# Primeenergy Resources Corp: Form 10-Q for the period ended Mar 31, 2024

- Company: [Primeenergy Resources Corp](/companies/pnrg.md) (CIK 56868)
- Form: 10-Q
- Filed: 2024-05-17
- Accepted by EDGAR: May 17, 2024, 20:06 ET
- Period: 2024-03-31
- Accession: 0001437749-24-017481
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/56868/000143774924017481/pnrg20230930_10q.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/56868/000143774924017481/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2024-03-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2024-01-01 to 2024-03-31 | $43.0m | us-gaap:Revenues |
| Cost of revenue | 3 months, 2024-01-01 to 2024-03-31 | $2.8m | us-gaap:CostOfGoodsAndServicesSold |
| Interest expense | 3 months, 2024-01-01 to 2024-03-31 | $215.0k | us-gaap:InterestExpenseNonoperating |
| Income tax | 3 months, 2024-01-01 to 2024-03-31 | $3.0m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2024-01-01 to 2024-03-31 | $11.3m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2024-01-01 to 2024-03-31 | $4.41 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2024-01-01 to 2024-03-31 | $6.27 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2024-01-01 to 2024-03-31 | 2,565,951 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 3 months, 2024-01-01 to 2024-03-31 | $43.2m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Share repurchases | 3 months, 2024-01-01 to 2024-03-31 | $2.8m | us-gaap:PaymentsForRepurchaseOfCommonStock |
| Cash and equivalents | at 2024-03-31 | $1.8m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2024-03-31 | $32.1m | us-gaap:AssetsCurrent |
| Total assets | at 2024-03-31 | $332.9m | us-gaap:Assets |
| Current liabilities | at 2024-03-31 | $88.5m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2024-03-31 | $163.5m | us-gaap:Liabilities |
| Long-term debt | at 2024-03-31 | $4.0m | us-gaap:LongTermDebtNoncurrent |
| Shareholders' equity | at 2024-03-31 | $169.4m | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 46,102 characters.

The following discussion is intended to assist you in understanding our results of operations and our present financial condition. Our Condensed Consolidated Financial Statements and the accompanying Notes to the Condensed Consolidated Financial Statements included elsewhere in this Report contain additional information that should be referred to when reviewing this material. Our subsidiaries are listed in Note 1 to the Consolidated Financial Statements.

### OVERVIEW

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.

In addition to developing our oil and natural gas reserves, we continue to actively pursue the acquisition of producing properties. We attempt to assume the position of operator in all acquisitions of producing properties and will continue to evaluate properties for leasehold acquisition and for exploration and development in areas in which we operate. To diversify and broaden our asset base, we will consider acquiring the assets or stock in other entities in the oil and gas business. Our main objective in making any such acquisitions will be to acquire income-producing assets or developable leasehold acreage to build stockholder value.

Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisition and drilling activities, and the operational performance of our producing properties. On occasion, we will use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of increases in oil and gas prices above the maximum fixed amount specified in the derivative agreements and subjects us to the credit risk of the counterparties to such agreements. When used our derivative contracts are accounted for under mark-to-market accounting and we can expect volatility in gains and losses on contracts in our consolidated statement of operations as changes occur in the NYMEX price indices. We currently have no derivative contracts and do not intend to enter into future derivative contracts unless required to do so for our bank line of credit, or we believe we would significantly benefit from near term price stability.

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.

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.

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 16,407 gross (9,341 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 (10,137 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 43 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 $33 million at an average 10% ownership level.

Future development plans are established based on various factors, including the expectation of available cash flows from operations and the availability of funds under our revolving credit facility.

### District Information

The following table represents certain reserves and well information as of December 31, 2023.

| Proved Reserves as of December 31, 2023 (MBoe) | Gulf Coast | Mid- Continent | West Texas | Other | Total |
| --- | ---: | ---: | ---: | ---: | ---: |
| Developed | 563 | 2,210 | 10,778 | 7 | 13,558 |
| Undeveloped | — | — | 15,488 | — | 15,488 |
| Total | 563 | 2,210 | 26,266 | 7 | 29,046 |
| Average Net Daily Production (Boe per day) | 173 | 831 | 6,172 | 4 | 7,181 |
| Gross Productive Wells (Working Interest and ORRI Wells) | 114 | 511 | 647 | 222 | 1,494 |
| Gross Productive Wells (Working Interest Only) | 72 | 361 | 541 | 144 | 1,118 |
| Net Productive Wells (Working Interest Only) | 21 | 132 | 275 | 5 | 433 |
| Gross Operated Productive Wells | 28 | 128 | 334 | — | 490 |
| Gross Operated Water Disposal, Injection and Supply wells | 5 | 39 | 8 | — | 52 |

In several 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.

