What changed in PRIMEENERGY RESOURCES CORP's 10-K — 2023 vs 2024
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Paragraph-level year-over-year comparison of PRIMEENERGY RESOURCES CORP's 2023 and 2024 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2024 report.
+45 added−246 removedSource: 10-K (2025-04-15) vs 10-K (2024-04-15)
Top changes in PRIMEENERGY RESOURCES CORP's 2024 10-K
45 paragraphs added · 246 removed · 29 edited across 1 sections
- Item 7. Management's Discussion & Analysis+45 / −246 · 29 edited
Item 7. Management's Discussion & Analysis
Management's Discussion & Analysis (MD&A) — revenue / margin commentary
29 edited+16 added−217 removed28 unchanged
Item 7. Management's Discussion & Analysis
Management's Discussion & Analysis (MD&A) — revenue / margin commentary
29 edited+16 added−217 removed28 unchanged
2023 filing
2024 filing
Biggest changeThe following table summarizes the results of our derivative instruments for the years ended December 2023 and 2022: Years ended December 31, 2023 2022 Oil derivatives - realized gains (losses) $ 179 $ (12,101 ) Oil derivatives – unrealized gains -- 3,713 Total gains (losses) on oil derivatives $ 179 $ (8,388 ) Natural gas derivatives – realized gains (losses) 235 (4,543 ) Natural gas derivatives – unrealized gains -- 892 Total gains (losses) on natural gas derivatives $ 235 $ (3,651 ) Total gains (losses) on oil and natural gas $ 414 $ (12,039 ) 39 Prices received for the years ended December 31, 2023 and 2022, respectively, including the impact of derivatives were: 2023 2022 Increase / (Decrease) Increase / (Decrease) Oil Price $ 76.33 $ 87.77 $ (11.44 ) (13.03 )% Gas Price $ 1.93 $ 4.44 $ (2.51 ) (56.53 )% NGL Price $ 19.64 $ 35.70 $ (16.06 ) (44.99 )% Oil and gas production expense increased $1.0 million, or 4.0% to 3.11% for the year ended December 31, 2023 from $31.7 million for the year ended December 31, 2022.
Biggest changeAs oil and natural gas prices remain volatile, mark-to-market accounting treatment creates volatility in our revenues. 40 The following table summarizes the results of our derivative instruments for the years ended December 2024 and 2023: Years ended December 31, 2024 2023 Oil derivatives - realized gains (losses) $ 0 $ 179 Oil derivatives – unrealized gains 0 -- Total gains (losses) on oil derivatives $ 0 $ 179 Natural gas derivatives – realized gains (losses) 0 235 Natural gas derivatives – unrealized gains 0 -- Total gains (losses) on natural gas derivatives $ 0 $ 235 Total gains (losses) on oil and natural gas $ 0 $ 414 Prices received for the years ended December 31, 2024 and 2023, respectively, including the impact of derivatives were: 2024 2023 Increase / (Decrease) Increase / (Decrease) Oil Price $ 75.80 $ 76.33 $ (0.53 ) (0.69 )% Gas Price $ 0.43 $ 1.93 $ (1.50 ) (77.72 )% NGL Price $ 20.25 $ 19.64 $ 0.61 3.11 % Oil and gas production expense increased $15.8 million, or 49.6% to $47.7 million for the year ended December 31, 2024 from $31.9 million for the year ended December 31, 2023.
For 2024, we will continue our focus on preserving financial flexibility and liquidity as we manage the risks facing our industry. Our 2024 capital budget is reflective of commodity prices and has been established based on an expectation of available cash flows, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility.
For 2025, we will continue our focus on preserving financial flexibility and liquidity as we manage the risks facing our industry. Our 2025 capital budget is reflective of commodity prices and has been established based on an expectation of available cash flows, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility.
The following table summarizes the primary components of production volumes and average sales prices realized for the years ended December 31, 2023 and 2022 (excluding realized gains and losses from derivatives).
The following table summarizes the primary components of production volumes and average sales prices realized for the years ended December 31, 2024 and 2023 (excluding realized gains and losses from derivatives).
The next borrowing base review is scheduled for May 2024. Our oil and gas properties are pledged as collateral for the line of credit and we are subject to certain financial and operational covenants defined in the agreement. We are currently in compliance with these covenants and expect to be in compliance over the next twelve months.
