# Primeenergy Resources Corp: Form 10-Q for the period ended Jun 30, 2025

- Company: [Primeenergy Resources Corp](/companies/pnrg.md) (CIK 56868)
- Form: 10-Q
- Filed: 2025-08-19
- Accepted by EDGAR: Aug 19, 2025, 20:44 ET
- Period: 2025-06-30
- Accession: 0001437749-25-027372
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/56868/000143774925027372/pnrg20250630_10q.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/56868/000143774925027372/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2025-06-30.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2025-04-01 to 2025-06-30 | $42.0m | us-gaap:Revenues |
| Revenue | 6 months, 2025-01-01 to 2025-06-30 | $92.0m | us-gaap:Revenues |
| Cost of revenue | 3 months, 2025-04-01 to 2025-06-30 | $1.2m | us-gaap:CostOfGoodsAndServicesSold |
| Cost of revenue | 6 months, 2025-01-01 to 2025-06-30 | $3.1m | us-gaap:CostOfGoodsAndServicesSold |
| Income tax | 3 months, 2025-04-01 to 2025-06-30 | $952.0k | us-gaap:IncomeTaxExpenseBenefit |
| Income tax | 6 months, 2025-01-01 to 2025-06-30 | $3.2m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2025-04-01 to 2025-06-30 | $3.2m | us-gaap:ProfitLoss |
| Net income | 6 months, 2025-01-01 to 2025-06-30 | $12.4m | us-gaap:ProfitLoss |
| Diluted EPS | 3 months, 2025-04-01 to 2025-06-30 | $1.33 | us-gaap:EarningsPerShareDiluted |
| Diluted EPS | 6 months, 2025-01-01 to 2025-06-30 | $5.07 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2025-04-01 to 2025-06-30 | $1.94 | us-gaap:EarningsPerShareBasic |
| Basic EPS | 6 months, 2025-01-01 to 2025-06-30 | $7.37 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2025-04-01 to 2025-06-30 | 2,424,723 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Diluted shares (weighted) | 6 months, 2025-01-01 to 2025-06-30 | 2,440,305 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 6 months, 2025-01-01 to 2025-06-30 | $29.9m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Share repurchases | 6 months, 2025-01-01 to 2025-06-30 | $10.0m | us-gaap:PaymentsForRepurchaseOfCommonStock |
| Cash and equivalents | at 2025-06-30 | $2.4m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2025-06-30 | $33.2m | us-gaap:AssetsCurrent |
| Total assets | at 2025-06-30 | $343.0m | us-gaap:Assets |
| Current liabilities | at 2025-06-30 | $55.3m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2025-06-30 | $137.8m | us-gaap:Liabilities |
| Long-term debt | at 2025-06-30 | $12.0m | us-gaap:LongTermDebtNoncurrent |
| Shareholders' equity | at 2025-06-30 | $205.2m | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 35,768 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 of our Annual Report.

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 it could have future value for producers in the area. 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.

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. 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. 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 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.

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.

The Company is actively developing additional 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 (9,622 net) acres, 89.3% of which is located in Reagan, Upton, Martin, and Midland counties of Texas where our current horizontal drilling activity is 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 100 additional 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 4,021 net leasehold acres in the Scoop/Stack Play.

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.

### Recent Activity

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, 2024. 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. The members of our districts consist of degreed engineers with over twenty-five years of industry experience and between ten and twenty-five years of experience managing our reserves. 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) |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| 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 |
| 2024 | 7,444 | 6,597 | 37,489 | 20,288 | 3,166 | 1,670 | 8,326 | 6,224 | 10,610 | 8,267 | 45,815 | 26,512 |

(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.

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, 2024, 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 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| 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 |
| 2024 | $389,266 | $280,595 | $111,451 | $65,030 | $500,716 | $345,626 | $72,581 | $273,045 |

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 SEC specifications and 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.

Natural gas prices, based on the twelve-month average of the first-of-the-month Henry Hub index price, were $2.13 per MMBtu in 2024 as compared to $2.64 per MMBtu in 2023 and $6.36 per MMBtu in 2022. Oil prices, based on the West Texas Intermediate (WTI) Light Sweet Crude first-of-the-month average spot price, were $75.48 per barrel in 2024 as compared to $78.22 per barrel in 2023, and $93.67 per barrel in 2022. When applying these prices to our reserves, they are further adjusted to take into consideration differentials.

