
Natural gas liquids 11,621,355 11,676,963 7,493,234
Average sales price:
Oil (per Bbl) $ 74.87 $ 76.21 $ 92.80
Natural gas (per Mcf) (1.44) 0.05 4.57
Natural gas liquids (Bbl) 9.23 11.95 20.18
Production costs and expenses:
Lease operating expenses $ 78,310,949 $ 70,158,227 $ 47,695,351
Gathering, transportation and processing costs 506,333 457,573 1,830,024
Ad valorem taxes 8,069,064 6,757,841 4,670,617
Oil and natural gas production taxes 16,116,565 18,135,336 17,125,982
Other costs and operating expenses:
Depreciation, depletion and amortization $ 98,702,843 $ 88,610,291 $ 55,740,767
Asset retirement obligation accretion 1,380,298 1,425,686 983,432
Operating lease expense 700,362 541,801 363,908
General and administrative expense ("G&A")
29,640,300 29,188,755 27,095,323
Share-based compensation 5,506,017 8,833,425 7,162,231
G&A excluding share-based compensation
24,134,283 20,355,330 19,933,092
Other income (expense):
Interest income $ 491,946 $ 257,155 $ 4
Interest (expense) (43,311,810) (43,926,732) (23,167,729)
Gain (loss) on derivative contracts (2,365,917) 2,767,162 (21,532,659)
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)
Year Ended December 31, 2024 Compared to Year Ended December 31, 2023
Oil sales . Oil sales increased approximately $14.9 million to $364.0 million in 2024 from $349.0 million in 2023. The oil sales increased by a volume variance of approximately $21.5 million from an increase in sales volumes to 4,861,628 barrels of oil in 2024 from 4,579,942 barrels of oil in 2023, primarily driven by production from wells within the
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assets acquired with the Founders Acquisition (closed in August 2023). Other impacts to revenue volumes include organic growth from workovers, new drills, and other capital expenditures, offset by divestitures completed and natural asset decline. The volume variance was offset by a negative price variance of approximately $(6.5) million from a decrease in the average realized per barrel oil price to $74.87 in 2024 from $76.21 in 2023.
Natural gas sales. Natural gas sales decreased approximately $9.6 million to $(9.3) million in 2024 from $0.3 million in 2023. The natural gas sales decreased by a negative price variance of approximately $(9.6) million, as the average realized per Mcf gas price decreased to $(1.44) in 2024 from $0.05 in 2023. The significant reduction in realized natural gas prices was driven by a lower market index price. In 2024, the average gross realized price for natural gas was $0.29 per Mcf, and the average fees per Mcf were $(1.73), bringing the net average price to $(1.44) per Mcf. In 2023, the average gross realized price for natural gas was $1.67 per Mcf, and the average fees per Mcf were $(1.62), bringing the net average price to 0.05 per Mcf. This was only slightly offset by the volume variance as the volume increased to 6,423,674 Mcf in 2024 from 6,339,158 Mcf in 2023.
NGL sales. NGL sales decreased approximately $0.1 million to $11.6 million in 2024 from $11.7 million in 2023. NGL sales had a volume variance of approximately $3.4 million, as volumes were 1,258,814 barrels of NGLs in 2024 compared to 976,852 barrels in 2023, with 36% of the increase in barrels due to the assets acquired in the Founders Acquisition in 2023. Offsetting this increase to sales was a negative price variance of approximately $(3.4) million, as the average realized price per barrel of NGLs was $9.23 in 2024 compared to $11.95 in 2023. This was due to a reduction in the gross realized price per NGL barrel to $20.00 in 2024 compared to $21.16 in 2023 coupled with a growth in the average fees per barrel to $(10.77) in 2024 compared to $(9.20) in 2023.
Lease operating expenses. Our total lease operating expenses (“LOE”) increased approximately $8.1 million to $78.3 million in 2024 from $70.2 million in 2023 and increased slightly on a Boe basis to $10.89 in 2024 from $10.61 in 2023. These per Boe amounts are calculated by dividing our total LOE by our total volume sold, in Boe. LOE increased due to the full year of expenses from the assets acquired with the Founders Acquisition (closed in August 2023) which contributed to a 9% increase in production of 577,733 Boe 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.
