# Ring Energy, Inc.: Form 10-Q for the period ended Mar 31, 2024

- Company: [Ring Energy, Inc.](/companies/rei.md) (CIK 1384195)
- Form: 10-Q
- Filed: 2024-05-06
- Accepted by EDGAR: May 6, 2024, 16:53 ET
- Period: 2024-03-31
- Accession: 0001628280-24-020695
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1384195/000162828024020695/rei-20240331.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1384195/000162828024020695/

## Figures reported in this filing

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

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2024-01-01 to 2024-03-31 | $94.5m | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Operating income | 3 months, 2024-01-01 to 2024-03-31 | $37.6m | us-gaap:OperatingIncomeLoss |
| Interest expense | 3 months, 2024-01-01 to 2024-03-31 | $11.5m | us-gaap:InterestExpense |
| Income tax | 3 months, 2024-01-01 to 2024-03-31 | $1.7m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2024-01-01 to 2024-03-31 | $5.5m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2024-01-01 to 2024-03-31 | $0.03 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2024-01-01 to 2024-03-31 | $0.03 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2024-01-01 to 2024-03-31 | 199,305,150 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 3 months, 2024-01-01 to 2024-03-31 | $45.2m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Cash and equivalents | at 2024-03-31 | $1.4m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2024-03-31 | $58.7m | us-gaap:AssetsCurrent |
| Total assets | at 2024-03-31 | $1.38bn | us-gaap:Assets |
| Current liabilities | at 2024-03-31 | $118.4m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2024-03-31 | $591.7m | us-gaap:Liabilities |
| Shareholders' equity | at 2024-03-31 | $793.0m | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 29,604 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 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 of 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 shareholders.

- *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 assets, 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 well 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. During the three months ended March 31, 2024, the Company made net paydowns of $3 million on its revolving line of credit, resulting in the outstanding long-term debt balance of $422 million.
- *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 balance sheet metrics and are accretive to shareholders. Our executive team, with its extensive experience in the Permian Basin, has many relationships with operators and service providers in the region. Ring believes that leveraging the relationships of its management and board of directors will be a competitive advantage in identifying potential acquisition targets.

### 2024 Developments and Highlights

### Drilling and Completion

In the first quarter of 2024, in the Northwest Shelf, the Company drilled and completed two 1-mile horizontal wells (one with a working interest of 99.5% and the other with a working interest of 100%). In the Central Basin Platform, the Company drilled and completed nine wells, all with a working interest of 100%. Specifically, in our Andrews County acreage the Company drilled and completed three 1-mile horizontal wells, in the Ector County acreage the Company drilled three vertical wells, and in the Crane County acreage the Company drilled and completed three vertical wells. Additionally, within the Central Basin Platform, the Company drilled and completed one salt water disposal ("SWD") well in Crane County.

The table below sets forth our drilling and completion activities for the three months ended March 31, 2024.

| Quarter | Area | Wells Drilled | Wells Completed |
| --- | --- | ---: | ---: |
| 1Q 2024 | Northwest Shelf (Horizontal) | 2 | 2 |
|  | Central Basin Platform (Horizontal) | 3 | 3 |
|  | Central Basin Platform (Vertical) | 6 | 6 |
|  | Total (1) | 11 | 11 |

(1) First quarter total does not include the SWD well drilled and completed in the Central Basin Platform.

### 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 2023 and 2024 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.

#### Natural Gas Takeaway Capacity

The Permian Basin has been experiencing a lack of sufficient pipeline transportation that is connected to markets which 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. 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. In addition, the attempts to reduce inflation by the U.S. Federal Reserve have resulted in increased interest rates on debt and contributed to debt and equity market volatility. 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 March 31, 2024 and 2023

| Net sales: | For the Three Months Ended March 31, 2024 | March 31, 2023 | Change | % Change |
| --- | ---: | ---: | ---: | ---: |
| Oil | $92,294,585 | $83,586,327 | $8,708,258 | 10% |
| Natural gas | (818,235) | 1,064,563 | (1,882,798) | (177)% |
| Natural gas liquids | 3,026,786 | 3,432,022 | (405,236) | (12)% |
| **Total sales** | **$94,503,136** | **$88,082,912** | **$6,420,224** | **7%** |
| **Net production:** |  |  |  |  |
| Oil (Bbls) | 1,218,837 | 1,139,413 | 79,424 | 7% |
| Natural gas (Mcf) | 1,496,507 | 1,601,407 | (104,900) | (7)% |
| Natural gas liquids (Bbls) | 263,802 | 239,992 | 23,810 | 10% |
| **Total production (Boe)(1)** | **1,732,057** | **1,646,306** | **85,751** | **5%** |
| **Average sales price:** |  |  |  |  |
| Oil (per Bbl) | $75.72 | $73.36 | $2.36 | 3% |
| Natural gas (per Mcf) | (0.55) | 0.66 | (1.21) | (183)% |
| Natural gas liquids (Bbl) | 11.47 | 14.30 | (2.83) | (20)% |
| **Total per Boe** | **$54.56** | **$53.50** | **$1.06** | **2%** |