The next borrowing base review is scheduled for June 2025. Our oil and gas properties are pledged as collateral for the line of credit and we are subject to certain financial and operational covenants defined in the agreement. We are currently in compliance with these covenants and expect to be in compliance over the next twelve months.
Net cash provided by operating activities for the year ended December 31, 2023 was $109.0 million compared to $33.1 million in the prior year. Excluding the effects of significant unforeseen expenses or other income, our cash flow from operations fluctuates primarily because of variations in oil and gas production and prices or changes in working capital accounts.
Net cash provided by operating activities for the year ended December 31, 2024, was $115.9 million compared to $109.0 million in the prior year. Excluding the effects of significant unforeseen expenses or other income, our cash flow from operations fluctuates primarily because of variations in oil and gas production and prices or changes in working capital accounts.
As we have done historically to preserve or enhance liquidity, we may adjust our capital program throughout the year, divest assets, or enter into strategic joint ventures. 37 The Company maintains a Credit Agreement with a maturity date of June 1, 2026, providing for a credit facility totaling $300 million, with a borrowing base of $85 million.
As we have done historically to preserve or enhance liquidity, we may adjust our capital program throughout the year, divest assets, or enter into strategic joint ventures. 38 The Company maintains a Credit Agreement with a maturity date of December 20, 2028, providing for a credit facility totaling $300 million, with a borrowing base of $115 million.
The credit agreement requires that as of the last day of any fiscal quarter, if the borrowing base utilization percentage on such a date is less than the 15%, then the borrower shall not be required to enter into any swap agreements. As of the quarter ended December 31, 2023, the Company had no outstanding borrowings.
The credit agreement requires that as of the last day of any fiscal quarter, if the borrowing base utilization percentage on such a date is less than 15%, then the borrower shall not be required to enter into any swap agreements.
The liability is offset by a corresponding increase in the underlying asset. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company’s oil and gas properties. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations.
The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company’s oil and gas properties. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations.
As of March 31, 2024, the Company had $4 million in outstanding borrowings and $81 million in availability under this facility. The bank reviews the borrowing base semi-annually and, at its discretion, may decrease or propose an increase to the borrowing base relative to a re-determined estimate of proved oil and gas reserves.
As of April 8, 2025, the Company had $17.5 million in outstanding borrowings and $97.5 million in availability under this facility. The bank reviews the borrowing base semi-annually and, at its discretion, may decrease or propose an increase to the borrowing base relative to a re-determined estimate of proved oil and gas reserves.
These changes reflect the cost savings related to wells that have been plugged offset by rising service costs and additional costs related to the new wells that have been placed on production. Field service income increased $2.4 million or 18.5% to $15.4 million for the year ended December 31, 2023 from $13.0 million for the year ended December 31, 2022.
These changes reflect the cost savings related to wells that have been plugged offset by rising service costs and additional costs related to the new wells that have been placed on production. Field service income decreased $4.5 million or 29.5% to $10.9 million for the year ended December 31, 2024 from $15.4 million for the year ended December 31, 2023.
The Company has a stock repurchase program in place, spending under this program in 2023 and 2022 was $7.5 million and $7.4 million, respectively.
The Company has a stock repurchase program in place, spending under this program in 2024 and 2023 was $13.4 million and $7.5 million, respectively. The Company expects continued spending under the stock repurchase program in 2025.
The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.
The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time.
Our natural gas production increased by 802 MMcf, or 24.12% to 4,127 MMcf for the year ended December 31, 2023 from 3,325 MMcf for the year ended December 31, 2022. The changes in crude oil, NGL and natural gas production volumes are a result of new wells placed in production offset by the natural decline of existing properties.
Our natural gas production increased by 3,639 MMcf, or 88.18% 7,766 MMcf for the year ended December 31, 2024 from 4,127 MMcf for the year ended December 31, 2023. The changes in crude oil, NGL and natural gas production volumes are a result of new wells placed in production offset by the natural decline of existing properties.
Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations. ARO associated with retiring tangible long-lived assets is recognized as a liability in the period in which the legal obligation is incurred and becomes determinable.
Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations. ARO associated with retiring tangible long-lived assets is recognized as a liability in the period in which the legal obligation is incurred and becomes determinable. The liability is offset by a corresponding increase in the underlying asset.
Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account. Asset Retirement Obligation (ARO ) : The Company has significant obligations to remove tangible equipment and restore land at the end of oil and gas production operations. The Company’s removal and restoration obligations are primarily associated with plugging and abandoning wells.
Asset Retirement Obligation (ARO ) : The Company has significant obligations to remove tangible equipment and restore land at the end of oil and gas production operations. The Company’s removal and restoration obligations are primarily associated with plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments.
The significant components of income and expense are discussed below. Oil, NGL and gas sales decreased $16.4 million, or 13.19% to $107.7 million for the year ended December 31, 2023 from $124.1 million for the year ended December 31, 2022. Crude oil, NGL and natural gas sales vary due to changes in volumes of production sold and realized commodity prices.
Oil, NGL and gas sales increased $115 million, or 107.01% to $223.1 million for the year ended December 31, 2024 from $107.7 million for the year ended December 31, 2023. Crude oil, NGL and natural gas sales vary due to changes in volumes of production sold and realized commodity prices.
This decrease reflects the increase in rates combined with reduced borrowings under our revolving credit agreement Tax expense of $6.1 million and $10.3 million were recorded for the years ended December 31, 2023 and 2022, respectively. The change in our income tax provision was primarily due to the decrease in pre-tax income for the year ended December 31, 2023.
Tax expense of $15.8 million and $6.1 million were recorded for the years ended December 31, 2024 and 2023, respectively. The change in our income tax provision was primarily due to the increase in pre-tax income for the year ended December 31, 2024.
Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. 36 Depreciation, Depletion and Amortization for Oil and Gas Properties The quantities of estimated proved oil and gas reserves are a significant component of our calculation of depletion expense and revisions in such estimates may alter the rate of future expense.
Depreciation, Depletion and Amortization for Oil and Gas Properties The quantities of estimated proved oil and gas reserves are a significant component of our calculation of depletion expense and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserves were revised upward or downward, earnings would increase or decrease respectively.
Accordingly, the Company had no swap agreements in place for oil and natural gas. The Company’s activities include development and exploratory drilling. Our strategy is to develop a balanced portfolio of drilling prospects that includes lower risk wells with a high probability of success and higher risk wells with greater economic potential.
Our strategy is to develop a balanced portfolio of drilling prospects that includes lower-risk wells with a high probability of success and higher-risk wells with greater economic potential.
The Company expects continued spending under the stock repurchase program in 2024. 38 Results of Operations 2023 and 2022 Compared We reported a net income of $28.1 million for 2023, or $15.19 per share, compared to $48.7 million, or $24.91 per share for 2022. The current year net income reflects production increases offset by commodity price decreases.
Results of Operations 2024 and 2023 Compared We reported a net income of $55.4 million for 2024, or $31.43 per share, compared to $28.1 million, or $15.19 per share for 2023. The current year net income reflects production increases offset by commodity price decreases. The significant components of income and expense are discussed below.
The reserve base used to calculate depletion, depreciation or amortization is the sum of proved developed reserves and proved undeveloped reserves for leasehold acquisition costs and the cost to acquire proved properties. The reserve base includes only proved developed reserves for lease and well equipment costs, which include development costs and successful exploration drilling costs.
Depreciation, depletion and amortization of the cost of proved oil and gas properties are calculated using the unit-of-production method. The reserve base used to calculate depletion, depreciation or amortization is the sum of proved developed reserves and proved undeveloped reserves for leasehold acquisition costs and the cost to acquire proved properties.
Index prices for oil, natural gas, and NGLs have improved since the lows of 2020 however we expect prices to remain volatile and consequently cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital program, production volumes or revenues.
Index prices for oil, natural gas, and NGLs have been volatile in recent years and consequently cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital program, production volumes or revenues. 37 Critical Accounting Estimates: Proved Oil and Gas Reserves Proved oil and gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization.