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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.
Net income . The Company achieved net income of $67,470,314 in 2024 compared to net income of $104,864,641 in 2023. The decrease in income associated with operations was due to increased LOE costs, ad valorem taxes, and depletion, depreciation, and amortization costs. This was offset by increased oil sales and also lower production taxes as a result of prior period refunds. A change in derivatives position from gain to loss further caused the reduction of net income. The 2024 income tax provision was a significant change from year to year impacting the overall decrease in net income realized by the Company.
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Year Ended December 31, 2023 Compared to Year Ended December 31, 2022
Oil sales . Oil sales increased approximately $28.0 million to $349.0 million in 2023 from $321.1 million in 2022. The oil sales increased by a volume variance of approximately $103.9 million from a significant increase in sales volumes to 4,579,942 barrels of oil in 2023 from 3,459,840 barrels of oil in 2022, with approximately 19% of the increase in oil volumes related to the Founders Acquisition. Other impacts to revenue volumes include organic growth from workovers, new drills, and other capital expenditures, offset by divestitures completed. The volume variance was offset by a negative price variance of approximately $76.0 million from a decrease in the average realized per barrel oil price to $76.21 in 2023 from $92.80 in 2022.
Natural gas sales. Natural gas sales decreased approximately $18.4 million to $0.3 million in 2023 from $18.7 million in 2022. The natural gas sales decreased by a negative price variance of approximately $28.6 million, as the average realized per Mcf gas price decreased to $0.05 in 2023 from $4.57 in 2022. The significant reduction in realized natural gas prices was driven by a lower market index price. In 2023, the average gross realized price for natural gas was $1.67 per Mcf, and the average fees per Mcf were $(1.62), bringing the net average price to $0.05 per Mcf. In 2022, the average gross realized price for natural gas was $6.32 per Mcf, and the average fees per Mcf were $(1.75), bringing the net average price to $4.57 per Mcf. This was partially offset by a volume variance of approximately $10.3 million as the volume increased to 6,339,158 Mcf in 2023 from 4,088,642 Mcf in 2022.
NGL sales. NGL sales increased approximately $4.2 million to $11.7 million in 2023 from $7.5 million in 2022. NGL sales had a volume variance of approximately $12.2 million, as volumes were 976,852 barrels of NGLs in 2023 compared to 371,329 barrels in 2022. The volumes increase was primarily due to the Company's change in reporting presentation for its natural gas productions, which were presented on a three-stream basis basis beginning July 1, 2022. Offsetting this increase to sales was a negative price variance of approximately $8.0 million, as the average realized price per barrel of NGLs was $11.95 in 2023 compared to $20.18 in 2022.
Lease operating expenses. Our total lease operating expenses (“LOE”) increased approximately $22.5 million to $70.2 million in 2023 from $47.7 million in 2022 and increased slightly on a Boe basis to $10.61 in 2023 from $10.57 in 2022. These per Boe amounts are calculated by dividing our total LOE by our total volume sold, in Boe. LOE increased primarily due to a 47% increase in production of 2,100,711 Boe year-over-year. Specifically, the following cost increases accounted for the majority of the increase in LOE: $7.5 million in LOE workover costs, $4.2 million in salaries and wages, $2.5 million in electrical/utilities costs, $1.6 million in equipment rental/services $1.3 million in supplies/materials, $1.2 million in contract services, and $1.0 million in chemicals/treating costs.
Gathering, transportation and processing costs. Our total GTP costs decreased by $1,372,451 to $457,573 in 2023 from $1,830,024 in 2022 and decreased slightly on a Boe basis to $0.07 in 2023 from $0.41 in 2022. In May 2022, a contract update with one of our largest natural gas processors altered the point of control of gas resulting in a change to the recording of those fees from expense to a netted reduction to revenues. There remains only one contract with a natural gas processing entity in place where point of control of gas dictates requiring the fees be recorded as an expense.
