PRIMEENERGY RESOURCES CORP

Previous wording

We are an independent oil and natural gas company engaged in acquiring, developing, and producing oil and natural gas. We presently own producing and non-producing properties located primarily in Texas and Oklahoma. All of our oil and gas properties and interests are located in the United States. Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as newer properties with development and exploration potential. We also own a 12.5% overriding royalty interest in over 30,000 acres in the state of West Virginia, although we are currently not receiving revenue from this asset as development has not begun. In Texas, we own well-servicing equipment that is used to service our operated properties as well as to provide oil field services to third-party operators. In addition, we own a 60-mile-long pipeline offshore on the shallow shelf of Texas that is currently idle but that we believe has future value for producers in the area. We also hold a 33.3% interest in a limited partnership that owns a 138,000-square-foot retail shopping center on ten acres in Prattville, Alabama. There is currently no debt on the shopping center and it has approximately $500,000 of working capital on its balance sheet. We believe our balanced portfolio of assets positions us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities. Our primary sources of liquidity are cash generated from operations, our credit facility, and existing cash on our balance sheet.

Current wording

We are an independent oil and natural gas company engaged in acquiring, developing, and producing oil and natural gas. We presently own producing and non-producing properties located primarily in Texas and Oklahoma. All of our oil and gas properties and interests are located in the United States. Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as newer properties with development and exploration potential. We also own a 12.5% overriding royalty interest in over 30,000 acres in the state of West Virginia, although we are currently not receiving revenue from this asset as development has not begun. In Texas, we own well-servicing equipment that is used to service our operated properties as well as to provide oil field services to third-party operators. In addition, we own a 60-mile-long pipeline offshore on the shallow shelf of Texas that is currently idle but that may possibly have future value for producers in the area. We also hold a 33.3% interest in a limited partnership that owns a 138,000-square-foot retail shopping center on ten acres in Prattville, Alabama. There is currently no debt on the shopping center and it has approximately $700,000 of working capital on its balance sheet. We believe our balanced portfolio of assets positions us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities. Our primary sources of liquidity are cash generated from operations, our credit facility, and existing cash on our balance sheet.

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 when used to manage commodity price risk. As mentioned above, our existing contracts expired in March of 2023 and we currently do not intend to use future derivative contracts unless required by our bank loan.

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 when used to manage commodity price risk. Our most recent contracts expired in March of 2023 and we currently do not intend to use future derivative contracts unless required by our bank loan.

Previous wording

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 are higher than in the recent past, however, prices may be volatile and, consequently, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital program, production volumes or revenue.

Current wording

We derive our revenue and cash flow principally from the sale of oil, natural gas, and Natural Gas Liquids (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 are higher than in the recent past, however, prices may be volatile and, consequently, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital program, production volumes or revenue.

Previous wording

The Company is actively developing additional reserves of its leasehold acreage positions in Texas and Oklahoma. In the Permian Basin of West Texas and eastern New Mexico the Company maintains an acreage position of approximately 16,491 gross (9,383 net) acres, 96% of which is located in Reagan, Upton, Martin, and Midland counties of Texas where our current horizontal drilling activity is focused. We believe this acreage has significant resource potential in the Spraberry and Wolfcamp intervals for additional horizontal drilling that could support the drilling of as many as 190 additional horizontal wells. In Oklahoma, we maintain an acreage position of approximately 46,960 gross (10,097 net) acres. Our Oklahoma horizontal development is focused primarily in Canadian, Kingfisher, Grady, and Garvin counties. We believe approximately 2,355 net acres in these counties hold significant additional resource potential that could support the drilling of as many as 38 new horizontal wells based on an estimate of four wells per section, two in the Mississippian and two in the Woodford Shale. Should we choose to participate with a working interest in future development, our share of these future capital expenditures would be approximately $30 million at an average 10% ownership level.

