# Ring Energy, Inc.: Form 10-Q for the period ended Jun 30, 2025

- Company: [Ring Energy, Inc.](/companies/rei.md) (CIK 1384195)
- Form: 10-Q
- Filed: 2025-08-06
- Accepted by EDGAR: Aug 6, 2025, 16:51 ET
- Period: 2025-06-30
- Accession: 0001628280-25-038401
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1384195/000162828025038401/rei-20250630.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1384195/000162828025038401/

## 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 | $82.6m | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Revenue | 6 months, 2025-01-01 to 2025-06-30 | $161.7m | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Operating income | 3 months, 2025-04-01 to 2025-06-30 | $23.5m | us-gaap:OperatingIncomeLoss |
| Operating income | 6 months, 2025-01-01 to 2025-06-30 | $45.8m | us-gaap:OperatingIncomeLoss |
| Interest expense | 3 months, 2025-04-01 to 2025-06-30 | $11.8m | us-gaap:InterestExpenseNonoperating |
| Interest expense | 6 months, 2025-01-01 to 2025-06-30 | $21.3m | us-gaap:InterestExpenseNonoperating |
| Income tax | 3 months, 2025-04-01 to 2025-06-30 | $6.1m | us-gaap:IncomeTaxExpenseBenefit |
| Income tax | 6 months, 2025-01-01 to 2025-06-30 | $9.1m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2025-04-01 to 2025-06-30 | $20.6m | us-gaap:NetIncomeLoss |
| Net income | 6 months, 2025-01-01 to 2025-06-30 | $29.7m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2025-04-01 to 2025-06-30 | $0.10 | us-gaap:EarningsPerShareDiluted |
| Diluted EPS | 6 months, 2025-01-01 to 2025-06-30 | $0.15 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2025-04-01 to 2025-06-30 | $0.10 | us-gaap:EarningsPerShareBasic |
| Basic EPS | 6 months, 2025-01-01 to 2025-06-30 | $0.15 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2025-04-01 to 2025-06-30 | 206,982,327 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Diluted shares (weighted) | 6 months, 2025-01-01 to 2025-06-30 | 204,085,207 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 6 months, 2025-01-01 to 2025-06-30 | $61.7m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Cash and equivalents | at 2025-06-30 | $0 | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2025-06-30 | $62.4m | us-gaap:AssetsCurrent |
| Total assets | at 2025-06-30 | $1.52bn | us-gaap:Assets |
| Current liabilities | at 2025-06-30 | $98.3m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2025-06-30 | $618.4m | us-gaap:Liabilities |
| Shareholders' equity | at 2025-06-30 | $897.9m | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 49,799 characters.

The following discussion and analysis should be read in conjunction with our accompanying condensed financial statements and the notes to those condensed financial statements included elsewhere in this Quarterly Report. The following discussion includes forward-looking statements that reflect our plans, estimates and beliefs and our actual results could differ materially from those discussed in these forward-looking statements as a result of many factors, including those discussed under “Risk Factors,” "Forward Looking Statements" and elsewhere in this Quarterly Report.

### Overview

Ring Energy, Inc. (the "Company," "Ring," "we," "us," "our" and similar terms) is a growth oriented independent oil and natural gas exploration and production company based in The Woodlands, Texas engaged in oil and natural gas development, production, acquisition, and exploration activities currently focused in the Permian Basin in Texas. Our primary drilling operations target the oil and liquids rich producing formations in the Northwest Shelf and the Central Basin Platform, both of which are part of the Permian Basin.

### Business Description and Plan of Operation

The Company is focused on balancing the need to reduce long-term debt and further developing our oil and gas properties to maintain or grow our annual production. We intend to achieve both through proper allocation of cash flow generated by our operations and potentially through the sale of non-core assets. We intend to continue evaluating potential transactions to acquire strategic producing assets with attractive acreage positions that can provide competitive returns for our stockholders.

- *Growing production and reserves by developing our oil-rich resource base through conventional and horizontal drilling*. In an effort to maximize its value and resources potential, Ring intends to drill and develop its acreage base in both the Northwest Shelf and Central Basin Platform, allowing Ring to execute on its plan of operating within its generated cash flow.
- *Reduction of long-term debt and deleveraging of asset.* Ring intends to reduce its long-term debt primarily through the use of excess cash flow and potentially through the sale of non-core assets. The Company believes that with its attractive field level margins, it is positioned to maximize the value of its assets and deleverage its balance sheet. The Company also believes through potential accretive acquisitions and strategic asset dispositions, it can accelerate the strengthening of its balance sheet.
- *Employ industry leading drilling and completion techniques.* Ring’s executive team intends to utilize new and innovative technological advancements for completion optimization, comprehensive geological evaluation, and reservoir engineering analysis to generate value and to build future development opportunities. These technological advancements have led to a low-cost structure that helps maximize the returns generated by our drilling programs.
- *Pursue strategic acquisitions with attractive upside potential.* Ring has a history of acquiring leasehold positions that it believes to have additional resource potential that meet its targeted returns on invested capital and comparable to its existing inventory of drilling locations. We pursue an acquisition strategy designed to increase reserves at attractive finding costs and complement existing core properties. Management intends to continue to pursue strategic acquisitions and structure the potential transactions financially, so they improve our balance sheet metrics and are accretive to stockholders. Our executive team, with its extensive experience in the Permian Basin, has many relationships with operators and service providers in the region.

### 2025 Developments and Highlights

### Lime Rock Acquisition

On March 31, 2025, the Company, as buyer, and Lime Rock Resources IV-A, L.P. (“LRRA”), and Lime Rock Resources IV-C, L.P. (“LRRC” and with LRRA, “Lime Rock”), as seller, consummated the transactions contemplated in that certain Purchase and Sale Agreement dated February 25, 2025, by and among the Company, LRRA and LRRC (the “Purchase Agreement”) that was previously reported on Form 8-K filed on February 28, 2025 with the Securities and Exchange Commission (“SEC”). At the closing of the Purchase Agreement, among other things, the Company acquired (the “Lime Rock Acquisition”) interests in oil and gas leases and related property of Lime Rock located in Andrews County, Texas, for an aggregate purchase price (the “Purchase Price”) of approximately $68.6 million in cash at closing (the “Closing Cash Consideration”), net of preliminary and customary purchase price adjustments and subject to final post-closing settlement between the Company and Lime Rock, $10.0 million due on or about December 31, 2025, and an aggregate of 6,452,879 shares of common stock of the Company, net of preliminary and customary purchase price adjustments. At the closing of the Lime Rock Acquisition, $5.0 million of the Closing Cash Consideration was retained in an escrow account to support Lime Rock’s indemnity obligations under the Purchase Agreement.