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.

### District Information and Recent Activity

The following table represents certain reserves and well information as of December 31, 2024.

| Proved Reserves as of December 31, 2024 (MBoe) | Gulf Coast | Mid- Continent | West Texas | Other | Total |
| --- | ---: | ---: | ---: | ---: | ---: |
| Developed | 452 | 2,643 | 17,159 | 35 | 20,288 |
| Undeveloped | — | — | 6,224 | — | 6,224 |
| Total | 452 | 2,643 | 23,383 | 35 | 26,512 |
| Average Net Daily Production (Boe per day) | 143 | 806 | 13,749 | 9 | 14,707 |
| Gross Productive Wells (Working Interest and ORRI Wells) | 124 | 518 | 652 | 219 | 1,513 |
| Gross Productive Wells (Working Interest Only) | 73 | 359 | 543 | 75 | 1,050 |
| Net Productive Wells (Working Interest Only) | 24 | 159 | 274 | 4 | 461 |
| Gross Operated Productive Wells | 28 | 117 | 315 | — | 460 |
| Gross Operated Water Disposal, Injection and Supply wells | 4 | 38 | 6 | — | 48 |

In West Texas, we have a field service group 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, saltwater disposal facilities, and trucks we own that are operated by our field employees.

### Gulf Coast Region

Our production and development activities in the Gulf Coast region are concentrated in southeast and east Texas. This region is managed from our office in Houston, Texas. Principal producing intervals are in the Wilcox, Hackberry, and Yegua formations at depths ranging from 6,000 to 12,000 feet. We had 73 producing wells (24 net) in the Gulf Coast region as of December 31, 2024, of which 28 wells are operated by us. Average net daily production in our Gulf Coast Region at year-end 2024 was 143 Boe. At December 31, 2024, we had 452 MBoe of proved reserves in the Gulf Coast region, which represented 1.7% 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. In October of 2024, on the San Pedro Ranch in Dimmit County, Texas, we finished plugging-out all of our wells, removing all surface equipment, and reclaiming the land. With assistance from an operator in the area, we were able to do so at minimal expense to the Company. By plugging out our wells on this property we were able to extinguish a substantial amount of future plugging liability.

Currently, we are monitoring the production from a new well drilled by Ventex Operating, on acreage in the Segno field of Polk County, Texas where the Company farmed-out its 55% leasehold rights for cash and a 5.53% over-riding royalty interest (ORRI). The well was cased in February 2025 and fraced in May 2025. Currently, the well is producing approximately 1700 Mcfd along with 75 Bcpd and 130 Bwpd.

In the Segno Field of Polk County, Texas, the Wing #16 was completed in May 2025 at an estimated cost of $400,000. First gas sales occurred in June 2025. Currently, the well is producing 240 Mcfd, 3 Bcpd, and 50 Bwpd. Gulf Coast also plans to recomplete the Sarah F. Wing #80 in the Segno field of Polk County, Texas, at an expense of approximately $100,000.

### 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, 2024, we had 359 producing wells (159 net) in the Mid-Continent area, of which 117 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 2024 was 806 Boe. On December 31, 2024, we had 2,643 MBoe of proved reserves in the Mid-Continent area, representing 10% of our total proved reserves. We maintain an acreage position of approximately 45,075 gross (10,050 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 Scoop and Stack plays of Oklahoma where drilling is primarily targeting reservoirs of the Mississippian and Woodford formations. In Canadian County, Oklahoma we participated with Ovintiv Mid-Continent in drilling of two 2-mile-long horizontal wells which were spud in March 2025 and completed in May 2025. Our share of these wells are around 3.1% and the total investment will be on the order of $402,000. We have also elected to participate with Devon in Kingfisher County, Oklahoma in drilling two 2-mile-long horizontal wells which should be spud in August 2025. Our share of these wells are around 9.95% and total investment will be on the order of $1,414,000.

### West Texas Region

Our 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 June 30, 2025, we had 543 wells (274 net) in the West Texas area, of which 304 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 2024 was 13,749 Boe. On December 31, 2024, we had 23,383 MBoe of proved reserves in the West Texas area, or 88.3% of our total proved reserves. We maintain an acreage position of approximately 17,138 gross (9,622 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 eight 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.