Years ended December 31, Increase / Increase / 2023 2022 (Decrease) (Decrease) Barrels of Oil Produced 1,144,000 939,000 205,000 21.83 % Average Price Received $ 76.84 $ 96.70 $ (19.86 ) (20.54 )% Oil Revenue (In 000’s) $ 87,906 $ 90,803 $ (2,897 ) (3.19 )% Mcf of Gas Sold 4,127,000 3,325,000 802,000 24.12 % Average Price Received $ 1.92 $ 5.54 $ (3.62 ) (65.34 )% Gas Revenue (In 000’s) $ 7,935 $ 18,428 $ (10,493 ) (56.94 )% Barrels of Natural Gas Liquids Sold 606,000 417,000 189,000 45.32 % Average Price Received $ 19.64 $ 35.70 $ (16.06 ) (44.99 )% Natural Gas Liquids Revenue (In 000’s) $ 11,901 $ 14,887 $ (2,986 ) (20.06 )% Total Oil & Gas Revenue (In 000’s) $ 107,742 $ 124,118 $ (16,376 ) (13.19 )% Oil, Natural Gas and NGL Derivatives We do not apply hedge accounting to any of our commodity based derivatives, thus changes in the fair market value of commodity contracts held at the end of a reported period, referred to as mark-to-market adjustments, are recognized as unrealized gains and losses in the accompanying condensed consolidated statements of operations.
Years ended December 31, Increase / Increase / 2024 2023 (Decrease) (Decrease) Barrels of Oil Produced 2,556,000 1,144,000 1,412,000 123.43 % Average Price Received $ 75.80 $ 76.84 $ (1.04 ) (1.35 )% Oil Revenue (In 000’s) $ 193,737 $ 87,906 $ 105,831 120.39 % Mcf of Gas Sold 7,766,000 4,127,000 3,639,000 88.18 % Average Price Received $ 0.43 $ 1.92 $ (1.49 ) (77.60 )% Gas Revenue (In 000’s) $ 3,309 $ 7,935 $ (4,626 ) (58.30 )% Barrels of Natural Gas Liquids Sold 1,284,000 606,000 678,000 111.88 % Average Price Received $ 20.25 $ 19.64 $ 0.61 3.11 % Natural Gas Liquids Revenue (In 000’s) $ 25,996 $ 11,901 $ 14,095 118.44 % Total Oil & Gas Revenue (In 000’s) $ 223,042 $ 107,742 $ 115,300 107.01 % Oil, Natural Gas and NGL Derivatives We do not apply hedge accounting to any of our commodity based derivatives, thus changes in the fair market value of commodity contracts held at the end of a reported period, referred to as mark-to-market adjustments, are recognized as unrealized gains and losses in the accompanying condensed consolidated statements of operations.
Our realized prices at the well head decreased an average of $19.86 per barrel, or 20.54% on crude oil, decreased an average of $16.06 per barrel, or 44.99% on NGL and decreased $3.62 per Mcf, or 65.34% on natural gas during 2023 as compared to 2022.
Our realized prices at the well head decreased an average of $1.04 per barrel, or 1.35% on crude oil, increased an average of $0.61 per barrel, or 3.11% on NGL and decreased $1.49 per Mcf, or 77.6% on natural gas during 2024 as compared to 2023.
Our crude oil production increased by 205,000 barrels, or 21.83% to 1,144,000 barrels for the year ended December 31, 2023 from 939,000 barrels for the year ended December 31, 2022. Our NGL production increased by 189,000 or 45.32% to 606,000 for the year ended December 31, 2023 from 417,000 barrels for the year ended December 31, 2022.
Our crude oil production increased by 1,412,000 barrels, or 123.43% to 2,556,000 barrels for the year ended December 31, 2024 from 1,144,000 barrels for the year ended December 31, 2023. Our NGL production increased by 678,000 or 111.88% to 1,284,000 for the year ended December 31, 2024 from 606,000 barrels for the year ended December 31, 2023.
These changes are primarily related to employee compensation and benefits. Gain on sale and exchange of assets of $8.9 million for the year ended December 31, 2023 consists of sales of net mineral and surface acres in various locations in Texas and Oklahoma.
Gain on sale and exchange of assets of $3.7 million for the year ended December 31, 2024 consists of sales of net mineral and surface acres in various locations in Texas and Oklahoma as well as the sale of our South Texas oilfield service company, Eastern Oil Well Service.