### Drilling and Completion

In the first quarter of 2025, in the Northwest Shelf in Yoakum County, the Company drilled and completed three 1-mile horizontal wells and one 1.25-mile horizontal well, all with a working interest of 75%. In the Central Basin Platform in Ector County, the Company drilled and completed three vertical wells, all with a working interest of 100%.

In the second quarter of 2025, in the Central Basin Platform in Andrews County, the Company drilled and completed one 1-mile horizontal well, with a working interest of 100%. Also in the Central Basin Platform in Crane County, the Company drilled and completed one vertical well, with a working interest of 100%.

The table below sets forth our drilling and completion activities for the six months ended June 30, 2025.

| Quarter | Area | Wells Drilled | Wells Completed |
| --- | --- | ---: | ---: |
| 1Q 2025 | Northwest Shelf (Horizontal) | 4 | 4 |
|  | Central Basin Platform (Vertical) | 3 | 3 |
|  | Total | 7 | 7 |
| 2Q 2025 | Central Basin Platform (Horizontal) | 1 | 1 |
|  | Central Basin Platform (Vertical) | 1 | 1 |
|  | Total | 2 | 2 |

(1) Total does not include the SWD well(s) drilled and completed in the \[ \].

### Market Conditions and Commodity Prices

Our financial results depend on many factors, particularly the price of crude oil and natural gas 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 both domestically and world wide, which are impacted by many factors. As a result, we cannot accurately predict future commodity prices, and therefore, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our drilling program, production volumes or revenues.

Average oil and natural gas prices received through 2024 and 2025 to date continue to demonstrate commodity price volatility and we believe oil and natural gas prices will continue to be volatile for the foreseeable future. The ability to find and develop sufficient amounts of crude oil and natural gas reserves at economical costs are critical to our long-term success.

#### Ceiling Test

We perform a ceiling test at the end of each reporting period to evaluate for potential non-cash impairments. Under the full cost method of accounting, the net book value of properties, less related deferred income taxes, may not exceed a calculated “ceiling,” which is defined as the estimated after-tax future net revenues from proved oil and natural gas properties, discounted at an annual rate of 10%. The discounted future net revenues are estimated using spot prices for oil and natural gas, based on the average price during the preceding twelve months. This average is calculated as an unweighted arithmetic mean of the first-day-of-the-month prices for each month within that period, except when changes are fixed and determinable by existing contracts. We anticipate a decrease in the twelve month average price over the next several months which will reasonably likely lead to a non-cash impairment. Estimating potential future non-cash impairments is complex due to numerous factors affecting the ceiling test calculation, including but not limited to future prices, operating costs, upward or downward reserve revisions, reserve additions, and tax attributes. The amount of any such potential non-cash impairment, if any, is not estimable at this time given the uncertainty of these factors.

#### Natural Gas Takeaway Capacity

The Permian Basin has been experiencing a lack of sufficient pipeline transportation that is connected to markets that are purchasing the natural gas produced. This has resulted in negative natural gas prices at times, whereby the seller is actually paying the purchaser to take the gas. We have experienced negative realized gas prices at times and conditions are continuing. If these depressed or inverted natural gas prices continue in the region, our natural gas revenues will continue to be negatively impacted.

#### Inflation

Inflation has increased costs associated with our capital program and production operations. We have experienced increases in the costs of many of the materials, supplies, equipment and services used in our operations and we expect inflation to continue based on current economic circumstances, including tariffs, trade wars, and supply chain disruptions. In addition, the attempts to reduce inflation by the U.S. Federal Reserve have resulted in increased interest rates on debt. We continue to closely monitor costs and take all reasonable steps to mitigate the inflationary effect on our cost structure and also work to enhance our efficiency to minimize additional cost increases where possible.

### Results of Operations

### Oil, Natural Gas, and Natural Gas Liquids Revenues for the Three Months Ended June 30, 2025 and 2024

| Net sales: | For the Three Months Ended June 30, 2025 | June 30, 2024 | Change | % Change |
| --- | ---: | ---: | ---: | ---: |
| Oil | $82,778,476 | $99,289,498 | $(16,511,022) | (17)% |
| Natural gas | (2,238,937) | (2,972,807) | 733,870 | 25% |
| Natural gas liquids | 2,063,220 | 2,822,658 | (759,438) | (27)% |
| **Total sales** | **$82,602,759** | **$99,139,349** | **$(16,536,590)** | **(17)%** |
| **Net production:** |  |  |  |  |
| Oil (Bbls) | 1,320,508 | 1,239,731 | 80,777 | 7% |
| Natural gas (Mcf) | 1,703,808 | 1,538,347 | 165,461 | 11% |
| Natural gas liquids (Bbls) | 333,374 | 304,448 | 28,926 | 10% |
| **Total production (Boe)(1)** | **1,937,850** | **1,800,570** | **137,280** | **8%** |
| **Average sales price:** |  |  |  |  |
| Oil (per Bbl) | $62.69 | $80.09 | $(17.40) | (22)% |
| Natural gas (per Mcf) | (1.31) | (1.93) | 0.62 | 32% |
| Natural gas liquids (Bbl) | 6.19 | 9.27 | (3.08) | (33)% |
| **Total per Boe** | **$42.63** | **$55.06** | **$(12.43)** | **(23)%** |

(1) Boe is calculated using six Mcf of natural gas as the equivalent of one barrel of oil.

***Oil sales.*** Oil sales decreased approximately $16.5 million from $99.3 million to $82.8 million due to a price variance of $(23.0) million from a decrease in the average realized price per barrel from $80.09 to $62.69. This was offset by a volume variance of $6.5 million from an increase in sales volume from 1,239,731 barrels of oil to 1,320,508 barrels of oil. The increase in volume of 80,777 barrels of oil consisted of two components. An increase in volumes of 153,877 barrels was due to the wells acquired in the Lime Rock Acquisition (which closed at the end of March 2025), and a decrease of 73,100 was attributed to natural production declines from our legacy assets. The decreased average realized price per barrel was primarily a result of weaker market conditions.

***Natural gas sales.*** Natural gas sales increased approximately $0.7 million from a negative $3.0 million to a negative $2.2 million, with a price variance of $1.1 million and with a volume variance making up the remaining difference. Our natural gas sales volumes increased from 1,538,347 Mcf to 1,703,808 Mcf, and the average realized price per Mcf increased from $(1.93) to $(1.31). Of the increase in volume of 165,461 Mcf, an increase of 98,282 Mcf was from the Lime Rock Acquisition and 67,179 Mcf was attributable to legacy assets. The price increase was driven by better market conditions. The realized revenue pricing included the impact of gas plant processing fees that were netted from revenue. For the three months ended June 30, 2025, gross revenues were $0.87 per Mcf and fees were $(2.18) per Mcf, compared to gross revenues of $(0.34) per Mcf and fees of $(1.59) per Mcf for the three months ended June 30, 2024. This resulted in a net realized price of $(1.31) per Mcf for the three months ended June 30, 2025 compared to $(1.93) per Mcf for the three months ended June 30, 2024.