### Gulf Coast Region

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. As of March 31, 2023, 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.

### Mid-Continent Region

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. Average net daily production in our Mid-Continent Region in 2023 was 831 Boe. At 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 (10,137 net) acres in this region, primarily in Canadian, Kingfisher, Grant, 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.

### West Texas Region

Our 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. Average net daily production in Our West Texas Region at year-end 2023 was 6,172 Boe. At 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 16,407 gross (9,341 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.

As of March 31, 2024, the Company was participating in the drilling or completion of 34 horizontal wells in Reagan County, Texas with an average of 39% interest in 14 wells, 8.3% in 12 wells, 50% in six wells and less than 1% in two wells. Combined, we expect to spend approximately $80 million in these horizontals and their associated facilities. Twenty-eight of these 34 wells and their forecast reserves are included in the 2023 year-end reserve report as proved undeveloped, whereas the reserves of six wells are considered probable undeveloped and not included in the reserve report. Additionally, we have 12 horizontals slated to begin drilling in the second quarter of 2024 and be on production in the third quarter.

In 2024, we expect to complete 54 new horizontal wells, investing approximately $140 million. We are also preparing to invest approximately $95 million in another 23 horizontal wells to be drilled and completed in 2025. In addition, we have identified 28 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 $67 million.

### Reserves

All of our interests in proved developed and undeveloped oil and gas properties have been evaluated by Ryder Scott Company, L.P. for each of the three years ended December 31, 2023. The professional qualifications of the technical persons primarily responsible for overseeing the preparation of the reserve estimates can be found in Exhibit 99.1, the Ryder Scott Company, L.P. Report on Registrant’s Reserves Estimates. In matters related to the preparation of our reserve estimates, our district managers report to the Engineering Data manager, who maintains oversight and compliance responsibility for the internal reserve estimate process and provides oversight for the annual preparation of reserve estimates of 100% of our year-end reserves by our independent third-party engineers, Ryder Scott Company, L.P. The members of our districts consist of degreed engineers and geologists with over twenty-five years of industry experience and between ten and twenty-five years of experience managing our reserves. Our Engineering Data manager, the technical person primarily responsible for overseeing the preparation of reserves estimates, has over thirty years of experience, holds a Bachelor degree in Geology and an MBA in finance and is a member of the Society of Petroleum Engineers and American Association of Petroleum Geologist. All of our reserves are located within the continental United States. The following table summarizes our oil and gas reserves at each of the respective dates:

| As of December 31, | Reserve Category Proved Developed Oil (MBbls) | NGLs (MBbls) | Gas (MMcf) | Total (MBoe) | Proved Undeveloped Oil (MBbls) | NGLs (MBbls) | Gas (MMcf) | Total (MBoe) | Total Oil (MBbls) | NGLs (MBbls) | Gas (MMcf) | Total (MBoe) |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| 2021 | 5,386 | 2,882 | 23,902 | 12,252 | — | — | — | — | 5,386 | 2,882 | 23,902 | 12,252 |
| 2022 | 4,143 | 2,497 | 22,277 | 10,353 | 3,028 | 1,833 | 9,030 | 6,366 | 7,171 | 4,330 | 31,307 | 16,719 |
| 2023 | 5,757 | 3,676 | 24,749 | 13,558 | 6,254 | 5,156 | 24,470 | 15,488 | 12,011 | 8,832 | 49,219 | 29,046 |

(a) In computing total reserves on a barrels of oil equivalent (Boe) basis, gas is converted to oil based on its relative energy content at the rate of six Mcf of gas to one barrel of oil and NGLs are converted based upon volume; one barrel of natural gas liquids equals one barrel of oil.