Current wording

The Company is actively developing non-producing reserves of its leasehold acreage positions in Texas and Oklahoma. In the Permian Basin of West Texas, the Company maintains an acreage position of approximately 17,138 gross (9,484 net) acres, 97% of which is located in Reagan, Upton, Martin, and Midland counties of Texas where our current horizontal drilling activity is focused. We believe this acreage has significant resource potential in the Spraberry, Jo Mill and Wolfcamp intervals for additional horizontal drilling that could support the drilling of as many as 190 additional horizontal wells. In Oklahoma, we maintain an acreage position of approximately 45,715 gross (10,102 net) acres. Our Oklahoma horizontal development is focused primarily in Canadian, Kingfisher, Grady, and Garvin counties. We believe approximately 2,355 net acres in these counties hold additional resource potential that could support the drilling of as many as 38 new horizontal wells based on an estimate of four wells per section, two in the Mississippian and two in the Woodford Shale. Should we choose to participate with a working interest in future development, our share of these future capital expenditures would be approximately $30 million at an average 10% ownership level, but in this current natural price environment we would not likely participate with a working interest, but would instead sell or farm-out our interest.

Previous wording

In two of our producing regions we have field service groups to service our operated wells and locations as well as third-party operators in the area. These services consist of well service support, site preparation and construction services for drilling and workover operations. Our operations are performed utilizing workover or swab rigs, water transport trucks, saltwater disposal facilities, various land excavating equipment and trucks we own and that are operated by our field employees.

Current wording

In the West Texas region, we have field service groups to service our operated wells and locations as well as third-party operators in the area. These services consist of well service support, site preparation and construction services for drilling and workover operations. Our operations are performed utilizing workover or swab rigs, water transport trucks, saltwater disposal facilities, various land excavating equipment and trucks we own and that are operated by our field employees.

Previous wording

Our development, exploitation, exploration and production activities in the Gulf Coast region are primarily concentrated in southeast Texas. This region is managed from our office in Houston, Texas. Principal producing intervals are in the Yegua and Wilcox formations at depths ranging from 3,000 to 12,500 feet. We had 114 producing wells (21 net) in the Gulf Coast region as of December 31, 2023, of which 28 wells are operated by us. Average net daily production in our Gulf Coast Region at year-end 2023 was 173 Boe. At December 31, 2023, we had 563 MBoe of proved reserves in the Gulf Coast region, which represented 2% of our total proved reserves. We maintain an acreage position of over 7,468 gross (4,699 net) acres in this region, primarily in Colorado, Newton, and Polk counties. We operate a field service group in this region from a field office in Carrizo Springs, Texas utilizing two workover rigs, twenty water transport trucks, two hot-oil trucks, a cement truck, and two saltwater disposal wells to provide oil field services for third-party operators in South Texas. At this time, the Gulf Coast region has no operated wells in the process of being drilled, no waterfloods in the process of being installed and no other related activities of material importance.

Current wording

Our development, exploitation, exploration and production activities in the Gulf Coast region are primarily concentrated in southeast Texas. This region is managed from our office in Houston, Texas. Principal producing intervals are in the Yegua and Wilcox formations at depths ranging from 3,000 to 12,500 feet. We had 114 producing wells (21 net) in the Gulf Coast region as of December 31, 2023, of which 28 wells were operated by us. Average net daily production in our Gulf Coast Region at year-end 2023 was 173 Boe. At December 31, 2023, we had 563 MBoe of proved reserves in the Gulf Coast region, which represented 2% of our total proved reserves. We maintain an acreage position of over 7,468 gross (4,699 net) acres in this region, primarily in Colorado, Newton, and Polk counties. At this time, the Gulf Coast region has no operated wells in the process of being drilled, no waterfloods in the process of being installed, but we do have plans for the recompletion of one well in the Segno field of Polk County, in which the Company has a 72.5% working interest.

Previous wording

Our Mid-Continent activities are concentrated in central Oklahoma. This region is managed from our office in Oklahoma City, Oklahoma. As of December 31, 2023, we had 511 producing wells (132 net) in the Mid-Continent area, of which 128 wells are operated by us. Principal producing intervals are in the Robberson, Avant, Skinner, Sycamore, Bromide, McLish, Hunton, Mississippian, Oswego, Red Fork, and Chester formations at depths ranging from 1,100 to 10,500 feet. The average net daily production in our Mid-Continent Region in 2023 was 831 Boe. On December 31, 2023, we had 2,210 MBoe of proved reserves in the Mid-Continent area, representing 8% of our total proved reserves. We maintain an acreage position of approximately 46,960 gross (10,097 net) acres in this region, primarily in Canadian, Kingfisher, Garfield, Major, and Garvin counties. Our Mid-Continent region is actively participating with third-party operators in the horizontal development of lands that include Company-owned interest in several counties in the Stack and Scoop plays of Oklahoma where drilling is primarily targeting reservoirs of the Mississippian and Woodford formations. These Oklahoma counties that are our primary focus for horizontal development are Canadian, Kingfisher, Grady, and Garvin.