***Natural gas liquids sales.*** NGL sales decreased approximately $0.8 million from $2.8 million to $2.1 million. NGL sales volumes for the three months ended June 30, 2025 were 333,374 barrels of NGLs compared to 304,448 barrels of NGLs for the comparable period in 2024. Of the increase in volume of 28,926 barrels, 20,603 barrels were attributable to wells acquired and new wells drilled in the acreage acquired in the Lime Rock Acquisition, with the remaining 8,323 barrels attributable to our legacy assets due to increased NGL yields and increased gas production. The average realized price per barrel of NGLs was $6.19 for the three months ended June 30, 2025 compared to $9.27 for the three months ended June 30, 2024, due to weaker market conditions. Specifically, the gross realized price per NGL barrel was $19.02 and the average fees per barrel was $(12.83), resulting in a net realized price of $6.19 for the three months ended June 30, 2025, while the gross realized price per NGL barrel was $19.49 and the average fees per barrel was $(10.22), resulting in a net realized price of $9.27 for the same period in 2024.

### Oil, Natural Gas, and Natural Gas Liquids Revenues for the Six Months Ended June 30, 2025 and 2024

| Net sales: | For the Six Months Ended June 30, 2025 | June 30, 2024 | Change | % Change |
| --- | ---: | ---: | ---: | ---: |
| Oil | $159,283,526 | $191,584,083 | $(32,300,557) | (17)% |
| Natural gas | (2,541,664) | (3,791,042) | 1,249,378 | 33% |
| Natural gas liquids | 4,952,104 | 5,849,444 | (897,340) | (15)% |
| **Total sales** | **$161,693,966** | **$193,642,485** | **$(31,948,519)** | **(16)%** |
| **Net production:** |  |  |  |  |
| Oil (Bbls) | 2,407,202 | 2,458,568 | (51,366) | (2)% |
| Natural gas (Mcf) | 3,319,004 | 3,034,854 | 284,150 | 9% |
| Natural gas liquids (Bbls) | 632,740 | 568,250 | 64,490 | 11% |
| **Total production (Boe)(1)** | **3,593,109** | **3,532,627** | **60,482** | **2%** |
| **Average sales price:** |  |  |  |  |
| Oil (per Bbl) | $66.17 | $77.93 | $(11.76) | (15)% |
| Natural gas (per Mcf) | (0.77) | (1.25) | 0.48 | 38% |
| Natural gas liquids (Bbl) | 7.83 | 10.29 | (2.46) | (24)% |
| **Total per Boe** | **$45.00** | **$54.82** | **$(9.82)** | **(18)%** |

(1) Boe is calculated using six Mcf of natural gas as the equivalent of one barrel of oil.

***Oil sales.*** Oil sales decreased approximately $32.3 million from $191.6 million to $159.3 million, with a price variance of $(28.3) million from a decrease in the average realized price per barrel from $77.93 to $66.17 as well as a volume variance of $(4.0) million due to a decrease in sales volume from 2,458,568 barrels of oil to 2,407,202 barrels of oil. The decrease in volume of 51,366 barrels consisted of two components. An increase in volumes of 153,877 was due to the Lime Rock Acquisition, and a decrease of 205,243 was attributed to natural production declines in the legacy assets. The Company's drilling and completion spend was 39% lower in the months that affected production for the first half of 2025 compared to the same months that affected production in the first half of 2024. This resulted in less offsets to declining production. The decreased average realized price per barrel was primarily the result of weaker market conditions.

***Natural gas sales.*** Natural gas sales increased approximately $1.2 million from a negative $3.8 million to a negative $2.5 million, with a price variance of $1.6 million with a volume variance making up the remaining variance. The natural gas sales volume increased from 3,034,854 Mcf to 3,319,004 Mcf, and the average realized price per Mcf increased from $(1.25) to $(0.77). Of the increase in volume of 284,150 Mcf, an increase of 98,282 was due to the Lime Rock Acquisition, with the remaining increase of 185,868 from the legacy assets. The price increase was driven by more favorable market conditions. The realized revenue pricing includes the impact of gas plant processing fees that were netted from revenue. For the six months ended June 30, 2025, gross revenues were $1.35 per Mcf and fees were $(2.12) per Mcf, compared to gross revenues of $0.42 per Mcf and fees of $(1.67) per Mcf for the six months ended June 30, 2024. This resulted in a net realized price of $(0.77) for the six months ended June 30, 2025 compared to $(1.25) per Mcf for the six months ended June 30, 2024.

***Natural gas liquids sales.*** NGL sales slightly decreased by approximately $0.8 million from $5.8 million to $5.0 million. NGL sales volumes for the six months ended June 30, 2025 were 632,740 barrels of NGLs compared to 568,250 barrels of NGLs for the comparable period in 2024. Of the increase in volume of 64,490 barrels, 20,603 was due to the Lime Rock Acquisition while the remaining 43,887 was from legacy assets. The average realized price per barrel of NGLs decreased by $2.46 to $7.83 for the six months ended June 30, 2025 compared to $10.29 for the six months ended June 30, 2024, attributable to weaker market conditions. Specifically, the gross realized price per NGL barrel was $20.74 and the average fees per barrel was $(12.91), resulting in a net realized price of $7.83 for the six months ended June 30, 2025, while the gross realized price per NGL barrel was $20.37 and the average fees per barrel was $(10.08), resulting in a net realized price of $10.29 for the same period in 2024.