Field service expenses primarily consist of wages and vehicle operating expenses. The changes reflect the variance in equipment utilization during the periods represented. Depreciation, depletion, and amortization increased $3.6 million, or 13.1% to $31 million for the year ended December 31, 2023 from $27.4 million for the year ended December 31, 2022.
Field service expense decreased $2.6 million, or 22.4% to $9.1 million for the year ended December 31, 2024 from $11.7 million for the year ended December 31, 2023. Field service expenses primarily consist of wages and vehicle operating expenses. These changes reflect decreases in equipment utilization related to the sale of Eastern Oil Well Service Company, effective August 31, 2024.
Workover rig services, hot oil treatments, saltwater hauling and disposal represent the bulk of our field service operations. These changes reflect the variance in equipment utilization and service rates during these periods. Field service expense increased $0.6 million, or 5.4% to $11.7 million for the year ended December 31, 2023 from $11.1 million for the year ended December 31, 2022.
Workover rig services, hot oil treatments, saltwater hauling and disposal represent the bulk of our field service operations. These changes reflect decreases in equipment utilization related to the sale of Eastern Oil Well Service Company, effective August 31, 2024.
During 2023, to supplement cash flow and finance our future drilling programs, the Company sold 368 net mineral acres as well as 7.8 surface acres in Midland County, Texas receiving gross proceeds of $436,050 and recognizing a gain of $47,000.
In total in these 22 wells, we will invest approximately $60 million. 39 During 2024, to supplement cash flow and finance our future drilling programs, the Company sold 120 net mineral acres and 10 surface acres in Midland and Ector counties, Texas. For these, we received $1,386,000 in gross proceeds.
Removed
Critical Accounting Estimates: Proved Oil and Gas Reserves Proved oil and gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization.
Added
The reserve base includes only proved developed reserves for lease and well equipment costs, which include development costs and successful exploration drilling costs. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account.
Removed
Holding all other factors constant, if reserves were revised upward or downward, earnings would increase or decrease respectively. Depreciation, depletion and amortization of the cost of proved oil and gas properties are calculated using the unit-of-production method.
Added
As of the quarter ended December 31, 2024, the Company had $4 million in outstanding borrowings and $111 million in availability. Accordingly, the Company had no swap agreements in place for oil and natural gas. Development and Other Activities The Company’s activities include development and exploratory drilling.
Removed
In 2023, including 20 wells spud in the fourth quarter of 2023, the Company participated with five operators in 35 wells: 32 of these are located in West Texas and three are located in Oklahoma.
Added
In 2024, the Company invested $113 million in 48 horizontals in West Texas: 47 of these are located in Reagan County and one is located in Upton County.
Removed
The Company invested approximately $91 million in these wells, including in their production facilities, almost all attributable to wells drilled and completed in West Texas where we are focused on horizontal development of various proven pay intervals in the Wolfcamp and Spraberry formations.
Added
In Reagan County, the Company joined Double Eagle in drilling and completing 33 new horizontal wells: on the “Honey RF” tract we completed 12 horizontals each being two-mile-long laterals, and participated with 50% interest investing $37 million; on the “Prime West” tract we have 50% interest in six wells and invested $20.5 million; on both the “Kramer” and “O’Bannion” tracts we participated in six horizontals, each with an average 8.3% interest and we invested approximately $7.8 million; and on the “Pink Floyd” tract we have less than 1% interest in two wells in which we invested approximately $174,900; and on our“Studley AV” tract we participated with Double eagle in testing the Wolfcamp “D” interval; in this well we have about 6.3% interest and invested approximately $600,000.
Removed
On December 31, 2023, we had 12 wells completed that were all brought into production in January of 2024. In addition to $7.9 million of the $91 million invested in these wells in 2023, the Company had an additional $15.5 million investment in these 12 wells.
Added
Also in Reagan County, we participated with Civitas in 14 horizontal wells on the “Christi” tract, carrying an average of 39% interest and investing roughly $46.7 million. Also in 2024, in Upton County, we participated with Pioneer Natural Resources in one 2-mile-long horizontal with 3.94% interest, investing approximately $425,700.
Removed
Also at year-end 2023, the Company was in the process of drilling and completing 34 wells in West Texas that carry an expense of $80.6 million, and planning for a 50% participation in an additional 12 wells to be drilled in 2024 that will require an investment of approximately $43 million.