Current wording

Our Mid-Continent activities are concentrated in central Oklahoma. This region is managed from our office in Oklahoma City, Oklahoma. As of December 31, 2023, we had 511 producing wells (132 net) in the Mid-Continent area, of which 128 wells are operated by us. Principal producing intervals are in the Robberson, Avant, Skinner, Sycamore, Bromide, McLish, Hunton, Mississippian, Oswego, Red Fork, and Chester formations at depths ranging from 1,100 to 10,500 feet. The average net daily production in our Mid-Continent Region in 2023 was 831 Boe. On December 31, 2023, we had 2,210 MBoe of proved reserves in the Mid-Continent area, representing 8% of our total proved reserves. We maintain an acreage position of approximately 45,715 gross (10,102 net) acres in this region, primarily in Canadian, Kingfisher, Garfield, Major, and Garvin counties. Our Mid-Continent region is actively participating with third-party operators in the horizontal development of lands that include Company-owned interest in several counties in the Stack and Scoop plays of Oklahoma where drilling is primarily targeting reservoirs of the Mississippian and Woodford formations. These Oklahoma counties that are our primary focus for horizontal development are Canadian, Kingfisher, Grady, and Garvin.

Previous wording

West Texas activities are concentrated in the Permian Basin in Texas and New Mexico. The oil and gas in this basin are produced primarily from five intervals; the Upper and Lower Spraberry, the Wolfcamp, the Strawn, and the Atoka, at depths ranging from 6,700 feet to 11,300 feet. This region is managed from our office in Midland, Texas. As of December 31, 2023, we had 647 wells (275 net) in the West Texas area, of which 334 wells are operated by us. Principal producing intervals are in the Spraberry, Wolfcamp, and San Andres formations at depths ranging from 4,200 to 12,500 feet. The average net daily production in Our West Texas Region at year-end 2023 was 6,172 Boe. On December 31, 2023, we had 26,267 MBoe of proved reserves in the West Texas area, or 90% of our total proved reserves. We maintain an acreage position of approximately 16,491 gross (9,383 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin, and Midland counties and believe this acreage has significant resource potential for horizontal drilling in the Spraberry, Jo Mill, and Wolfcamp intervals. We operate a field service group in this region utilizing nine workover rigs, three hot oiler trucks, and one kill truck. Oil field support is provided for drilling and workover operations both to third-party operators as well as for our own operated wells and locations.

Current wording

West Texas activities are concentrated in the Permian Basin in Texas. The oil and gas in this basin are produced primarily from five intervals; the Upper and Lower Spraberry, the Wolfcamp, the Strawn, and the Atoka, at depths ranging from 6,700 feet to 11,300 feet. This region is managed from our office in Midland, Texas. As of December 31, 2023, we had 647 wells (275 net) in the West Texas area, of which 334 wells are operated by us. Principal producing intervals are in the Spraberry, Wolfcamp, and San Andres formations at depths ranging from 4,200 to 12,500 feet. The average net daily production in Our West Texas Region at year-end 2023 was 6,172 Boe. On December 31, 2023, we had 26,267 MBoe of proved reserves in the West Texas area, or 90% of our total proved reserves. We maintain an acreage position of approximately 17,138 gross (9,484 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin, and Midland counties and believe this acreage has significant resource potential for horizontal drilling in the Spraberry, Jo Mill, and Wolfcamp intervals. We operate a field service group in this region utilizing nine workover rigs, three hot oiler trucks, and one kill truck. Oil field support is provided for drilling and workover operations both to third-party operators as well as for our own operated wells and locations.

Previous wording

As of June 30, 2024, the Company was participating in the completion of 12 horizontal wells in Reagan County, Texas with an average 50% interest and 4.08% in one well in Upton County, Texas. Combined, we expect to spend approximately $44 million in these horizontals and their associated facilities. These wells will be put on production in the third quarter.

Current wording

As of September 30, 2024, the Company was participating in the completion of 6 horizontal wells in Upton County, Texas with an average 47.52% interest. In total, we expect to spend approximately $35 million in these horizontals and their associated facilities. are in the process of being completed and expect to be on production in the first quarter of 2025

Previous wording

In total in 2024, we expect to complete 56 new horizontal wells, investing approximately $141 million. We are also preparing to invest approximately $84 million in another 30 horizontal wells to be drilled and completed in 2025. In addition, we have identified 21 horizontal locations for future development in West Texas that we anticipate to be drilled in the 2026-2027 timeframe and would require a net investment of approximately $69 million.