### Production Costs for the Three Months Ended June 30, 2025 and 2024

|  | For the Three Months Ended June 30, 2025 | June 30, 2024 | Change | % Change |
| --- | ---: | ---: | ---: | ---: |
| **Lease operating expenses ("LOE")** | **$20,245,981** | **$19,309,017** | **$936,964** | **5%** |
| Average LOE per Boe | $10.45 | $10.72 | $(0.27) | (3)% |
| **Gathering, transportation and processing costs ("GTP")** | **$133,809** | **$107,629** | **$26,180** | **24%** |
| Average GTP per Boe | $0.07 | $0.06 | $0.01 | 17% |
| **Ad valorem taxes** | **$1,648,647** | **$1,337,276** | **$311,371** | **23%** |
| Average Ad valorem taxes per Boe | $0.85 | $0.74 | $0.11 | 15% |
| **Oil and natural gas production taxes** | **$3,832,607** | **$3,627,264** | **$205,343** | **6%** |
| Average Production taxes per Boe | $1.98 | $2.01 | $(0.03) | (1)% |
| Production taxes as a percentage of total sales | 4.64% | 3.66% | 0.98% | 27% |

***Lease operating expenses.*** Our total lease operating expenses (“LOE”) increased from $19.3 million to $20.2 million and decreased on a per Boe basis from $10.72 to $10.45. These per Boe amounts are calculated by dividing our total lease operating expenses by our total volume sold, in Boe. Total LOE increased primarily due to an 8% increase in production of 137,280 Boe as a result of the increased production and well count from the Lime Rock Acquisition as well as new wells drilled and completed in our development program. The primary cost driver for the period was an increase of $1.7 million in electricity costs. Other impacting factors included an increase of $0.1 million for environmental sustainability, offset by reductions of $0.5 million for supplies, tools, and materials, $0.1 million for workovers, $0.1 million for hot oil costs, and $0.1 million for chemical costs.

***Gathering, transportation and processing costs.*** Our total gathering, transportation and processing costs (“GTP”) increased from $107,629 to $133,809 and increased on a per Boe basis from $0.06 to $0.07. Beginning May 1, 2022, due to a natural gas processing entity taking control of transportation at the wellhead, GTP costs were re-classified as a reduction to oil and natural gas sales revenues. However, one contract remains in place with a natural gas processing entity where point of control of gas dictates requiring the fees be recorded as an expense. The increase in GTP costs was primarily due to the higher natural gas Mcf and NGL barrels processed.

***Ad valorem taxes.*** Our total ad valorem taxes increased from $1.3 million to $1.6 million and increased on a per Boe basis from $0.74 to $0.85. Of the $0.3 million increase in ad valorem taxes, $0.6 million was related to Andrews County tax estimates, primarily related to the Lime Rock acquisition. There was also an increase of $0.1 million for Ector County tax estimates. These were offset by a reduction of $(0.4) million for Yoakum County tax estimates.

***Oil and natural gas production taxes.*** Oil and natural gas production taxes as a percentage of oil and natural gas sales were 3.66% for the three months ended June 30, 2024 and increased to 4.64% for the three months ended June 30, 2025. The tax in the three months ended June 30, 2024 included an accrual for refunds that had been filed with the state comptroller and therefore was less than the regular expected percentage of revenues.

### Production Costs for the Six Months Ended June 30, 2025 and 2024

|  | For the Six Months Ended June 30, 2025 | June 30, 2024 | Change | % Change |
| --- | ---: | ---: | ---: | ---: |
| **Lease operating expenses ("LOE")** | **$39,923,533** | **$37,669,451** | **$2,254,082** | **6%** |
| Average LOE per Boe | $11.11 | $10.66 | $0.45 | 4% |
| **Gathering, transportation and processing costs ("GTP")** | **$337,421** | **$273,683** | **$63,738** | **23%** |
| Average GTP per Boe | $0.09 | $0.08 | $0.01 | 13% |
| **Ad valorem taxes** | **$3,180,755** | **$3,482,907** | **$(302,152)** | **(9)%** |
| Average Ad valorem taxes per Boe | $0.89 | $0.99 | $(0.10) | (10)% |
| **Oil and natural gas production taxes** | **$7,417,062** | **$8,055,567** | **$(638,505)** | **(8)%** |
| Average Production taxes per Boe | $2.06 | $2.28 | $(0.22) | (10)% |
| Production taxes as a percentage of total sales | 4.59% | 4.16% | 0.43% | 10% |

***Lease operating expenses.*** Our total LOE increased from $37.7 million to $39.9 million and LOE per Boe increased from $10.66 to $11.11. Total LOE increased in accordance with a 2% increase in production of 60,482 Boe, as a result of the additional production and well count from the Lime Rock Acquisition. The primary cost driver for the period was an increase in electricity costs of $2.9 million. Other cost increases included environmental sustainability of $0.4 million, and contract and lease services of $0.3 million. This was offset by reductions in LOE costs from workovers of $0.9 million, supplies, tools, and materials of $0.3 million, and hot oil costs of $0.2 million.

***Gathering, transportation and processing costs.*** Our total GTP increased $63,738 from $273,683 to $337,421 and increased on a per Boe basis from $0.08 to $0.09. The increase in GTP costs was due to the higher natural gas Mcf and NGL barrels processed as well as a prior period adjustment for fee exempt owners.

***Ad valorem taxes.*** Our total ad valorem taxes decreased from $3.5 million to $3.2 million and decreased on a per Boe basis from $0.99 to $0.89. Of the approximate $0.3 million decrease in ad valorem taxes, $0.5 million was from the reversal of the 2024 methane tax accrual for the waste emissions charge ("WEC"), which was repealed by Congress on March 14, 2025.

***Oil and natural gas production taxes.*** Oil and natural gas production taxes as a percentage of oil and natural gas sales were 4.16% for the six months ended June 30, 2024 and increased to 4.59% for the six months ended June 30, 2025. Overall, the percentage was consistent period over period.

### Other Costs and Operating Expenses for the Three Months Ended June 30, 2025 and 2024

| Depreciation, depletion and amortization (DD&A): | For the Three Months Ended June 30, 2025 | June 30, 2024 | Change | % Change |
| --- | ---: | ---: | ---: | ---: |
| Depletion | $25,224,638 | $24,325,186 | $899,452 | 4% |
| Depreciation | 106,658 | 102,772 | 3,886 | 4% |
| Amortization of financing lease assets | 238,618 | 271,463 | (32,845) | (12)% |
| **Total depreciation, depletion and amortization** | **$25,569,914** | **$24,699,421** | **$870,493** | **4%** |
| Depletion per Boe | $13.02 | $13.51 | $(0.49) | (4)% |
| Depreciation, depletion and amortization per Boe | $13.19 | $13.72 | $(0.53) | (4)% |
| **Asset retirement obligation ("ARO") accretion** | **$382,251** | **$352,184** | **$30,067** | **9%** |
| **Operating lease expense** | **$175,090** | **$175,090** | **$—** | **—%** |
| **General and administrative expense ("G&A"):** |  |  |  |  |
| General and administrative expense (excluding Share-based compensation) | $5,786,680 | $5,635,756 | $150,924 | 3% |
| Share-based compensation | 1,351,839 | 2,077,778 | (725,939) | (35)% |
| **Total general and administrative expense** | **$7,138,519** | **$7,713,534** | **$(575,015)** | **(7)%** |
| G&A per Boe | $3.68 | $4.28 | $(0.60) | (14)% |
| G&A excluding Share-based compensation, per Boe | $2.99 | $3.13 | $(0.14) | (4)% |

***Depreciation, depletion and amortization.*** Our depreciation, depletion and amortization increased from $24.7 million to $25.6 million, with $0.9 million of the increase from higher depletion. The increase in depletion was the result of a volume variance of $1.9 million due to an increase of 137,280 in Boe produced, offset by a price variance of $(1.0) million. driven by a lower depletion rate per Boe from higher reserves. Our average depreciation, depletion and amortization per Boe decreased from $13.72 per Boe to $13.19 per Boe.