Horizontal development of our leasehold acreage has continued at a fast pace, particularly in West Texas, where in 2024 we participated with Double Eagle, Pioneer, Civitas, and ConocoPhillips in the drilling and completion of 56 new horizontal wells targeting the Wolfcamp and Spraberry producing intervals. There are at least six pay intervals (“benches”) being developed in the Midland Basin, from the deeper Wolfcamp “D” up through the shallower Middle Spraberry. The economic variability from one area to another and from one well to another depends on geologic properties (thickness, porosity, permeability, and hydrocarbon maturity), lateral length, stimulation, and oil price, as well as the economies of scale and therefore cost advantages often achieved by the more active operators. Under our leasehold acreage in the Midland Basin, several of these benches have either never been tested, or not yet developed, however, near our acreage, some of these benches have just recently been aggressively developed. We estimate that our acreage in Reagan, Upton, and Martin counties has the potential for as many as 100 drilling locations for these benches that we believe will likely be drilled in the next several years. In particular, under our large acreage position in Reagan County, only the Wolfcamp “A” and “B” intervals have been developed so far, along with a one-well test of the Wolfcamp “D” on one block, which is encouraging. We, therefore, see significant potential for near-term development of one or more productive intervals in the Wolfcamp “D”, Jo Mill, Lower Sprabbery, and Middle Spraberry.

In 2024, the Company invested $113 million in 48 horizontals in West Texas: 47 of these are located in Reagan County and one is located in Upton County. In Reagan County, the Company joined Double Eagle in drilling and completing 33 new horizontal wells: on the “Honey RF” tract we completed 12 horizontals each being two-mile-long laterals, and participated with 50% interest investing $37 million; on the “Prime West” tract we have 50% interest in six wells and invested $20.5 million; on both the “Kramer” and “O’Bannion” tracts we participated in six horizontals, each with an average 8.3% interest and we invested approximately $7.8 million; and on the “Pink Floyd” tract we have less than 1% interest in two wells in which we invested approximately $174,900; and on our “Studley AV” tract we participated with Double eagle in testing the Wolfcamp “D” interval; in this well we have about 6.3% interest and invested approximately $600,000. Also in Reagan County, we participated with Civitas in 14 horizontal wells on the “Christi” tract, carrying an average of 39% interest and investing roughly $46.7 million. Also in 2024, in Upton County, we participated with Pioneer Natural Resources in one 2-mile-long horizontal with 3.94% interest, investing approximately $425,800. Of these 48 wells, 32 are 2-mile-long laterals, 14 are 2.5-mile-long laterals, and two are 3-mile-long laterals.

In addition to this activity, in June of 2024, we began participation with Apache in the drilling of six additional 3-mile-long laterals in Upton County on our “Mt. Moran” tract. Three of these wells were completed in late December 2024 and three were completed in January of 2025. All six new “Mt. Moran” wells are producing as of April 1, 2025. In these six Mt. Moran wells, the Company has an average of 51.16% interest and will in total invest approximately $40.5 million. In addition, in November of 2024, in Reagan County, we began participating with Double Eagle in 15 “OG” horizontal wells: eight are 2.5-mile-long laterals, and seven are 2-mile-long laterals. In each of these 15 “OG” wells the Company has approximately 23% interest and in total will invest roughly $23 million through completion of production facilities. Each of these 15 horizontals are on production as of June 1, 2025. By the end of the second quarter of 2025, therefore, the Company has invested approximately $64 million in these additional 21 horizontal wells.

In the second half of 2025, we are anticipating the start of 15 new horizontals in the Midland Basin of West Texas operated by Double Eagle on our “Full House” tract in Reagan County in which the Company will participate with approximately 27% interest and invest $30.1 million. Drilling has been completed on all 15 wells and completion is in progress as of August 1, 2025. These wells are expected to be on production late third quarter of this year. In addition to the Reagan County activity, the company is participating in eight (8) “Horseshoe” wells in Midland County with Vital Energy. Drilling activity with these wells began in the second quarter and will complete in early third quarter of 2025 with production early fourth quarter. The Company has an average of 8.2% interest in these eight (8) wells and will invest approximately $5.4 million in Midland County.