Current wording

In 2024, we have completed 56 new horizontal wells, investing approximately $141 million. We are also preparing to invest approximately $84 million in another 30 horizontal wells to be drilled and completed in 2025. In addition, we have identified 21 horizontal locations for future development in West Texas that we anticipate to be drilled in the 2026-2027 timeframe and would require a net investment of approximately $69 million.

Previous wording

In the fourth quarter of 2022, we began participation in the drilling of 20 horizontal wells located in West Texas operated by three different operators. In Martin County, we participated with ConocoPhillips in five 2.5-mile-long horizontal wells in which the Company has 20.83% interest and had capital investment of $12.1 million. In Reagan County, we participated with Hibernia Energy III (now Civitas Resources) in 10 two-mile horizontals with 25% interest and an investment of approximately $25.6 million. Also in Reagan County, we participated with Double Eagle (DE IV) in five two-mile-long horizontals with nearly 50% interest, carrying a net capital outlay of $23.4 million. All twenty of these West Texas wells were completed and online in the second quarter of 2023.

Current wording

In the fourth quarter of 2022, we began participation in the drilling of 20 horizontals located in West Texas operated by three different operators. In Martin County, we participated with ConocoPhillips in five 2.5-mile-long horizontal wells in which the Company has 20.83% interest and had capital investment of $12.1 million. In Reagan County, we participated with Hibernia Energy III (now Civitas Resources) in 10 two-mile horizontals with 25% interest and an investment of approximately $25.6 million. Also in Reagan County, we participated with Double Eagle (DE IV) in five two-mile-long horizontals with nearly 50% interest, carrying a net capital outlay of $23.4 million. All twenty of these West Texas wells were completed and online in the second quarter of 2023.

Previous wording

In 2023, the Company participated with five operators in the drilling and completion of 35 horizontal wells: 32 of these are located in West Texas and three are located in Oklahoma. In total, including the cost of facilities, the Company invested approximately $91 million, 99% of which is attributable to the wells in West Texas where we have been drilling horizontal wells targeting various proven pay intervals in the Wolfcamp and Spraberry formations. At December 31, 2023, we had 12 wells completed but not producing that were all brought into production in January of 2024. These 12 wells account for 1,278 MBOE of proved developed reserves at year-end. In addition, as of December 31, 2023, the Company was in the process of drilling and completing 34 wells in West Texas, 28 of which are considered proved undeveloped, and six of which are considered probable undeveloped. The year-end reserve report includes only proved reserves, therefore expected reserves from the six probable undeveloped wells are not included in the reserve report.

Current wording

In 2023, the Company participated with five operators in the drilling and completion of 35 horizontal wells: 32 of these are located in West Texas and three are located in Oklahoma. In total, including the cost of facilities, the Company invested approximately $91 million, 99% of which is attributable to the wells in West Texas where we have been drilling horizontal wells targeting various proven pay intervals in the Wolfcamp and Spraberry formations. At December 31, 2023, we had 12 wells completed but not producing that were all brought into production in January of 2024. These 12 wells account for 1,278 MBOE of proved developed reserves at year-end. In addition, as of December 31, 2023, the Company was in the process of drilling and completing 34 wells in West Texas, 28 of which are considered proved undeveloped, and six of which are considered probable undeveloped. The year-end reserve report includes only proved reserves, therefore expected reserves from the six probable undeveloped wells are not 999 included in the reserve report.

Previous wording

In the Second Quarter of 2024, the Company has completed nine additional wells in Reagan County, Texas: three more “O’Bannon” wells, and six “Kramer” wells. In these nine 2.5-mile-long-horizontals, the Company has an average 8.3% ownership and invested approximately $7.5 million. These nine wells, along with the three “O’Bannon” wells completed in the first quarter, were brought on line in April. Also in April nine “Christi” wells were brought on production. In addition to these wells brought on production in April, the Company is participating with 37.5% interest in five more “Christi” wells operated by Civitas and with 50% interest in six “Prime West” wells operated by Double Eagle. The estimated cost for the remaining five “Christi” wells and the six Prime West wells is $14 million and $23.9 million respectively. These 11 wells were stimulated and put on production in May. In April of this year, participating with Double Eagle, the Company spud 12 wells in Reagan County, Texas. In these 12 “Honey RF” wells the Company has 50% working interest and will invest approximately $43.5 million. These wells are in the process of being stimulated and we anticipate them to be finished with completion and on production in the third quarter of 2024.