Added
Of these 48 wells, 32 are 2-mile-long laterals, 14 are 2.5-mile-long laterals, and two are 3-mile-long laterals. In addition to this activity, in June of 2024, we began participation with Apache in the drilling of six additional 3-mile-long laterals in Upton County on our “Mt. Moran” tract.
Removed
In total, the Company expects to invest $140 million in 54 wells in 2024 and, in 2025, to invest $95 million in an additional 23 wells in West Texas.
Added
Three of these wells were completed in late December 2024 and three were completed in January of 2025. All six new “Mt. Moran” wells are producing as of April 1, 2025. In these six Mt. Moran wells, the Company has an average of 51.16% interest and will in total invest approximately $40.5 million.
Removed
In the second quarter of 2023, the Company acquired 55 net acres in the South Stiles area of Reagan County, Texas for $605,000, and in a separate agreement also in Reagan County, the Company sold 320 non-core acres for proceeds of $6,000,000. In addition, the Company sold 36.51% interest in one well in Midland County, Texas for proceeds of $60,000.
Added
In addition, in November of 2024, in Reagan County, we began participating with Double Eagle in 15 “OG” horizontal wells: eight are 2.5-mile-long laterals, and seven are 2-mile-long laterals. In each of these 15 “OG” wells the Company has approximately 23% interest and in total will invest roughly $29 million through completion of production facilities.
Removed
In the third quarter of 2023, the Company sold a non-core 38.25-acre leasehold tract in Martin County, Texas for proceeds of $899,000 and sold 3 surface acres in Liberty County, Texas for net proceeds of $37,053.
Added
These 15 horizontals are expected to be on production in mid to late April 2025. By the end of the second quarter of 2025, therefore, the Company will have invested approximately $70 million in these additional 21 horizontal wells.
Removed
Also in the third quarter, in various counties of Oklahoma, the Company divested its interest in 39 wells, reducing its future plugging liability by approximately $1.5 million. Effective July 1, 2023, the Company acquired the operations of 36 wells from DE Permian and 50% of DE Permian’s original ownership in such wells.
Added
In early March 2025, Ovintiv Mid-Continent spud two “Jennifer 1407” wells in Canadian County, Oklahoma; in these, we will participate for approximately 3.125% interest and invest $408,000.
Removed
In addition, in Reagan County, Texas, the Company acquired 114.52 net acres from DE Permian for $1,700,853 and assigned to them 203.23 net acres. In the fourth quarter of 2023, the Company sold 136 surface acres in Oklahoma for net proceeds of $306,000 and in Midland Texas sold 9.35 net acres for proceeds of $280,423.
Added
In the second and third quarters of 2025, we are anticipating the start of twenty new horizontals in the Midland Basin of West Texas: 15 wells operated by Double Eagle on our “Full House” tract in Reagan County in which the Company will participate with approximately 31% interest and invest $48.4 million, and five wells operated by ConocoPhillips on our “Schenecker” tract in Martin, County in which we plan to participate for 20.83% interest and invest $11.3 million.
Removed
Proceeds from these sales in 2023, along with our cash flow, were used to eliminate the Company’s outstanding bank debt as of March 31, 2023. As noted above, as of March 31, 2024, the Company had $4 million outstanding borrowings and $81 million in availability under this facility.
Added
In addition, we divested 37 producing and two saltwater injection wells in various counties of New Mexico and Texas. These divestments have extinguished a substantial amount in future plugging liability. Also in 2024, we sold our South Texas oil field services company, Eastern Oil Well Service, for proceeds of $2.8 million.
Removed
As oil and natural gas prices remain volatile, mark-to-market accounting treatment creates volatility in our revenues.
Added
Included with this sale were extensive oil field service equipment and transport trucks, as well as two commercial saltwater disposal wells. Acquisitions in 2024, entailed the purchase of 381 net leasehold acres in West Texas for approximately $3.9 million.
Removed
The DD&A expense is primarily attributable to our properties in West Texas and Oklahoma, reflecting the addition of new properties offset by the declining cost basis of existing properties. General and administrative expense decreased $4.6 million, or 22.7% to $15.6 million for the year ended December 31, 2023 from $20.2 million for the year ended December 31, 2021.