Ad valorem taxes. Our total ad valorem taxes increased approximately $2.1 million to $6.8 million in 2023 from $4.7 million in 2022 and decreased on a Boe basis to $1.02 in 2023 from $1.04 in 2022. Ad valorem taxes increased due to a full year of taxes for the properties within counties acquired in the Stronghold Acquisition (i.e. Crane County) as well as a partial year of taxes for properties within Ector County, acquired in the Founders Acquisition. Additional increases were primarily in Yoakum County and Andrews County.
Oil and natural gas production taxes . Oil and natural gas production taxes as a percentage of oil and natural gas sales increased to 5.02% in 2023 from 4.93% during 2022. Overall, the percentage was consistent year over year.
Depreciation, depletion and amortization . Our depreciation, depletion and amortization expense increased approximately $32.9 million to $88.6 million in 2023 from $55.7 million in 2022 due to an increase in our total estimated costs of property, resulting in a higher depletion expense per unit, as well as an increase of 2,100,711 in Boe produced. Our average depreciation, depletion and amortization per Boe increased to $13.40 per Boe during 2023 from $12.35 per Boe during 2022.
Asset retirement obligation accretion. Our asset retirement obligation (“ARO”) accretion increased by $442,254 to $1,425,686 in 2023 from $983,432 in 2022. This was due to a full year of accretion on the assets acquired in the
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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.
Net income . The Company achieved net income of $104,864,641 in 2023 compared to net income of $138,635,025 in 2022 compared. The decrease in net income was due to increased LOE costs, depletion, depreciation, and amortization costs, and interest expense and lower natural gas revenues. This was offset by increased oil and NGL revenues in addition to a more favorable derivative contract portfolio in comparison with the year-end commodity futures prices.
Liquidity and Capital Resources
Financing of Operations. We have historically funded our operations through cash available from operations and from equity offerings of our stock. Our primary source of cash in 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 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.
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Credit Facility. On July 1, 2014, the Company entered into a Credit Agreement with SunTrust Bank (now Truist Bank), as lender, issuing bank and administrative agent for several banks and other financial institutions and lenders (the “Administrative Agent”), (which was amended several times) that provided for a maximum borrowing base of $1 billion with security consisting of substantially all of the assets of the Company. In April 2019, the Company amended and restated the Credit Agreement with the Administrative Agent (as amended and restated, the “Amended Credit Facility”).
On August 31, 2022, the Company modified its Amended Credit Facility through that certain Second Amended and Restated Credit Agreement (the "Second Credit Agreement"), extending the maturity date of the facility to August 2026 and the syndicate was modified to add five lenders, replacing five lenders. On February 12, 2024, the Company, Truist Bank as the Administrative Agent and Issuing Bank, and the lenders party thereto (the "Lenders") entered into an amendment (the "Amendment") to the Second Credit Agreement. Among other things, the Amendment amends the definition of Free Cash Flow so amounts used by the Company for acquisitions will no longer be subtracted from the calculation of Free Cash Flow.
The Second Credit Agreement has a borrowing base of $600 million, which is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time. The borrowing base is redetermined semi-annually each May and November. The borrowing base is subject to reduction in certain circumstances such as the sale or disposition of certain oil and gas properties of the Company and cancellation of certain hedging positions.
Rather than Eurodollar loans, the reference rate in the Second Credit Agreement is the SOFR. Also, the Second Credit Agreement permits the Company to declare dividends for its equity owners, subject to certain limitations, including (i) no default or event of default has occurred or will occur upon such payments, (ii) the pro forma Leverage Ratio (outstanding debt to adjusted earnings before interest, taxes, depreciation and amortization, exploration expenses, and all other non-cash charges acceptable to the Administrative Agent) does not exceed 2.00 to 1.00, (iii) the amount of such payments does not exceed Available Free Cash Flow (as defined in the Second Credit Agreement), and (iv) the Borrowing Base Utilization Percentage (as defined in the Second Credit Agreement) is not greater than 80%.