Current wording

In the Second Quarter of 2024, the Company completed nine additional wells in Reagan County, Texas: three more “O’Bannon” wells, and six “Kramer” wells. In these nine 2.5-mile-long-horizontals, the Company has an average 8.3% ownership and invested approximately $7.5 million. These nine wells, along with the three “O’Bannon” wells completed in the first quarter, were brought on line in April. Also, in April nine “Christi” wells were brought on production. In addition to these wells brought on production in April, the Company is participating with 37.5% interest in five more “Christi” wells operated by Civitas and with 50% interest in six “Prime West” wells operated by Double Eagle. The estimated cost for the remaining five “Christi” wells and the six Prime West wells is $14 million and $23.9 million respectively. These 11 wells were stimulated and put on production in May. In April of this year, participating with Double Eagle, the Company spud 12 wells in Reagan County, Texas. In these 12 “Honey RF” wells the Company has 50% working interest and has invested approximately $43.6 million. These wells were all completed in the third quarter and on production by mid-September 2024.

Previous wording

In May, together with Double Eagle, we spud a 2-mile-long horizontal test well in Reagan County, Texas targeting the Wolfcamp “D” interval which showed promise but had few production tests. This well began production in mid-June, however, it will take three to six months or more to determine if it has confirmed the Wolfcamp “D” as an economically viable target.

Current wording

In May 2024, together with Double Eagle, we spud a 2-mile-long horizontal test well in Reagan County, Texas targeting the Wolfcamp D interval. In this well the Company has approximately 6% interest. The well had a respectable initial production rate of 1000 barrels of oil per day, but declined rather quickly in the first two months, so it may be three months or more of additional production before we know if this well has confirmed the Wolfcamp D as an economically viable target in the immediate area. Civitas Resources has also been targeting the Wolfcamp D interval and in their November 2024 third quarter reports have highlighted strong results from their 16 new Wolfcamp D wells in Reagan and Upton counties. Both Civitas Resources and Diamondback Energy have stated plans for additional Wolfcamp D drilling in southern Midland Basin. This additional drilling target for the Company would potentially set-up the development of as many as 36 horizontals on our acreage in Reagan County. In such a development program, the Company would have a range of interest from 6% to 50%, with an average of approximately 29%, and investment of approximately $94 million.

Previous wording

In total, in 2024, we expect to complete 56 new horizontal wells, investing approximately $141 million. We are also preparing to invest approximately $84 million in another 30 horizontal wells to be spud in 2024 or 2025 and be completed and put on production in 2025. In addition, we have identified 21 horizontal locations for future development in West Texas that we anticipate to be drilled in the 2026-2027 timeframe which would require a net investment of approximately $69 million. In total, we anticipate investing more than $300 million in horizontal development in West Texas from January 2024 through December 2027.

Current wording

In total, in 2024, we completed 56 new horizontal wells, investing approximately $141 million and the six wells with Apache in Upton County, Texas that are in the process of being completed are expected to come on line after the first of the year. We are also actively investing or preparing to invest approximately $84 million in 30 new horizontal wells, including six 3-mile-long horizontals with Apache now in the process of being completed in Upton County, Texas, that are expected to be completed and put on production in 2025. In addition, we have identified 21 horizontal locations for future development of the Upper Wolfcamp and Spraberry, primarily in Martin and Upton Counties that we anticipate will be drilled in the 2026-2027 timeframe which would require a net investment of approximately $69 million. In total, we anticipate investing more than $300 million in horizontal development in West Texas from January 2024 through December 2027. The Wolfcamp D target interval could potentially add 36 drilling locations and investment potential of $94 million to what is already expected through 2027.

Previous wording

In the Permian Basin of West Texas and eastern New Mexico, we maintain an acreage position of approximately 16,491 gross (9,383 net) acres, 96.4% of which is located in Reagan, Upton, and Martin counties of Texas where our current West Texas horizontal drilling activities are focused. In addition to the wells currently being drilled or completed, we believe this acreage has the resource potential to support the drilling of as many as 190 future horizontal wells.