During 2021, in West Texas, we participated with Apache in the drilling of three additional horizontals on the Kashmir Tract in Upton County, Texas and completed these three wells in September of 2021 along with six other wells drilled in 2020 on the same lease that were drilled but uncompleted at year-end. The Company has an average of 47.8% interest in these nine wells and invested approximately $30 million in these horizontal wells. Also in 2021, the Company participated with Ovintiv Mid-Continent for 11.25% interest in four two-mile horizontal wells in Canadian County, Oklahoma. Twelve of these thirteen horizontal wells were successfully completed and placed into production in the fourth quarter of 2021. One of the Ovintiv wells had a casing leak issue and has been temporarily abandoned. The Company invested approximately $32 million in these thirteen wells. In addition, in 2021, the Company added minor reserves through over-riding royalty interest in two wells drilling and completed in Grady County, Oklahoma.

At December 31, 2021, the Company had 159 Mboe of proved developed shut-in reserves attributable to three horizontals drilled and completed in Canadian County, Oklahoma, but not yet online at year-end. These reserves were converted to proved producing in the first quarter of 2022. At year-end 2021, we did not include proved undeveloped reserves in our reserve report because we had not yet received definitive drilling proposals from third-party operators for the more than fifteen horizontal wells that we planned to participate in located primarily in West Texas.

In 2022, the Company participated in eight horizontal wells that were drilled and completed; four located in Irion County, West Texas, operated by SEM Operating Company, in which we have 10.13% interest, and four located in Canadian County, Oklahoma, operated by Ovintiv Mid-Continent, Inc., in which we have an average 9% interest. Our investment in these eight wells was approximately $4 million and all were brought on production in August of 2022. In addition, the Company added reserves through 15 wells in which we have various minor over-riding royalty interest. Eight of these wells are located in West Texas and seven are located in Oklahoma.

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.

At year-end 2022, the Company had 6,366 Mboe of proved undeveloped reserves attributable to the 25 horizontal wells described above.

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.

At year-end 2023, the Company had 15,488 MBOE of proved undeveloped reserves that are attributable to 52 undeveloped wells, 28 of which were in the process of being drilled or completed at year-end.

The estimated future net revenue (using current prices and costs as of those dates) and the present value of future net revenue (at a 10% discount for estimated timing of cash flow) for our proved developed and proved undeveloped oil and gas reserves at the end of each of the three years ended December 31, 2023, are summarized as follows (in thousands of dollars):

| As of December 31, | Proved Developed Future Net Revenue | Present Value 10 Of Future Net Revenue | Proved Undeveloped Future Net Revenue | Present Value 10 Of Future Net Revenue | Total Future Net Revenue | Present Value 10 Of Future Net Revenue | Present Value 10 Of Future Income Taxes | Standardized Measure of Discounted Cash flow |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| 2021 | $275,227 | $171,906 | $— | $— | $275,227 | $171,906 | $36,100 | $135,806 |
| 2022 | $320,146 | $192,688 | $200,790 | $118,081 | $520,936 | $310,769 | $66,233 | $244,536 |
| 2023 | $314,415 | $213,281 | $253,959 | $138,679 | $568,374 | $351,960 | $73,912 | $278,048 |

The PV10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income tax, discounted at 10%. Although this measure is not in accordance with U.S. generally accepted accounting principles (“GAAP”), we believe that the presentation of the PV10 Value is relevant and useful to investors because it presents the discounted future net cash flow attributable to proved reserves prior to taking into account corporate future income taxes and the current tax structure. We use this measure when assessing the potential return on investment related to oil and gas properties. The PV10 of future income taxes represents the sole reconciling item between this non-GAAP PV10 Value versus the GAAP measure presented in the standardized measure of discounted cash flow. A reconciliation of these values is presented in the last three columns of the table above. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to proved oil and natural gas reserves after income tax, discounted at 10%.

“Proved developed” oil and gas reserves are reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. “Proved undeveloped” oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

In accordance with U.S. generally accepted accounting principles, product prices are determined using the twelve-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month, adjusted for oilfield or gas gathering hub and wellhead price differentials (e.g. grade, transportation, gravity, sulfur, and basic sediment and water) as appropriate. Also, in accordance with SEC specifications and U.S. generally accepted accounting principles, changes in market prices subsequent to December 31 are not considered.

While it may be reasonably anticipated that the prices received for the sale of our production may be higher or lower than the prices used in this evaluation, as described above, and the operating costs relating to such production may also increase or decrease from existing levels, such possible changes in prices and costs were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation for the SEC case. Actual volumes produced, prices received and costs incurred may vary significantly from the SEC case.