***Asset retirement obligation accretion.*** Our asset retirement obligation (“ARO”) accretion increased slightly from $352,184 to $382,251 due to additional ARO accretion associated with properties acquired in the Lime Rock Acquisition as well as new drilled and completed wells, offset by wells plugged and abandoned and sold.

***Operating lease expense.*** Our operating lease expense costs were the same period over period.

***General and administrative expense.*** General and administrative ("G&A") expense decreased from $7.7 million to $7.1 million. The $0.6 million cost decrease was primarily due to a decrease of $0.7 million in share-based compensation costs. Other cost reductions included a decrease of $0.3 million in legal fees, $0.2 million in additional costs capitalized for geological and geophysical ("G&G"), $0.1 million in reduced costs for environmental sustainablity, and a $0.1 million reduction in insurance costs. These cost reductions were offset by an increase of $0.8 million in salaries and bonuses.

### Other Costs and Operating Expenses for the Six Months Ended June 30, 2025 and 2024

| Depreciation, depletion and amortization (DD&A): | For the Six Months Ended June 30, 2025 | June 30, 2024 | Change | % Change |
| --- | ---: | ---: | ---: | ---: |
| Depletion | $47,479,214 | $47,754,798 | $(275,584) | (1)% |
| Depreciation | 203,278 | 204,709 | (1,431) | (1)% |
| Amortization of financing lease assets | 503,405 | 532,364 | (28,959) | (5)% |
| **Total depreciation, depletion and amortization** | **$48,185,897** | **$48,491,871** | **$(305,974)** | **(1)%** |
| Depletion per Boe | $13.21 | $13.52 | $(0.31) | (2)% |
| Depreciation, depletion and amortization per Boe | $13.41 | $13.73 | $(0.32) | (2)% |
| **Asset retirement obligation ("ARO") accretion** | **$708,800** | **$703,018** | **$5,782** | **1%** |
| **Operating lease expense** | **$350,181** | **$350,181** | **$—** | **—%** |
| **General and administrative expense ("G&A"):** |  |  |  |  |
| General and administrative expense (excluding Share-based compensation) | $12,715,698 | $11,381,146 | $1,334,552 | 12% |
| Share-based compensation | 3,042,797 | 3,801,610 | (758,813) | (20)% |
| **Total general and administrative expense** | **$15,758,495** | **$15,182,756** | **$575,739** | **4%** |
| G&A per Boe | $4.39 | $4.30 | $0.09 | 2% |
| G&A excluding Share-based compensation, per Boe | $3.54 | $3.22 | $0.32 | 10% |

***Depreciation, depletion and amortization.*** Our depreciation, depletion and amortization decreased approximately $0.3 million from $48.5 million to $48.2 million, with substantially all of the reduction from lower depletion. The decrease in depletion was primarily due to a a price variance of $(1.1) million, from a lower depletion expense per Boe, due to an increase in the amortization base (Boe). Further, depletion had a volume variance of $0.8 million from a increase of 60,482 in Boe produced. Our average depreciation, depletion and amortization per Boe decreased from $13.73 per Boe to $13.41 per Boe.

***Asset retirement obligation accretion.*** Our ARO accretion increased by $5,782 from $703,018 to $708,800 primarily as a result of newly acquired and drilled wells, offset by those plugged and abandoned and sold.

***Operating lease expense.*** Our operating lease expense costs were the same period over period.

***General and administrative expense.*** G&A expense increased approximately $0.6 million from $15.2 million to $15.8 million, with the $0.6 million cost increase primarily due to an increase of $2.3 million in salaries and bonuses (including impacts from severance paid), offset by reductions of $0.8 million in stock based compensation, $0.4 million in legal fees, $0.2 million in environmental sustainability, $0.2 million in credit loss expense, $0.1 million in additional costs capitalized for G&G, and a reduction of $0.1 million in other professional fees.

### Other Income (Expense) for the Three Months Ended June 30, 2025 and 2024

|  | For the Three Months Ended June 30, 2025 | June 30, 2024 | Change | % Change |
| --- | ---: | ---: | ---: | ---: |
| **Interest income** | **$69,658** | **$144,933** | **$(75,275)** | **(52)%** |
| **Interest expense:** |  |  |  |  |
| Interest on revolving line of credit | $9,482,817 | $9,521,775 | $(38,958) | —% |
| Fees associated with revolving line of credit | 210,459 | 245,297 | (34,838) | (14)% |
| Amortization of deferred financing costs | 1,836,174 | 1,221,608 | 614,566 | 50% |
| Interest on financing lease liabilities | 27,638 | 31,422 | (3,784) | (12)% |
| Interest paid for notes payable | 10,645 | 9,986 | 659 | 7% |
| Deferred cash payment accretion | 189,671 | — | 189,671 | 100% |
| Other interest | — | (83,961) | 83,961 | 100% |
| **Total interest expense** | **$11,757,404** | **$10,946,127** | **$811,277** | **7%** |
| **Gain (loss) on derivative contracts:** |  |  |  |  |
| Realized gain (loss): |  |  |  |  |
| Crude oil | $433,301 | $(4,073,127) | $4,506,428 | 111% |
| Natural gas | 244,542 | 1,478,630 | (1,234,088) | (83)% |
| **Total realized gain (loss)** | **$677,843** | **$(2,594,497)** | **$3,272,340** | **126%** |
| Unrealized gain (loss): |  |  |  |  |
| Crude oil | $12,145,940 | $2,308,594 | $9,837,346 | 426% |
| Natural gas | 1,824,271 | (1,542,696) | 3,366,967 | 218% |
| **Total unrealized gain (loss)** | **$13,970,211** | **$765,898** | **$13,204,313** | **1724%** |
| **Total gain (loss) on derivative contracts:** | **$14,648,054** | **$(1,828,599)** | **$16,476,653** | **901%** |
| **Gain (loss) on disposal of assets** | **$155,293** | **$51,338** | **$103,955** | **202%** |
| **Other income** | **$150,770** | **$—** | **$150,770** | **100%** |

***Interest income.*** Interest income decreased from $144,933 to $69,658 due to lower interest earned from depositing excess cash balances in bank sweep accounts.