Current wording

In the Permian Basin of West Texas, we maintain an acreage position of approximately 17,138 gross (9,484 net) acres, 97% of which is located in Reagan, Upton, and Martin counties of Texas where our current West Texas horizontal drilling activities are focused. In addition to the wells currently being drilled or completed, we believe this acreage has the resource potential to support the drilling of as many as 190 future horizontal wells.

Previous wording

In Oklahoma, we are focused on the development of our reserves in Canadian, Kingfisher, Grady, and Garvin counties where we have approximately 4,073 net leasehold acres in the Scoop/Stack Play. Of this acreage, we believe 2,355 net leasehold acres hold significant additional resource potential that could support the drilling of as many as 38 new horizontal wells based on an estimate of four wells per multi-section drilling unit, two in the Mississippian and two in the Woodford Shale. Proposals may be received on the remaining 2,017 acres, however, rather than participate we may choose to sell the acreage or farm-out, receiving cash and retaining an over-riding royalty interest. In regard to 14 newly drilled wells in 2023, for which we chose to farm-out our working interest, five of these wells were completed in March 2024 and put on production, and the other nine wells are being completed at present and should be put on production in late August 2024. Thus far in 2024, there have been no additional development wells proposed.

Current wording

In Oklahoma, we are focused on the development of our reserves in Canadian, Kingfisher, Grady, and Garvin counties where we have approximately 4,073 net leasehold acres in the Scoop/Stack Play. Of this acreage, we believe 2,355 net leasehold acres hold significant additional resource potential that could support the drilling of as many as 38 new horizontal wells based on an estimate of four wells per multi-section drilling unit, two in the Mississippian and two in the Woodford Shale. Proposals may be received on the remaining 2,017 acres, however, rather than participate we may choose to sell the acreage or farm-out, receiving cash and retaining an over-riding royalty interest. Regarding 15 newly drilled wells in 2023, in which we elected to farm our working interest and retain an ORRI, five were completed and put on production in March 2024, another five were completed and put on production in September 2024, and the remaining five were completed and brought on production mid to late October 2024. Thus far in 2024, there have been no additional development wells proposed.

Previous wording

We reported net income of $31.05 million, or $17.31 per share, and $19.73 million, or $11.08 per share for the six and three months ended June 30, 2024, respectively, as compared to $11.5 million, or $6.14 per share and $10.1 million, or $5.35 per share for the six and three months ended June 30, 2023, respectively. Current year net income reflects increases in production and oil commodity prices combined with lower gas and natural gas liquid commodity prices over the three and six months ended June 30, 2024. The significant components of income and expense are discussed below.

Current wording

We reported net income of $53.13 million, or $29.88 per share, and $22.10 million, or $12.63 per share for the nine and three months ended September 30, 2024, respectively, as compared to $22.22 million, or $11.95 per share and $10.72 million, or $5.84 per share for the nine and three months ended September 30, 2024, respectively. Current year net income reflects increases in production and oil commodity prices combined with lower gas and natural gas liquid commodity prices over the three and nine months ended September 30, 2024. The significant components of income and expense are discussed below.

Previous wording

The following tables summarize the primary components of production volumes and average sales prices realized for the three and six months ended June 30, 2024 and 2023 (excluding realized gains and losses from derivatives).

Current wording

The following tables summarize the primary components of production volumes and average sales prices realized for the three and nine months ended September 30, 2024 and 2023 (excluding realized gains and losses from derivatives).

Previous wording

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 consolidated statements of income. As oil and natural gas prices remain volatile, mark-to-market accounting treatment creates volatility in our revenues. Unrealized and realized losses by product are presented in the table below for the six months ended June 30, 2024 and 2023. The Company has no active derivative instruments as of the filing of this report.

Current wording

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 consolidated statements of income. As oil and natural gas prices remain volatile, mark-to-market accounting treatment creates volatility in our revenues. Unrealized and realized losses by product are presented in the table below for the nine months ended September 30, 2024 and 2023. The Company has no active derivative instruments as of the filing of this report.

Previous wording

Average oil and gas prices received for the six months ended June 30, 2024 and 2023, including the impact of derivatives were:

Current wording

Average oil and gas prices received for the nine months ended September 30, 2024 and 2023, including the impact of derivatives were:

Previous wording

Oil and gas production expense increased $4.7 million, or 60.87% to $12.4 million for the three months ended June 30, 2024 from $7.7 million for the three months ended June 30, 2023, and $8.3 million, or 62.33% to $21.6 million for the six months ended June 30, 2024 from $13.3 million for the six months ended June 30, 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.