Natural gas prices, based on the twelve-month average of the first of the month Henry Hub index price, were $2.64 per MMBtu in 2023 as compared to $6.36 per MMBtu in 2022 and $3.60 per MMBtu in 2021. Oil prices, based on the West Texas Intermediate (WTI) Light Sweet Crude first of the month average spot price, were $78.22 per barrel in 2023 as compared to $93.67 per barrel in 2022, and $66.56 per barrel in 2021. Since January 1, 2023, we have not filed any estimates of our oil and gas reserves with, nor were any such estimates included in any reports to, any federal authority or agency, other than the Securities and Exchange Commission.

### RECENT ACTIVITIES

The Company’s activities include development and exploratory drilling. Our strategy is to develop the Company’s extensive oil and gas reserves primarily through horizontal drilling. This strategy includes targeting reservoirs with high initial production rates and cash flow as well as targeting reservoirs with lower initial production rates but with higher expected return on investment. We believe that with today’s technology, horizontal development of our reserves provides superior economic results as compared to vertical development, by delivering higher production rates through greater contact and stimulation of a larger volume of reservoir rock while minimizing the surface footprint required to develop those same reserves.

Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. In 2024, we will continue our focus on preserving financial flexibility and liquidity as we manage the risks facing our industry. Our capital budget for the year is reflective of current 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. As we have done historically to preserve or enhance liquidity, we may adjust our capital program throughout the year, divest non-strategic assets, or enter into strategic joint ventures.

Horizontal development of our leasehold acreage has continued at a fast pace, particularly in West Texas, where in 2023 we participated with Double Eagle, Apache, Civitas, and ConocoPhillips in the drilling and completion of 32 new horizontal wells and in 2024 we are on track to complete 54 new horizontal wells. In Oklahoma, in 2023, we participated with Ovintiv MidContinent with a minor interest in three 3-mile-long horizontal laterals.

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 in Oklahoma. In total, including the cost of facilities, the Company invested approximately $91 million in these wells, 99% of which is attributable to the wells in West Texas where we have been targeting proven pay intervals in the Wolfcamp and Spraberry formations.

In Reagan County, in 2023, we participated with Hibernia Energy II (Now Civitas) in ten 2-mile-long horizontals having 25% interest and investing $25.6 million in our “Brynn” wells that began production in April 2023. Also in Reagan County, we participated with DE IV, LLC (Double Eagle) in 15 horizontals: five 2-mile-long laterals in which we have nearly 50% interest, called the “Prime East” wells that were placed on production in May 2023, another six 2-mile-long laterals in which we have 7% interest, our “Studley AV” wells, that were brought on production in December 2023, and four 2.5-mile laterals with 20% interest, part of our “Studley CKO” wells, that were completed in December 2023 but not put online until January 2024. All twelve Studley CKO wells were brought on production in January 2024 and were included in the 2023 year-end reserve report as proved developed non-producing.

Also in 2023, in Upton County, Texas we participated for 50% interest in two 3-mile-long horizontals operated by Apache. These wells were brought into production in October 2023 and we invested approximately $17 million in these wells and their associated facilities. In Martin County, Texas we participated with ConocoPhillips for 20.8% interest in five 2.5-mile-long horizontal laterals, investing approximately $12 million. These five wells were completed and brought online in September 2023. Also in 2023, in Oklahoma, the Company joined Ovintiv USA, Inc. in the drilling of three 3-mile-long horizontals located in Canadian County with 2% interest, invested approximately $645,000.

In the first quarter of 2024, in Reagan County, Texas, with Double Eagle, we have completed eight “Studley CKO” 2.5-mile horizontals with an average 19.7% interest, investing $15.5 million, as well as three O’Bannon horizontals with 8.2% interest and two Pink Floyd horizontals with less than 1% interest. These five are also 2.5-mile-long laterals and we have invested approximately $2.6 million in them. With Civitas Resources an additional nine 2-mile-long horizontals were completed in the first quarter. In these “Christi” wells we have approximately 40% working interest and invested $29 million. All 12 Studley CKO wells were brought into production in the first quarter.

In the Second Quarter of 2024, as of the writing of this report, 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 brough 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 are in the process of being stimulated and are expected to be on production later in the second quarter. In April of this year, also with Double Eagle, the Company spud 12 new wells in Reagan County, Texas. In these “Honey RF” wells the Company has 50% working interest and will invest approximately $43.5 million. We expect these wells to be finished with completion and be brought on production in the third quarter of 2024.