The interest rate on each SOFR Loan will be the adjusted term SOFR for the applicable interest period plus a margin between 3.0% and 4.0% (depending on the then-current level of borrowing base usage). The annual interest rate on each base rate loan is (a) the greatest of (i) the Administrative Agent’s prime lending rate, (ii) the Federal Funds Rate (as defined in the Second Credit Agreement) plus 0.5% per annum, (iii) the adjusted term SOFR determined on a daily basis for an interest period of one month, plus 1.00% per annum and (iv) 0.00% per annum, plus (b) a margin between 2.0% and 3.0% per annum (depending on the then-current level of borrowing base usage).
The Second Credit Agreement contains certain covenants, which, among other things, require the maintenance of (i) a total Leverage Ratio of not more than 3.0 to 1.0 and (ii) a minimum ratio of Current Assets to Current Liabilities (as such terms are defined in the Second Credit Agreement) of 1.0 to 1.0. The Second Credit Agreement also contains other customary affirmative and negative covenants and events of default. The Company is required to maintain on a rolling 24 months basis, hedging transactions in respect of crude oil and natural gas, on not less than 50% of the projected production from its proved, developed, and producing oil and gas. However, if the borrowing base utilization is less than 25% at the hedge testing date and the Leverage Ratio is not greater than 1.25 to 1.00, the required hedging percentage for months 13 through 24 of the rolling 24 month period provided for will be 0% from such hedge testing date to the next succeeding hedge testing date and if the borrowing base utilization percentage is equal to or greater than 25%, but less than 50% and the Leverage Ratio is not greater than 1.25 to 1.00, the required hedging percentage for months 13 through 24 of the rolling 24 month period provided for will be 25% from such hedge testing date to the next succeeding hedge testing date.
As of December 31, 2024, $385 million was outstanding on the Credit Facility and the Company was in compliance with all covenants in the Second Credit Agreement.
Equity Offering. In October 2020, the Company closed on an underwritten public offering of (i) 9,575,800 Common Shares, (ii) 13,428,500 Pre-Funded Warrants and (iii) 23,004,300 Common Warrants at a combined purchase price of $0.70. This includes a partial exercise of the over-allotment. The Common Warrants have a term of five years and an exercise price of $0.80 per share. Gross proceeds totaled $16,089,582.
Concurrently with the underwritten public offering, the Company closed on a registered direct offering of (i) 3,500,000 Common Shares, (ii) 3,300,000 Pre-Funded Warrants and (iii) 6,800,000 Common Warrants at a combined
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purchase price of $0.70. The Common Warrants have a term of five years and an exercise price of $0.80 per share. Gross proceeds totaled $4,756,700.
Total gross proceeds from the 2020 underwritten public offering and the registered direct offering aggregated $20,846,282. Total net proceeds for the Common Warrants exercised in 2020 aggregated $19,379,832.
The Common Shares of 9,575,800 and 3,500,000 were issued in 2020. The Pre-Funded Warrants of 3,300,000 were exercised and common stock was issued in 2020. The Pre-Funded Warrants of 13,428,500 were exercised and common stock was issued in 2021, as shown in our Statement of Stockholders' Equity. Of the aforementioned 23,004,300 Common Warrants, 442,600 were exercised and common stock was issued in 2021; 10,253,907 were exercised and common stock was issued in 2022; and 19,029,593 were exercised and common stock was issued in 2023 (4,517,427 exercised at $0.80 and 14,512,166 exercised at $0.62 - refer to NOTE 11 — STOCKHOLDERS' EQUITY), and no Common Warrants were exercised during 2024; as shown in our Statement of Stockholders' Equity.
Issuance of Common Stock and Convertible Preferred Stock for Stronghold Acquisition. As part of the consideration for the Stronghold Acquisition, on August 31, 2022 the Company issued 21,339,986 shares of common stock and 153,176 shares of newly created Series A Convertible Preferred Stock, which was converted into 42,548,892 shares of common stock on October 27, 2022.