Current wording

Oil and gas production expense increased $5.0 million, or 63.29% to $12.9 million for the three months ended September 30, 2024 from $7.9 million for the nine months ended September 30, 2023, and $13.2 million, or 62.26% to $34.4 million for the nine months ended September 30, 2024 from $21.2 million for the nine months ended September 30, 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

Production and ad valorem taxesincreased $2.3 million, or 156.09% to $3.7million for the three months ended June 30, 2024 from $1.4 million for the three months ended June 30, 2023, and $2.8 million, or 72.17% to $6.7 million for the six months ended June 30, 2024 from $3.9 million for the six months ended June 30, 2023. These increased reflect the increases in oil and natural gas liquid revenues partially offset by lower gas revenues in the related periods.

Current wording

Production and ad valorem taxesincreased $1.2 million, or 83.39% to $2.6 million for the three months ended September 30, 2024 from $1.4 million for the three months ended September 30, 2023, and $4.0 million, or 75.23% to $9.3 million for the Nine months ended September 30, 2024 from $5.3 million for the Nine months ended September 30, 2023. These increased reflect the increases in oil and natural gas liquid revenues partially offset by lower gas revenues in the related periods.

Previous wording

Field service income decreased $1.7 million or 37.14% to $2.9 million for the second quarter 2024 from $4.6 million for the second quarter 2023 and $1.8 million, or 22.15% to $6.3 million for the six months ended June 30, 2024 from $8.1 million for the six months ended June 30, 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.

Current wording

Field service income decreased $0.7 million or 20.38% to $2.6 million for the third quarter 2024 from $3.3 million for the third quarter 2023 and $2.5 million, or 21.63% to $8.9 million for the nine months ended September 30, 2024 from $11.4 million for the nine months ended September 30, 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.

Previous wording

Depreciation, depletion and amortization expense increased $13.7 million or 98.19% to $27.6 million for the six months ended June 30, 2024 from $13.9 million for the six months ending June 30, 2023 and increased $9.8 million, or 130.25% to $17.3 million for the second quarter 2024 from $7.5 million for the second quarter 2023. This increase reflects the expense related to the new wells placed on production during both quarters of 2024.

Current wording

Depreciation, depletion and amortization expense increased $22.9 million or 100.57% to $45.8 million for the nine months ended September 30, 2024, from $22.8 million for the nine months ending September 30, 2023, and increased $9.3 million, or 104.29% to $18.2 million for the third quarter 2024 from $8.9 million for the third quarter 2023. These increases reflect the expense related to the new wells placed on production during the nine months ended September 30, 2024.

Previous wording

General and administrative expense increased $1.5 million, or 28.82% to $6.9 million for the six months ended June 30, 2024 from $5.4 million for the six months ended June 30, 2023, and $ 1.6 million, or 70.18% to $3.9 million for the three months ended June 30, 2024 from $2.3 million for the three months ended June 30, 2023. This increase is primarily due to employee compensation, benefits and other corporate costs.

Current wording

General and administrative expense increased $2.8 million, or 34.34% to $10.8 million for the nine months ended September 30, 2024 from $8.1 million for the nine months ended September 30, 2023, and $ 1.2 million, or 45.28% to $3.9 million for the three months ended September 30, 2024 from $2.7 million for the three months ended September 30, 2023. This increase is primarily due to employee compensation, benefits and other corporate costs.

Previous wording

Interest expense increased $0.1 million to $0.2 million for the second quarter 2024 from $0.1 million for the second quarter 2023, and $0.2 million to $0.5 for the six months ended June 30, 2024 from $0.3 million for the six months ended June 2023. This increase reflects the higher interest and fee rates partially offset by lower current borrowings during the six months of 2024 under our revolving credit agreement.

Current wording

Interest expense increased $0.3 million to $0.4 million for the third quarter 2024 from $0.1 million for the third quarter 2023, and increased $0.4 million to $0.8 million for the nine months ended September 30, 2024 from $0.4 million for the nine months ended September 2023. This increase reflects the higher interest and fee rates combined with borrowings throughout the nine months of 2024 under our revolving credit agreement.

Previous wording

Income tax expense for the June 30, 2024 and 2023 periods varied due to the change in net income.