Also in 2024, we have added plans to drill a 2-mile-long horizontal well in Reagan County, Texas that will target the Wolfcamp “D” interval which is promising but has had few production tests. We will have approximately 6% interest in this initial well, but if successful in establishing economically viable reserves from this interval it would potentially set-up development of as many as 25 additional horizontals on our acreage in Reagan County. In these wells the Company would have a range of interest from 6% to 50% that will average approximately 26% and require future investment of approximately $65 million.

In total, in 2024, we expect to complete 54 new horizontal wells, investing approximately $140 million. We are also preparing to invest approximately $95 million in another 23 horizontal wells to be drilled partially this year and completed in 2025. In addition, we have identified 28 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 $67 million. In total, we are planning to invest in excess of $300 million in horizontal development in West Texas over the next several years.

In the Permian Basin of West Texas and eastern New Mexico, we maintain an acreage position of approximately 16,407 gross (9,341 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.

In Oklahoma, we are focused on the development of our reserves in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have approximately 4,113 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 43 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 13 newly drilled wells in 2023, we chose to farm-out our interest and own an over-riding-royalty interest in these wells.

### RESULTS OF OPERATIONS

We reported net income of $11.3 million, $6.27 per share, for the three months ended March 2024 compared with $1.4 million, $0.75 per share, for the same period of 2023. The current year net income reflects changes in oil, gas and NGLs sales related to increases in production combined with slightly increased oil commodity prices and lower gas and natural gas liquid commodity prices. The significant components of income and expense are discussed below.

***Oil, gas and NGLs sales*** increased 108.4% to $39 million for the three months ended March 2024 from $18.7 million in the same period of 2023. Sales vary due to changes in volumes of production sold and realized commodity prices. Our oil production increased due to the additional West Texas wells added in the second half of 2023 and the new wells added in the first quarter of 2024. The changes in volumes and prices are presented in the table below. The following table summarizes the primary components of production volumes and average sales prices realized for the three months ended March 31, 2024 and 2023 (excluding realized gains and losses from derivatives).

|  | 2024 | Three Months Ended March 31, 2023 | Increase / (Decrease) | Increase / (Decrease) |
| --- | ---: | ---: | ---: | ---: |
| Barrels of Oil Produced | 431,000 | 193,351 | 237,649 | 122.91% |
| Average Price Received | $77.26 | $75.40 | $1.86 | 2.47% |
| Oil Revenue (In 000’s) | $33,299 | $14,578 | $18,721 | 128.42% |
| Mcf of Gas Sold | 1,157,000 | 801,084 | 355,916 | 44.43% |
| Average Price Received | $1.17 | $2.19 | $(1.02) | (46.58)% |
| Gas Revenue (In 000’s) | $1,358 | $1,752 | $(394) | (22.49)% |
| Barrels of Natural Gas Liquids Sold | 206,000 | 105,825 | 100,175 | 94.66% |
| Average Price Received | $21.19 | $22.62 | $(1.43) | (6.32)% |
| Natural Gas Liquids Revenue (In 000’s) | $4,365 | $2,394 | $1,971 | 82.33% |
| Total Oil & Gas Revenue (In 000’s) | $39,022 | $18,724 | $20,298 | 108.41% |

***Gains or Losses on derivative instruments*** 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. 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 three months ended March 31, 2024 and 2023. The Company has no active derivative instruments as of the filing of this report.

|  | 2024 | 2023 |
| --- | ---: | ---: |
| Oil derivatives – gains, net | $- | $179 |
| Natural gas derivatives – gains, net | - | 235 |
| Total gains on oil and natural gas derivatives | $- | 414 |

Average oil and gas prices received for the three months ended March 31, including the impact of derivatives were:

|  | 2024 | 2023 |
| --- | ---: | ---: |
| Average sales prices per barrel of oil | $77.26 | $76.32 |
| Average sales prices per MCF of gas | $1.17 | $2.48 |
| Average sales price Natural Gas Liquids | $21.19 | $22.62 |

***Oil and Gas, production and ad valoreum taxes*** increased $4.1 million or 51.2% from $8 million for the first quarter 2023 to $12.1 million for the first quarter 2024. The change in the overall expenses is reflective of the increase in production costs due to the additional West Texas wells added in the second half of 2023 and the new wells added in the first quarter of 2024.