Cash Flows. Historically, primary sources of cash have been from operations, equity offerings and borrowings on the Credit Facility. During 2024, 2023, and 2022 we had net cash provided by operating activities of $194.4 million, $198.2 million, and $197.0 million, respectively. During the three years ended December 31, 2024, we financed $20.5 million through proceeds from the sale of common stock. During 2024, 2023, and 2022, the Company had a net repayment of $40.0 million, a net draw of $10.0 million, and a net draw of $125.0 million on the Credit Facility, respectively. 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. As of December 31, 2024, we had cash on hand of $1.9 million and negative working capital of $54.6 million, compared to cash on hand of $0.3 million and negative working capital of $57.9 million as of December 31, 2023 and cash on hand of $3.7 million and negative working capital of $78.6 million as of December 31, 2022.
Contractual Obligations. 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, 2024 was $385 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 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 2027. Future lease payments for financing leases aggregate $1,667,763.
Effects of Inflation and Pricing
The oil and natural gas industry is cyclical and the demand for goods and services of oil field companies, suppliers, and others associated with the industry puts significant pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do associated costs. Material changes in prices impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, and the value of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money, and retain personnel. We anticipate business costs will vary in accordance with commodity prices for oil and natural gas, and the associated increase or decrease in demand for services related to production and exploration.
Off-Balance Sheet Financing Arrangements
As of December 31, 2024, we had no off-balance sheet financing arrangements.
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Critical Accounting Policies and Estimates
Our discussion of financial condition and results of operations is based upon the information reported in our financial statements. The preparation of these statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, weather, politics, global economics, mechanical problems, general business conditions, and other factors. Our significant accounting policies, as well as considerations of recent accounting pronouncements, are detailed in "NOTE 1 — ORGANIZATION, BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES" to our financial statements included in this Annual Report. We have outlined below certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management.
Oil and Natural Gas Reserve Quantities. Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. Reserve quantities and future cash flows included in this Annual Report are prepared in accordance with guidelines established by the SEC and FASB. The accuracy of our reserve estimates is a function of:
• the quality and quantity of available data;
• the interpretation of that data;
• the accuracy of various mandated economic assumptions; and
• the judgments of the persons preparing the estimates.
Our proved reserve information included in this Annual Report was prepared and determined by Cawley, Gillespie & Associates, Inc., independent petroleum engineers. Because these estimates depend on many assumptions, all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered. We continually make revisions to reserve estimates throughout the year as additional properties are acquired. We make changes to depletion rates and impairment calculations in the same period that changes to the reserve estimates are made.
All capitalized costs of oil and natural gas properties, including the estimated future costs to develop proved reserves and estimated future costs to plug and abandon wells and costs of site restoration, less the estimated salvage value of equipment associated with the oil and natural gas properties, are amortized on the unit-of-production method using estimates of proved reserves as determined by independent petroleum engineers. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined.
Ceiling Test of Oil and Natural Gas Properties . Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly utilizing the average of prices in effect on the first day of the month for the preceding twelve-month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10%, plus the lower of cost or market value of unproved properties, less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depletion, depreciation and amortization (“DD&A”) rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling.
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,
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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. Deferred income taxes are provided on differences between the tax basis of assets and liabilities and their carrying amounts in the financial statements, and tax carryforwards. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is settled. Since our tax returns are filed after the financial statements are prepared, estimates are required in valuing tax assets and liabilities. We record adjustments to the actual values in the period the Company files its tax returns.
In assessing the Company's deferred tax assets, we consider whether a valuation allowance should be recorded for some or all of the deferred tax assets which may not be realized. The ultimate realization of deferred tax assets is assessed at each reporting period and is dependent upon the generation of future taxable income and the Company's ability to utilize net operating loss carryforwards during the periods in which the temporary differences become deductible. We also consider the reversal of deferred tax liabilities and available tax planning strategies. As of December 31, 2024 and 2023, the Company did not carry a valuation allowance against its federal and state deferred tax assets.