***Interest expense.*** Interest expense increased from $10.9 million to $11.8 million primarily due to additional deferred financing costs recognized from the credit agreement modification which was completed in June 2025. Also impacting the increase in interest expense was the deferred cash payment accretion related to the Lime Rock acquisition which closed at the end of March 2025. Although the Company had higher amounts outstanding on its Credit Facility, with a weighted average daily debt of approximately $456.3 million during the second quarter of 2025 compared to approximately $420.3 million during the second quarter of 2024, the interest on the revolving line of credit decreased slightly due to a meaningful reduction in interest rates, with a weighted average annual interest rate of 8.5% in the second quarter of 2025 compared to 9.3% in the second quarter of 2024.

***Gain (loss) on derivative contracts.*** We recorded a gain on derivative contracts of $14.6 million for the three months ended June 30, 2025 compared to a loss on derivative contracts of $1.8 million for the three months ended June 30, 2024. For the derivative contract settlements, we recorded a realized gain of $0.7 million for the three months ended June 30, 2025 and a realized loss of $2.6 million for the three months ended June 30, 2024. The change of $3.3 million in the realized gain (loss) was a result of more favorable settlements of crude oil derivative contracts during the current year. For the marked-to-market contracts, we recorded an unrealized gain of $14.0 million for the three months ended June 30, 2025 and an unrealized gain of $0.8 million for the three months ended June 30, 2024. The change in position was primarily due to the changes in crude oil futures prices.

***Gain (loss) on disposal of assets.*** The Company's gain on disposal of assets increased by $103,955 from $51,338 during the three months ended June 30, 2024 to $155,293 during the three months ended June 30, 2025, with $89,716 of the increase from the sale of leased vehicles, and the remainder of $14,239 due to selling owned vehicles in the prior period.

***Other income.*** During the three months ended June 30, 2025, the Company recorded $150,770 of other income from a pipeline easement lease.

### Other Income (Expense) for the Six Months Ended June 30, 2025 and 2024

|  | For the Six Months Ended June 30, 2025 | June 30, 2024 | Change | % Change |
| --- | ---: | ---: | ---: | ---: |
| **Interest income** | **$159,716** | **$223,477** | **$(63,761)** | **(29)%** |
| **Interest expense:** |  |  |  |  |
| Interest on revolving line of credit | $17,430,459 | $19,287,826 | $(1,857,367) | (10)% |
| Fees associated with revolving line of credit | 487,848 | 484,925 | 2,923 | 1% |
| Amortization of deferred financing costs | 3,074,667 | 2,443,215 | 631,452 | 26% |
| Interest on financing lease liabilities | 56,379 | 62,739 | (6,360) | (10)% |
| Interest paid for notes payable | 17,166 | 16,366 | 800 | 5% |
| Deferred cash payment accretion | 189,671 | — | 189,671 | 100% |
| Other interest | — | 150,000 | (150,000) | (100)% |
| **Total interest expense** | **$21,256,190** | **$22,445,071** | **$(1,188,881)** | **(5)%** |
| **Gain (loss) on derivative contracts:** |  |  |  |  |
| Realized gain (loss): |  |  |  |  |
| Crude oil | $(206,966) | $(6,812,097) | $6,605,131 | 97% |
| Natural gas | 331,215 | 2,756,085 | (2,424,870) | (88)% |
| **Total realized gain (loss)** | **$124,249** | **$(4,056,012)** | **$4,180,261** | **103%** |
| Unrealized gain (loss): |  |  |  |  |
| Crude oil | $14,487,365 | $(14,685,728) | $29,173,093 | 199% |
| Natural gas | (892,350) | (2,101,354) | 1,209,004 | 58% |
| **Total unrealized gain (loss)** | **$13,595,015** | **$(16,787,082)** | **$30,382,097** | **181%** |
| **Total gain (loss) on derivative contracts:** | **$13,719,264** | **$(20,843,094)** | **$34,562,358** | **166%** |
| **Gain (loss) on disposal of assets** | **$279,903** | **$89,693** | **$190,210** | **212%** |
| **Other income** | **$159,712** | **$25,686** | **$134,026** | **522%** |

***Interest income.*** Interest income decreased $63,761 from $223,477 to $159,716, from a reduction of $71,128 from depositing excess cash balances in bank sweep accounts, offset by an increase of $7,367 in severance tax interest payments.

***Interest expense.*** Interest expense decreased by approximately $1.2 million from $22.4 million to $21.3 million as a result of lower interest rates, with a weighted average annual interest rate of 8.4% during the six months ended June 30, 2025 compared to 9.3% during the six months ended June 30, 2024. Slightly offsetting this impact was higher amounts outstanding on our Credit Facility, with a weighted average daily debt of approximately $425.0 million during the six months ended June 30, 2025 compared to approximately $424.6 million during the six months ended June 30, 2024. Further offsetting was the increase in deferred financing costs recognized from the credit agreement modification.

***Gain (loss) on derivative contracts.*** We recorded a gain on derivative contracts of $13.7 million for the six months ended June 30, 2025 and a loss on derivative contracts of $20.8 million for the six months ended June 30, 2024. For the derivative contract settlements, we recorded a realized gain of $0.1 million for the six months ended June 30, 2025 and a realized loss of $4.1 million for the six months ended June 30, 2024. The change of $4.2 million in the realized derivative gain (loss) was a result of more favorable settlements of crude oil derivative contracts during the current year. For the marked-to-market contracts, we recorded an unrealized gain of $13.6 million for the six months ended June 30, 2025 and an unrealized loss of $16.8 million for the six months ended June 30, 2024. This positive change in unrealized derivatives primarily was due to the changes in crude oil futures prices on derivative contracts in the Company's portfolio.

***Gain (loss) on disposal of assets.*** The Company's gain on disposal of assets increased by $190,210 from $89,693 to $279,903 with $182,945 of the increase from the sale of leased vehicles as well as $7,265 from more favorable sales of Company owned vehicles.

***Other income.*** Other income increased $134,026 from $25,686 to $159,712 from due to an increase in income of $150,770 from a pipeline easement lease, offset by a reduction of $16,744 in income from the Company's charge card rebate program.

### Provision for Income Taxes: for the Three Months Ended June 30, 2025 and 2024

| Provision for Income Taxes: | For the Three Months Ended June 30, 2025 | June 30, 2024 | Change | % Change |
| --- | ---: | ---: | ---: | ---: |
| Deferred federal income tax provision | $(5,776,325) | $(6,427,828) | $651,503 | 10% |
| Current state income tax provision | (147,461) | (152,385) | 4,924 | 3% |
| Deferred state income tax provision | (183,639) | (240,272) | 56,633 | 24% |
| **Provision for Income Taxes** | **$(6,107,425)** | **$(6,820,485)** | **$713,060** | **10%** |

***Provision for income taxes.*** The provision for income taxes changed from a provision of $6.8 million for the three months ended June 30, 2024 to a provision of $6.1 million for the three months ended June 30, 2025. The provision for income taxes was calculated using the annual effective tax rate method based on our estimated earnings and estimated state and federal income taxes due for 2025, taking into account all applicable tax rates and laws.