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

***Oil sales.*** Oil sales increased approximately $8.7 million from $83.6 million to $92.3 million due to an increase in sales volume from 1,139,413 barrels of oil to 1,218,837 barrels of oil, further supported by a increase in the average realized price per barrel from $73.36 to $75.72. Of the increase in volume of 79,424 barrels, 157,090 barrels of oil was from wells acquired and new wells drilled in the acreage of the Founders Acquisition offset by natural declines from the legacy assets and sale of non-core assets. The increased average realized price per barrel was primarily the result of higher market conditions.

***Natural gas sales.*** Natural gas sales decreased approximately $1.9 million from $1.1 million to a negative $818,235. While our natural gas sales volume decreased from 1,601,407 Mcf to 1,496,507 Mcf, the average realized price per Mcf decreased from $0.66 to $(0.55). Of the decrease in volume of 104,900 Mcf, 106,419 Mcf was from wells acquired and new wells drilled in the acreage of the Founders Acquisition, and the offsetting decrease of 211,319 Mcf was attributable to legacy assets. The price decrease was driven by lower market conditions. The realized revenue pricing includes the impact of gas plant processing fees that were netted from revenue. For the three months ended March 31, 2024, gross revenues were $1.19 per Mcf and fees were $(1.74) per Mcf, compared to gross revenues of $2.03 per Mcf and fees of $(1.36) per Mcf for the three months ended March 31, 2023. This resulted in a net realized price of $(0.55) for the three months ended March 31, 2024 compared to $0.66 per Mcf for the three months ended March 31, 2023.

***Natural gas liquids sales.*** NGL sales decreased approximately $0.4 million from $3.4 million to $3.0 million. NGL sales volumes for the three months ended March 31, 2024 were 263,802 barrels of NGLs compared to 239,992 barrels of NGLs for the comparable period in 2023. Of the increase in volume of 23,810 barrels, 29,113 barrels were attributable to the wells acquired and new wells drilled within the acreage of the Founders Acquisition, offset by natural declines from the legacy assets and sale of non-core assets. The average realized price per barrel of NGLs was $11.47 for the three months ended March 31, 2024 compared to $14.30 for the three months ended March 31, 2023, attributable to lower market conditions.

### Production Costs for the Three Months Ended March 31, 2024 and 2023

|  | For the Three Months Ended March 31, 2024 | March 31, 2023 | Change | % Change |
| --- | ---: | ---: | ---: | ---: |
| **Lease operating expenses ("LOE")** | **$18,360,434** | **$17,472,691** | **$887,743** | **5%** |
| Average LOE per Boe | $10.60 | $10.61 | $(0.01) | —% |
| **Gathering, transportation and processing costs ("GTP")** | **$166,054** | **$(823)** | **$166,877** | **NM (1)** |
| Average GTP per Boe | $0.10 | $— | $0.10 | 100% |
| **Ad valorem taxes** | **$2,145,631** | **$1,670,613** | **$475,018** | **28%** |
| Average Ad valorem taxes per Boe | $1.24 | $1.01 | $0.23 | 23% |
| **Oil and natural gas production taxes** | **$4,428,303** | **$4,408,140** | **$20,163** | **—%** |
| Average Production taxes per Boe | $2.56 | $2.68 | $(0.12) | (4)% |
| Production taxes as a percentage of total sales | 4.69% | 5.00% | (0.31)% | (6)% |

(1) Not meaningful.

***Lease operating expenses.*** Our total LOE increased from $17.5 million to $18.4 million but remained essentially flat on a per Boe basis, decreasing from $10.61 to $10.60. Total LOE increased primarily due to a 5% increase in production of 85,751 Boe as a result of the new wells acquired from the Founders Acquisition as well as new wells drilled and completed from our development program.

***Gathering, transportation and processing costs.*** Our total GTP increased from $(823) to $166,054 and increased on a per Boe basis from $— to $0.10. 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, GTP costs increased on the period shown due to one remaining contract with a natural gas processing entity in place where point of control of gas dictates requiring the fees be recorded as an expense.

***Ad valorem taxes.*** Our total ad valorem taxes increased from $1.7 million to $2.1 million and increased on a per Boe basis from $1.01 to $1.24. The $0.5 million increase was primarily attributable to the increased appraisal valuations due to increased drilling activity as well as the properties acquired in the Founders Acquisition.

***Oil and natural gas production taxes.*** Oil and natural gas production taxes as a percentage of oil and natural gas sales were 5.00% for the three months ended March 31, 2023 and decreased to 4.69% for the three months ended March 31, 2024. Overall, the percentage was consistent period over period.