***Field service income*** decreased $0.1 million or 2.16% for the first quarter 2024 to $3.4 million from $3.5 million for the first quarter 2023 reflects no changes in the current utilization of the field equipment.

***Field service expense*** decreased $0.4 million or 11.6% to $2.8 million for the first quarter 2024 from $3.2 million for the first quarter 2023 due to streamlined overhead operations.

***Depreciation, depletion and amortization*** increased $3.9 million or 60.7% from $6.4 million for the first quarter 2023 to $10.3 million for the first quarter 2024 reflecting the increase production and basis due to the additional West Texas wells added in the second half of 2023 and the new wells added in the first quarter of 2024.

***General and administrative expense*** decreased $0.05 million or 1.5% from $3.1 million for the three months ended March 31, 2024 to $3.05 million for the three months ended March 31, 2024. The costs associated with this caption period remained unchanged.

***Interest expense*** increased $0.03 million or 18.1% from $0.18 million for the first quarter 2023 to $0.21 million for the first quarter 2024. This increase reflects the company’s current borrowings applied to higher interest rates under our revolving credit agreement.

***Income tax expense*** for the March 31, 2024 and 2023 quarters varied due to the change in net income.

### LIQUIDITY AND CAPITAL RESOURCES

Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. For 2024, we will continue our focus on preserving financial flexibility and ample 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. 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.

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.

Our realized oil and gas prices vary due to world political events, supply and demand of products, product storage levels, and weather patterns. We sell the majority of our production at spot market prices. Accordingly, product price volatility will affect our cash flow from operations. To mitigate price volatility, we sometimes lock in prices for some portion of our production through the use of derivatives.

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 May 10, 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.

The Company maintains a Credit Agreement providing for a reserves-based line of credit totaling $300 million, with a current borrowing base of $85 million. As of May 15, 2024, the Company’s outstanding borrowings under this line are $2 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 June 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.

The majority of our capital spending is discretionary, and the ultimate level of expenditures will be dependent on our assessment of the oil and gas business environment, the number and quality of oil and gas prospects available, the market for oilfield services, and oil and gas business opportunities in general.

The Company has a stock repurchase program in place, spending under this program during the first quarter of 2024 was $2.85 million. The Company expects continued spending under the stock repurchase program in 2024.

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. Horizontal development of our resource base provides superior returns relative to vertical development due to the ability of each horizontal wellbore to come in contact with a greater volume of reservoir rock across a greater distance, more efficiently draining the reserves with less infrastructure and thus at a lower cost per acre.

In 2023, including 20 wells spud in the fourth quarter of 2023, the Company participated in the drilling of 35 horizontal wells with five operators, 32 of which are located in West Texas and three located in Oklahoma. The Company invested approximately $91 million in these wells and their production facilities, nearly all of which was toward the drilling and completions of the wells in West Texas where we are focused on horizontal drilling of proven pay intervals in the Wolfcamp and Spraberry formations.

On December 31, 2023, we had 12 wells completed that were brought into production in January of 2024. In addition to the $7.9 million invested in these 12 wells in 2023, the Company invested an additional $15.5 million in 2024. Also at the start of 2024, the Company was in the process of drilling and completing 34 wells in West Texas that carry an expense of $80.6 million, and we are planning to participate for 50% 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 this year and, in 2025, to invest $95 million in an additional 23 wells in West Texas.

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 the first two quarters of 2024, the Company has sold 60 net acres in Lea County, New Mexico, along with minor working interest in 23 wells, receiving gross proceeds of $526,200.

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.

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.

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.

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 in outstanding borrowings and $81 million in availability under this facility.

In the first quarter of 2024, the Company sold 48 net acres in Lea County, New Mexico, along with minor working interest in 23 wells, receiving gross proceeds of $375,600, and early in the second quarter of 2024, the Company sold an additional 12 net acres in Lea County for proceeds of $150,600.

## Controls and procedures

As filed, 1,151 characters.

As of the end of the current reported period covered by this report, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934 (the “Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission’s rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.

There were no changes in the Company’s internal control over financial reporting that occurred during the first three months of 2024 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Filed May 17, 2024.
Source: SEC EDGAR, the filing index for accession 0001437749-24-017481. Last ingested by Listed: Oct 24, 2026, 14:53 ET. No prices; not investment advice.