### Provision for Income Taxes: for the Six Months Ended June 30, 2025 and 2024

| Provision for Income Taxes: | For the Six Months Ended June 30, 2025 | June 30, 2024 | Change | % Change |
| --- | ---: | ---: | ---: | ---: |
| Deferred federal income tax provision | $(8,592,403) | $(7,979,587) | $(612,816) | (8)% |
| Current state income tax provision | (283,854) | (255,018) | (28,836) | (11)% |
| Deferred state income tax provision | (272,345) | (314,766) | 42,421 | 13% |
| **Provision for Income Taxes** | **$(9,148,602)** | **$(8,549,371)** | **$(599,231)** | **(7)%** |

***Provision for income taxes.*** The provision for income taxes changed from a provision of $8.5 million for the six months ended June 30, 2024 to a provision of $9.1 million for the six months ended June 30, 2025. The provision for income taxes was calculated using the annual effective tax rate method based on our estimated earnings and estimated state and federal income taxes due for 2025, taking into account all applicable tax rates and laws.

### Liquidity and Capital Resources

As of June 30, 2025, we had cash on hand of $0.0 million, compared to $1.9 million as of December 31, 2024. We strive to keep our cash balance as low as possible to minimize our outstanding debt and associated interest. At certain times we reflect a zero book balance while utilizing the float on outstanding checks. We had net cash provided by operating activities for the six months ended June 30, 2025 of $61.7 million, compared to net cash provided by operating activities of $95.8 million for the same period in 2024, which was primarily due to lower year to date revenues, which resulted in less cash received from purchasers. We had net cash used in investing activities of $121.0 million for the six months ended June 30, 2025, compared to net cash used in investing activities of $76.4 million for the same period in 2024, driven by the payments made for the Lime Rock Acquisition in the first half of 2025, with no comparable payments made in the first half of 2024. This increase in acquisition payments was offset by a reduction in payments to develop oil and natural gas properties. Net cash provided by financing activities was $57.4 million for the six months ended June 30, 2025 and net cash used in financing activities was $18.6 million for the six months ended June 30, 2024, during which time $63 million was the net borrowing and $18.0 million was the net paydown of principal on our Credit Facility, respectively.

We will continue to focus on maximizing cash flow in 2025 through a combination of cost monitoring and prudent capital allocation, which includes prioritizing our capital to projects we believe will provide high rates of return in the current commodity price environment. We will continue our pursuit of acquisitions and business combinations, seeking opportunities that we believe will provide high margin properties with attractive returns at current commodity prices, ultimately pushing to reduce our debt level and maximize our liquidity.

### Availability of Capital Resources under Credit Facility

As of June 30, 2025, $448 million was outstanding on our Credit Facility and we were in compliance with all of the covenants under the Credit Facility. The Credit Facility matures in June 2029. The borrowing base under our Credit Facility is $585 million. The borrowing base is redetermined semi-annually each May and November. See "NOTE 8 — REVOLVING LINE OF CREDIT" in the Notes to the condensed financial statements for more information on our Credit Facility.

### Derivative Financial Instruments

The following table reflects the contracts outstanding as of June 30, 2025 (quantities are in barrels (Bbl) for the oil derivative contracts and in million British thermal units (MMBtu) for the natural gas derivative contracts):

| Swaps: | Oil Hedges (WTI) Q3 2025 | Q4 2025 | Q1 2026 | Q2 2026 | Q3 2026 | Q4 2026 | Q1 2027 | Q2 2027 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Hedged volume (Bbl) | 471,917 | 241,755 | 608,350 | 577,101 | 171,400 | 529,000 | 509,500 | 492,000 |
| Weighted average swap price | $68.64 | $65.56 | $67.95 | $67.41 | $62.26 | $65.34 | $62.82 | $60.45 |
| **Two-way collars:** |  |  |  |  |  |  |  |  |
| Hedged volume (Bbl) | 225,400 | 404,800 | — | — | 379,685 | — | — | — |
| Weighted average put price | $65.00 | $60.00 | $— | $— | $60.00 | $— | $— | $— |
| Weighted average call price | $78.91 | $75.68 | $— | $— | $72.50 | $— | $— | $— |

54

| NYMEX Swaps: | Gas Hedges (Henry Hub) Q3 2025 | Q4 2025 | Q1 2026 | Q2 2026 | Q3 2026 | Q4 2026 | Q1 2027 | Q2 2027 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Hedged volume (MMBtu) | 300,500 | 128,400 | 140,600 | 662,300 | 121,400 | 613,300 | — | — |
| Weighted average swap price | $3.88 | $4.25 | $4.20 | $3.54 | $4.22 | $3.83 | $— | $— |
| **Two-way collars:** |  |  |  |  |  |  |  |  |
| Hedged volume (MMBtu) | 309,350 | 748,000 | 694,500 | 139,000 | 648,728 | 128,000 | 717,000 | 694,000 |
| Weighted average put price | $3.17 | $3.10 | $3.50 | $3.50 | $3.10 | $3.50 | $3.99 | $3.00 |
| Weighted average call price | $4.98 | $4.40 | $5.11 | $5.42 | $4.24 | $5.42 | $5.21 | $4.32 |

| Argus basis swaps: | Oil Hedges (basis differential) Q3 2025 | Q4 2025 | Q1 2026 | Q2 2026 | Q3 2026 | Q4 2026 | Q1 2027 | Q2 2027 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Hedged volume (Bbl) | 183,000 | 276,000 | — | — | — | — | — | — |
| Weighted average spread price (1) | $1.00 | $1.00 | $— | $— | $— | $— | $— | $— |

| El Paso Permian Basin basis swaps: | Gas Hedges (basis differential) Q3 2025 | Q4 2025 | Q1 2026 | Q2 2026 | Q3 2026 | Q4 2026 | Q1 2027 | Q2 2027 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Hedged volume (MMBtu) | 381,725 | 363,200 | — | — | — | — | 700,000 | — |
| Weighted average spread price (2) | $1.69 | $1.69 | $— | $— | $— | $— | $0.74 | $— |

(1) The oil basis swap hedges are calculated as the fixed price (weighted average spread price above) less the difference between WTI Midland and WTI Cushing, in the issue of Argus Americas Crude.

