PRIMEENERGY RESOURCES CORP
For the period ended Dec 31, 2024. Filed Apr 15, 2025.
View on SEC.govAbout this filing
A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2024 · Filed Apr 15, 2025
PNRG$185.64+2.7%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-K
Period ended 2023-12-31; filed 2024-04-15.
0001437749-24-011958
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSCurrent report: 10-K
Period ended 2024-12-31; filed 2025-04-15.
0001437749-25-012086
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 47 previous paragraphs and 46 current paragraphs.
25 unchanged; 15 reworded; 6 added; 7 removed; 0 previous and 0 current paragraphs rearranged.
Tables are not compared: 3 previous and 3 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (6)
Current report
Development and Other Activities
Current report
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. 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. 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. Of these 48 wells, 32 are 2-mile-long laterals, 14 are 2.5-mile-long laterals, and two are 3-mile-long laterals.
Current report
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. 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. 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. 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.
Current report
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. 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. In total in these 22 wells, we will invest approximately $60 million.
Current report
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.
Current report
Interestexpense 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 paragraphs (7)
Previous report
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. 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. 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. 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. 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.
Previous report
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.
Previous report
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. 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. 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.
Previous report
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.
Previous report
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.
Previous report
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. 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.
Previous report
Interestexpense 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. This decrease reflects the increase in rates combined with reduced borrowings under our revolving credit agreement
Reworded paragraphs (15)
Previous wording
Our financial results depend on many factors, particularly the price of natural gas and crude oil 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. In addition, our realized prices are further impacted by our derivative and hedging activities. We derive our revenue and cash flow principally from the sale of oil, natural gas and NGLs. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil, natural gas and NGLs. We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts. Because some of our operations are located outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing. The market price for oil, natural gas and NGLs is dictated by supply and demand; consequently, we cannot accurately predict or control the price we may receive for our oil, natural gas and NGLs. 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.
Current wording
Our financial results depend on many factors, particularly the price of natural gas and crude oil 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. In addition, our realized prices are further impacted by our derivative and hedging activities. We derive our revenue and cash flow principally from the sale of oil, natural gas and NGLs. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil, natural gas and NGLs. We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts. Because some of our operations are located outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing. The market price for oil, natural gas and NGLs is dictated by supply and demand; consequently, we cannot accurately predict or control the price we may receive for our oil, natural gas and NGLs. 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.
Previous wording
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. Our oil and gas production will vary based on actual well performance but may be curtailed due to factors beyond our control.
Current wording
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. Our oil and gas production will vary based on actual well performance but may be curtailed due to factors beyond our control.
Previous wording
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 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. 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. If we do not comply with these covenants on a continuing basis, the lenders have the right to refuse to advance additional funds under the facility and/or declare all principal and interest immediately due and payable. Our borrowing base may decrease as a result of lower natural gas or oil prices, operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or for other reasons set forth in our revolving credit agreement. In the event of a decrease in our borrowing base due to declines in commodity prices or otherwise, our ability to borrow under our revolving credit facility may be limited and we could be required to repay any indebtedness in excess of the re-determined borrowing base.
Current wording
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. 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. 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. If we do not comply with these covenants on a continuing basis, the lenders have the right to refuse to advance additional funds under the facility and/or declare all principal and interest immediately due and payable. Our borrowing base may decrease as a result of lower natural gas or oil prices, operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or for other reasons set forth in our revolving credit agreement. In the event of a decrease in our borrowing base due to declines in commodity prices or otherwise, our ability to borrow under our revolving credit facility may be limited and we could be required to repay any indebtedness in excess of the re-determined borrowing base.
Previous wording
Our credit agreement requires us to hedge a portion of our production as forecasted for the PDP reserves included in our borrowing base review engineering reports. 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. Accordingly, the Company had no swap agreements in place for oil and natural gas.
Current wording
Our credit agreement requires us to hedge a portion of our production as forecasted for the PDP reserves included in our borrowing base review engineering reports. 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. 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.
Previous wording
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.
Current wording
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. 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. 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.
Previous wording
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 expects continued spending under the stock repurchase program in 2024.
Current wording
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.
Previous wording
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. The significant components of income and expense are discussed below.
Current wording
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.
Previous wording
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. 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.
Current wording
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. 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.
Previous wording
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 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.
Current wording
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. 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.
Previous wording
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. 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.
Current wording
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. 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.
Previous wording
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. 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.
Current wording
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. 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.
Previous wording
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. Field service expenses primarily consist of wages and vehicle operating expenses. The changes reflect the variance in equipment utilization during the periods represented.
Current wording
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.
Previous wording
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. These changes are primarily related to employee compensation and benefits.
Current wording
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.
Previous wording
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. The $31.8 million for the year ended December 31, 2022 consists principally of sales of deep rights in undeveloped acreage in West Texas.
Current wording
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.
Previous wording
Taxexpense 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.
Current wording
Taxexpense 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.