Current wording

Income tax expense for September 30, 2024 and 2023 periods varied due to the change in net income

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. If the borrowing base utilization percentage is less than 15% of total available borrowings, the Company is not required to enter into any hedge agreements. As of August 14, 2024, the Company is not required to enter into any hedge agreements. Additional drilling and future development plans will be established based on an expectation of available cash flows from operations and availability of funds under our revolving credit facility.

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. If the borrowing base utilization percentage is less than 15% of total available borrowings determined at the end of each quarter, the Company is not required to enter into any hedge agreements. As of November 14, 2024, the Company is not required to enter into any hedge agreements. Additional drilling and future development plans will be established based on an expectation of available cash flows from operations and availability of funds under our revolving credit facility.

Previous wording

The Company maintains a Credit Agreement providing for a reserves-based line of credit totaling $300 million, with a current borrowing base of $115 million. As of August 14, 2024, the Company’s outstanding borrowings under this line are $10 million. The bank reviews the borrowing base semi-annually and, at their 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 December 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 providing for a reserves-based line of credit totaling $300 million, with a current borrowing base of $115 million. As of November 14, 2024, the Company’s outstanding borrowings under this line are $22.1 million. The bank reviews the borrowing base semi-annually and, at their 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 December 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.

Previous wording

The Company has a stock repurchase program in place, spending under this program during the first six months of 2024 was $5.7 million. 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 during the first nine months of 2024 was $10.2 million. The Company expects continued spending under the stock repurchase program in 2024.

Previous wording

In 2023, the Company spud 58 wells, fifteen of these were completed by year-end, and the remaining 43 wells will all be complete in 2024: 22 of these were completed in the first quarter, 20 were completed in the second quarter, and one is in the process of being stimulated. Also in the second quarter of 2024, the Company participated with Double Eagle in a new well spud in May that was completed in mid-June. The Company invested approximately $27 million in the 15 wells completed in 2023, $50.6 million in the 22 wells completed in the first quarter of 2024, and $46 million in the 21 wells completed in the second quarter of 2024. All but three wells drilled in 2023 are horizontal wells drilled in West Texas, primarily in Reagan County.

Current wording

In 2023, the Company spud 58 wells, fifteen of these were completed by year-end, and the remaining 43 wells will all be complete in 2024: 22 of these were completed in the first quarter of 2024, 20 were completed in the second quarter of 2024, and one was completed in the third quarter of 2024. Also in the second quarter of 2024, the Company participated with Double Eagle in the drilling of a new well spud in May that was completed in mid-June. The Company invested approximately $27 million in the 15 wells completed in 2023, $50.6 million in the 22 wells completed in the first quarter of 2024, and $46 million in the 21 wells completed in the second quarter of 2024. All but three wells drilled in 2023 are horizontal wells drilled in West Texas, primarily in Reagan County. In the third quarter of 2024, the Company completed 12 new “Honey RF” horizontals in Reagan County, Texas in which we have 50% working interest and have invested approximately $43.6 million.

Previous wording

In March of this year the Company spud 12 “Honey RF” wells in West Texas with Double Eagle, in which the Company has 50% working interest and will invest approximately $43.5 million. These wells are being stimulated and are expected to be on production by the end of the third quarter of 2024. In addition, in the later-half of 2024, the Company anticipates drilling six three-mile-long horizontals in Upton County, Texas to be operated by Apache Corporation. In these six wells, the Company will have an average of 47.5% interest and will invest approximately $35 million.

Current wording

In addition, the Company is participating in six three-mile-long horizontals in Upton County, Texas operated by Apache Corporation that are in various stages of completion. In these six wells, the Company has an average of 47.5% interest and through completion will invest approximately $35 million.

Previous wording

On July 1st, 2024 the company sold six wells in New Mexico in exchange for future plugging liabilities. With this sale completed, the company is no longer an operator in the state of New Mexico. Also, early in the third quarter of 2024, the Company is in negotiations to sell 7.8 surface acres in Midland County, Texas for $429,000.

Current wording

On July 1st, 2024 the company sold six wells in New Mexico in exchange for future plugging liabilities. With this sale completed, the company is no longer an operator in the state of New Mexico.

Previous wording

As noted above, as of August 14 2024, the Company had $10 million in outstanding borrowings and $105,000 million in availability under this facility.

Current wording

As noted above, as of November 14, 2024, the Company had $22.1 million in outstanding borrowings and $92.9 million in availability under this facility.