(2) The gas basis swap hedges are calculated as the Henry Hub natural gas price less the fixed amount specified as the weighted average spread price above.

Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the accompanying Condensed Balance Sheets. Any gains or losses resulting from changes in fair value of outstanding derivative financial instruments and from the settlement of derivative financial instruments are recognized in earnings and included as a component of Other Income (Expense) in the accompanying Condensed Statements of Operations.

The use of derivative transactions involves the risk that the counterparties, which generally are financial institutions, will be unable to meet the financial terms of such transactions. At June 30, 2025, 86% of our derivative instruments were with lenders under our Credit Facility.

### Effects of Inflation and Pricing

The oil and natural gas industry is cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry puts significant pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do associated costs. Material changes in prices impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, and the value of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money, and retain personnel. We anticipate business costs will vary in accordance with commodity prices for oil and natural gas, and the associated increase or decrease in demand for services related to production and exploration.

### Off-Balance Sheet Financing Arrangements

As of June 30, 2025, we had no off-balance sheet financing arrangements.

### Capital Resources for Future Acquisition and Development Opportunities

We continuously evaluate potential acquisitions and development opportunities. To the extent possible, we intend to acquire producing properties with lower-risk undeveloped drilling opportunities rather than properties with higher-risk exploratory opportunities. We do not intend to limit our evaluation to any one state, but we presently have no intention to acquire offshore properties or properties located outside of the United States.

The pursuit of and the acquisition of accretive oil and gas properties is highly competitive and may require substantially greater capital than we currently have available and obtaining additional capital may require that we obtain either short-term or long-term debt or sell our equity or both. Further, it may be necessary for us to retain outside consultants and others in our endeavors to locate desirable oil and gas properties.

The process of acquiring one or more additional oil and gas properties would impact our financial position, reduce our cash position and likely increase our debt levels. The types of costs that we may incur include the costs to retain consultants and investment bankers specializing in the purchase of oil and gas properties, obtaining petroleum engineering reports relative to the oil and gas properties that we are investigating, legal fees associated with any such acquisitions including title reports, SEC reporting expenses, and negotiating definitive agreements. Additionally, accounting fees may be incurred relative to obtaining and evaluating historical and pro forma information regarding oil and gas properties. Even though we may incur these costs, there is no assurance that we will ultimately be able to consummate additional acquisitions of oil and gas producing properties.

## Market risk

As filed, 3,594 characters.

### Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Market risk refers to the risk of loss from decreases in oil and natural gas prices. Realized pricing is primarily driven by the prevailing domestic price for crude oil and spot prices in the Permian Basin. Historically, prices received for oil and natural gas production have been volatile and unpredictable. We expect pricing volatility to continue.

The prices we receive depend on many factors outside of our control. A significant decrease in the prices of oil or natural gas would likely have a material adverse effect on our financial condition and results of operations. In order to reduce commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas, we enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production.

### Customer Credit Risk

Our principal exposure to credit risk is through receivables from the sale of our oil and natural gas production (approximately $36.3 million as of June 30, 2025). We are subject to credit risk due to the concentration of our oil and natural gas receivables with our most significant customers, or purchasers. We do not require our purchasers to post collateral, and the inability of our significant purchasers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. Refer to the following table for detail on the top three purchasers of our oil, natural gas, and NGL revenues for the six months ended June 30, 2025. We believe that the loss of any of these purchasers would not materially impact our business as we could readily find other purchasers for our oil and natural gas.

| Purchaser: | For the Six Months Ended June 30, 2025 Percentage of Oil, Natural Gas, and Natural Gas Liquids Revenues | As of June 30, 2025 Percentage of accounts receivables from the sale of our oil and natural gas production |
| --- | ---: | ---: |
| Phillips 66 Company ("Phillips") | 66% | 73% |
| Concord Energy LLC ("Concord") | 13% | 10% |
| NGL Crude Partners ("NGL Crude") | 9% | 7% |

### Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility, which bears variable interest based upon a prime rate and is therefore susceptible to interest rate fluctuations. Changes in interest rates affect the interest earned on the Company’s cash and cash equivalents and the interest rate paid on borrowings under the Credit Facility.

As of June 30, 2025, we had $448 million outstanding on our Credit Facility with a weighted average annual interest rate for the six months ended June 30, 2025 of 8.4%. A 1% change in the interest rate on our Credit Facility would result in an estimated $4.5 million change in our annual interest expense. See "NOTE 8 — REVOLVING LINE OF CREDIT" in the Notes to the condensed financial statements for more information on the Company’s interest rates of our Credit Facility.

Currently, we do not use interest rate derivative instruments to manage exposure to interest rate changes.

### Currency Exchange Rate Risk

Foreign sales accounted for none of the Company's sales; the Company accepts payment for its commodity sales only in U.S. dollars. Ring is therefore not exposed to foreign currency exchange rate risk on these sales.

Please also see Item 1A “Risk Factors” for a discussion of other risks and uncertainties we face in our business.

## Controls and procedures

As filed, 2,492 characters.

### Evaluation of disclosure controls and procedures.

Our management, with the participation of Paul D. McKinney, our principal executive officer, and Travis T. Thomas, our principal financial officer, evaluated the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Exchange Act. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints, and that management is required to apply its judgment in evaluating the benefits of possible controls and procedures relative to their costs.

Based on management’s evaluation, Messrs. McKinney and Thomas concluded that our disclosure controls and procedures as of the end of the period covered by this report were effective in ensuring that information required to be disclosed by us in reports that we file or submit under the Exchange Act (i) is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and (ii) is accumulated and communicated to the Company’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

We will continue to monitor and evaluate the effectiveness of our disclosure controls and procedures and our internal controls over financial reporting on an ongoing basis and are committed to taking further action and implementing additional enhancements or improvements, as necessary and as funds allow.

### Changes in internal control over financial reporting.

We regularly review our system of internal control over financial reporting and make changes to our processes and systems to improve controls and increase efficiency, while ensuring that we maintain an effective internal control environment. Changes may include such activities as implementing new, more efficient systems, consolidating activities, and migrating processes.

There were no changes in our internal control over financial reporting that occurred during the three months ended June 30, 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

## Risk factors

As filed, 618 characters.

We are subject to certain risks and hazards due to the nature of the business activities we conduct. For a discussion of these risks, see “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2024 as filed with the SEC. We may experience additional risks and uncertainties not currently known to us. Further, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect us. Any such risks may materially and adversely affect our business, financial condition, cash flows, and results of operations.

Filed Aug 6, 2025.
Source: SEC EDGAR, the filing index for accession 0001628280-25-038401. Last ingested by Listed: Oct 27, 2026, 17:29 ET. No prices; not investment advice.