Added
Depreciation, depletion, and amortization increased $45.5 million, or 147.0% to $76.5 million for the year ended December 31, 2024 from $31.0 million for the year ended December 31, 2023. These increases reflect the expense related to the new wells placed on production during the twelve months ended December 31, 2024.
Removed
The $31.8 million for the year ended December 31, 2022 consists principally of sales of deep rights in undeveloped acreage in West Texas. Interest expense decreased $0.4 million, or 41.0% to $0.5 million for the year ended December 31, 2023 from $0.9 million for the year ended December 31, 2022.
Added
General and administrative expense increased $3.2 million, or 21.0% to $18.8 million for the year ended December 31, 2024 from $15.6 million for the year ended December 31, 2023. This increase is primarily due to employee compensation, benefits and other corporate costs.
Removed
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. We are a smaller reporting company and therefore no response is required pursuant to this Item. Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. The consolidated financial statements and supplementary information included in this Report are described in the Index to Consolidated Financial Statements at Page F-1 of this Report. Item 9.
Added
Interest expense increased $1.0 million, or 189.0% to $1.5 million for the year ended December 31, 2024 from $0.5 million for the year ended December 31, 2023. This increase reflects the higher interest and fee rates combined with borrowings throughout the twelve months of 2024 under our revolving credit agreement.
Removed
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. None. 40 Item 9A. CONTROLS AND PROCEDURES. As of the end of the period covered by this Annual Report on Form 10-K, our principal executive officer and principal financial officer have evaluated the effectiveness of our “disclosure controls and procedures” (“Disclosure Controls”).
Removed
Disclosure Controls, as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are procedures that are designed with the objective of ensuring that information required to be disclosed in our reports filed under the Exchange Act, such as this Annual Report, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.
Removed
Disclosure Controls are also designed with the objective of ensuring that such information is accumulated and communicated to our management, including the chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.
Removed
Our management, including the chief executive officer and chief financial officer, does not expect that our Disclosure Controls will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
Removed
Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs.
Removed
Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake.
Removed
The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.
Removed
Members of our management, including our chief executive officer and chief financial officer, have evaluated the effectiveness of our disclosure controls and procedures, as defined by paragraph (e) of Exchange Act Rules 13a-15 or 15d-15, as of December 31, 2023 the end of the period covered by this Report.
Removed
Based upon that evaluation, these officers concluded that our disclosure controls and procedures were effective as of December 31, 2023. Management ’ s Report on Internal Control Over Financial Reporting Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act.
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Our internal control over financial reporting is a process designed to provide reasonable assurance that assets are safeguarded against loss from unauthorized use or disposition, transactions are executed in accordance with appropriate management authorization and accounting records are reliable for the preparation of financial statements in accordance with U.S. generally accepted accounting principles.
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Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
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Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2023. Management based this assessment on criteria for effective internal control over financial reporting described in “Internal Control – Integrated Framework (2013)” issued by the Committee of Sponsoring Organizations of the Treadway Commission.
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Management’s assessment included an evaluation of the design of our internal control over financial reporting and testing of the operational effectiveness of its internal control over financial reporting. Management reviewed the results of its assessment with the Audit Committee of our Board of Directors.
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As a result of this assessment, management concluded that, as of December 31, 2023, our internal control over financial reporting was effective in providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
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This Annual Report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this Annual Report.
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There have been no changes in our internal controls over financial reporting during the fourth fiscal quarter ended December 31, 2023 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting. Item 9B. OTHER INFORMATION. None. Item 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS. Not applicable. 41 PART III Item 10.
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DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE. Information relating to the Company’s Directors, nominees for Directors and executive officers will be included in the Company’s definitive proxy statement relating the Company’s Annual Meeting of Stockholders to be held in June 5, 2024, and which is incorporated herein by reference.
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Code of Conduct and Ethics We have adopted a Code of Business Ethics and Conduct (the “Code”) that applies to all officers and employees. The Code is publicly available under the governance tab of our website at www.primeenergy.com.
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Any amendments to, or waivers of, the Code with respect to our principal executive officer, principal financial officer or principal accounting officer or controller, or persons performing similar functions, will be disclosed on our website within four business days following the date of the amendment or waiver.
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