Future drilling activity on our leasehold acreage in West Texas is expected in the next few years as well. In particular, based on activity west of our acreage in Reagan County, and a recent deep test by Double Eagle on our joint leasehold, we anticipate that proposals will soon be put forward for the drilling of between 36 and 45 new horizontals that will target the Wolfcamp “D” pay zone in Reagan County and perhaps an additional test well or two in one or more of the other undeveloped pay horizons. In this future activity, we would expect to invest in excess of $100 million. In addition, the Company has identified 25 horizontal locations across our acreage in Upton and Martin counties that could be drilled in this same time frame. These additional wells will require an investment of approximately $76 million. In total, therefore, with approximately $48 million to be invested in the various wells drilling or to begin drilling in 2025, the $100 million in Wolfcamp “D” development, and the $76 million in 25 other near-term wells expected in the 2026-2027 timeframe, we anticipate investing approximately $224 million in horizontal drilling in West Texas over the next several years.

### RESULTS OF OPERATIONS

We reported net income of $12.4 million, or $7.37 basic earnings per share, and $3.2 million, or $1.94 basic earnings per share for the six and three months ended June 30, 2025, respectively, as compared to $31.1 million, or $17.31 basic earnings per share, and $19.7 million, or $11.08 basic earnings per share for the six and three months ended June 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 six months ended June 30, 2025. The significant components of income and expense are discussed below.

***Oil, gas and NGLs sales*** decreased $21.9 million, or 35.4% to $39.8 million for the three months ended June 30, 2025, from $61.7 million for the three months ended June 30, 2024, and $13.7 million, or 13.6% to $87.1 million for the six months ended June 30, 2025, from $100.7 million for the six months ended June 30, 2024. Sales vary due to changes in volumes of production sold and realized commodity prices.

The following tables summarize the primary components of production volumes and average sales prices realized for the three and six months ended June 30, 2025 and 2024 (excluding realized gains and losses from derivatives).

|  | 2025 | Six months ended June 30, 2024 | Increase / (Decrease) | Increase / (Decrease) |
| --- | ---: | ---: | ---: | ---: |
| Barrels of Oil Produced | 1,057,000 | 1,126,000 | (69,000) | (6.13)% |
| Average Price Received | $63.24 | $79.51 | $(16.27) | (20.46)% |
| Oil Revenue (In 000’s) | $66,844 | $89,533 | $(22,689) | (25.34)% |
| Mcf of Gas Sold | 4,815,000 | 2,886,000 | 1,929,000 | 66.84% |
| Average Price Received | $1.26 | $0.50 | $0.76 | 152.00% |
| Gas Revenue (In 000’s) | $6,072 | $1,440 | $4,632 | 321.67% |
| Barrels of Natural Gas Liquids Sold | 835,000 | 480,000 | 355,000 | 73.96% |
| Average Price Received | $16.94 | $20.29 | $(3.35) | (16.50)% |
| Natural Gas Liquids Revenue (In 000’s) | $14,146 | $9,739 | $4,407 | 45.25% |
| Total Oil & Gas Revenue (In 000’s) | $87,062 | $100,712 | $(13,650) | (13.55)% |

|  | 2025 | Three months ended June 30, 2024 | Increase / (Decrease) | Increase / (Decrease) |
| --- | ---: | ---: | ---: | ---: |
| Barrels of Oil Produced | 600,000 | 695,000 | (95,000) | (13.67)% |
| Average Price Received | $56.96 | $80.91 | $(23.95) | (29.60)% |
| Oil Revenue (In 000’s) | $34,178 | $56,234 | $(22,056) | (39.22)% |
| Mcf of Gas Sold | 2,424,000 | 1,729,000 | 695,000 | 40.20% |
| Average Price Received | $0.02 | $0.05 | $(0.03) | (64.54)% |
| Gas Revenue (In 000’s) | $43 | $82 | $(39) | (47.56)% |
| Barrels of Natural Gas Liquids Sold | 381,000 | 274,000 | 107,000 | 39.05% |
| Average Price Received | $14.74 | $19.61 | $(4.87) | (24.82)% |
| Natural Gas Liquids Revenue (In 000’s) | $5,617 | $5,374 | $243 | 4.52% |
| Total Oil & Gas Revenue (In 000’s) | $39,838 | $61,690 | $(21,852) | (35.42)% |

14

***Oil and gas production expense*** decreased $2.3 million, or 18.5% to $10.1 million for the three months ended June 30, 2025 from $12.4 million for the three months ended June 30, 2024, and $1.8 million, or 8.4% to $19.7 million for the six months ended June 30, 2025 from $21.5 million for the six months ended June 30, 2024. These changes reflect costs related to the new wells that have been placed on production offset by cost savings related to wells that have been plugged.

***Production and ad valorem taxes*** decreased $1.9 million, or 51.4% to $1.8 million for the three months ended June 30, 2025 from $3.7 million for the three months ended June 30, 2024, and $1.6 million, or 23.9% to $5.1 million for the six months ended June 30, 2025 from $6.7 million for the six months ended June 30, 2024. These decreases reflect the changes in oil, natural gas and natural gas liquids revenues in the related periods.

***Field service income*** decreased $0.9 million or 31.0% to $2.0 million for the three months ended June 30, 2025 from $2.9 million for the three months ended June 30, 2024 and $2.2 million, or 34.9% to $4.1 million for the six months ended June 30, 2025 from $6.3 million for the six months ended June 30, 2024. Workover rig services and hot oil treatments represent the bulk of our field service operations. These changes reflect the sale of our South Texas service company in Q3 2024.

***Field service expense*** decreased $1.3 million or 52.0% to $1.2 million for the three months ended June 30, 2025 from $2.5 million for the three months ended June 30, 2024 and $2.2 million, or 41.5% to $3.1 million for the six months ended June 30, 2025 from $5.3 million for the six months ended June 30, 2024. Field service expenses primarily consist of wages and vehicle operating expenses. These changes reflect the sale of our South Texas service company in Q3 2024.

***Depreciation, depletion and amortization expense*** increased $3.5 million or 20.2% to $20.8 million for the three months ended June 30, 2025 from $17.3 million for the three months ended June 30, 2024 and increased $13.5 million, or 48.9% to $41.1 million for the six months ended June 30, 2025 from $27.6 million for the six months ended June 30, 2024. This increase is due to an increase in production volumes added from new wells being placed on-line since June 30, 2024, and due to changes in the overall depletion rate resulting from the costs of these wells being added to the depletion base plus revisions to overall reserves in place.

***General and administrative expense*** decreased $0.9 million or 23.1% to $3.0 million for the three months ended June 30, 2025 from $3.9 million for the three months ended June 30, 2024 and decreased $1.0 million, or 14.5% to $5.9 million for the six months ended June 30, 2025 from $6.9 million for the six months ended June 30, 2024. These changes are primarily due to lower employee compensation, benefits and other corporate costs.

***Interest expense*** increased $0.5 million or 250.0% to $0.7 million for the three months ended June 30, 2025 from $0.2 million for the three months ended June 30, 2024 and increased $0.8 million, or 160.0% to $1.3 million for the six months ended June 30, 2025 from $0.5 million for the six months ended June 30, 2024.This increase reflects the higher borrowings during the six months of 2025 under our revolving credit agreement.

***Income tax expense*** for the June 30, 2025 and 2024 periods varied due to the change in net income.

### LIQUIDITY AND CAPITAL RESOURCES

The Company’s goal is to responsibly develop its oil and gas reserves, predominantly through horizontal drilling. Our 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. For 2025, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2025 capital budget is reflective of commodity prices and has been established based on an expectation of available cash flows, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility. 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.

The Company’s horizontal development activities in the last two years, along with our projected activity for 2025, can be summarized as follows: in 2023 we invested $96 million in 35 horizontals, in 2024 we invested $113 million in 48 horizontals, and in 2025, we expect to invest $98 million in 44 horizontals as discussed under district information and recent activity. Therefore, in total, since January 2023 and through 2025, the Company will have invested roughly $307 million in horizontal development, primarily in the Midland Basin of West Texas.

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 August 14, 2025, 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 $115 million. As of August 14, 2025, there were no outstanding borrowings under this line. 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 new borrowing base review is currently in progress and no change in the borrowing base is expected. 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 commodity 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 natural gas prospects available, the market for oilfield services, and oil and natural gas business opportunities in general.

## Controls and procedures

As filed, 1,144 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 since the last quarter of 2025 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Filed Aug 19, 2025.
Source: SEC EDGAR, the filing index for accession 0001437749-25-027372. Last ingested by Listed: Oct 24, 2026, 14:53 ET. No prices; not investment advice.