### Other Costs and Operating Expenses for the Three Months Ended March 31, 2024 and 2023

| Depreciation, depletion and amortization (DD&A): | For the Three Months Ended March 31, 2024 | March 31, 2023 | Change | % Change |
| --- | ---: | ---: | ---: | ---: |
| Depletion | $23,429,612 | $20,980,542 | $2,449,070 | 12% |
| Depreciation | 101,937 | 105,101 | (3,164) | (3)% |
| Amortization of financing lease assets | 260,901 | 186,028 | 74,873 | 40% |
| **Total depreciation, depletion and amortization** | **$23,792,450** | **$21,271,671** | **$2,520,779** | **12%** |
| Depletion per Boe | $13.53 | $12.74 | $0.79 | 6% |
| Depreciation, depletion and amortization per Boe | $13.74 | $12.92 | $0.82 | 6% |
| **Asset retirement obligation ("ARO") accretion** | **$350,834** | **$365,847** | **$(15,013)** | **(4)%** |
| **Operating lease expense** | **$175,091** | **$113,138** | **$61,953** | **55%** |
| **General and administrative expense ("G&A"):** |  |  |  |  |
| General and administrative expense (excluding Share-based compensation) | $5,745,390 | $5,186,443 | $558,947 | 11% |
| Share-based compensation | 1,723,832 | 1,943,696 | (219,864) | (11)% |
| **Total general and administrative expense** | **$7,469,222** | **$7,130,139** | **$339,083** | **5%** |
| G&A per Boe | $4.31 | $4.33 | $(0.02) | —% |
| G&A excluding Share-based compensation, per Boe | $3.32 | $3.15 | $0.17 | 5% |

***Depreciation, depletion and amortization.*** Our depreciation, depletion and amortization increased from $21.3 million to $23.8 million due to a higher depletion rate as well as an increase of 85,751 in Boe produced. Our average depreciation, depletion and amortization per Boe increased from $12.92 per Boe to $13.74 per Boe, due to the increase in the total costs of property and the decrease in the Boe amortization base.

***Asset retirement obligation accretion.*** Our ARO accretion decreased from $365,847 to $350,834 primarily as a result of wells plugged and abandoned and sold, offset by the additional ARO accretion associated with the properties added from the Founders Acquisition.

***Operating lease expense.*** Our operating lease expense increased from $113,138 to $175,091 due to additional office space leased in The Woodlands office expansion.

***General and administrative expense.*** General and administrative ("G&A") expense increased from $7.1 million to $7.5 million, with the $0.3 million cost increase due to an increase of $0.4 million in salaries and wages, $0.2 million in bad debt expense, $0.1 million in software costs, $0.1 million in legal fees, and $0.1 million in health insurance costs. This was offset by a decrease of $0.2 million in share-based compensation costs and, $0.2 million in insurance costs.

### Other Income (Expense) for the Three Months Ended March 31, 2024 and 2023

|  | For the Three Months Ended March 31, 2024 | March 31, 2023 | Change | % Change |
| --- | ---: | ---: | ---: | ---: |
| **Interest income** | **$78,544** | **$—** | **$78,544** | **100%** |
| **Interest expense:** |  |  |  |  |
| Interest on revolving line of credit | $9,766,051 | $8,709,874 | $1,056,177 | 12% |
| Fees associated with revolving line of credit | 239,628 | 238,174 | 1,454 | 1% |
| Amortization of deferred financing costs | 1,221,607 | 1,220,384 | 1,223 | —% |
| Interest on financing lease liabilities | 31,317 | 25,431 | 5,886 | 23% |
| Interest paid for notes payable | 6,380 | 3,692 | 2,688 | 73% |
| Deferred cash payment accretion | — | 192,724 | (192,724) | (100)% |
| Other interest | 233,961 | — | 233,961 | 100% |
| **Total interest expense** | **$11,498,944** | **$10,390,279** | **$1,108,665** | **11%** |
| **Gain (loss) on derivative contracts:** |  |  |  |  |
| Realized gain (loss): |  |  |  |  |
| Crude oil | $(2,738,970) | $(663,762) | $(2,075,208) | 313% |
| Natural gas | 1,277,455 | 5,237 | 1,272,218 | NM (1) |
| **Total realized gain (loss)** | **$(1,461,515)** | **$(658,525)** | **$(802,990)** | **122%** |
| Unrealized gain (loss): |  |  |  |  |
| Crude oil | $(16,994,322) | $8,107,021 | $(25,101,343) | (310)% |
| Natural gas | (558,658) | 2,026,409 | (2,585,067) | (128)% |
| **Total unrealized gain (loss)** | **$(17,552,980)** | **$10,133,430** | **$(27,686,410)** | **(273)%** |
| **Total gain (loss) on derivative contracts:** | **$(19,014,495)** | **$9,474,905** | **$(28,489,400)** | **(301)%** |
| **Gain on disposal of assets** | **$38,355** | **$—** | **$38,355** | **100%** |
| **Other income** | **$25,686** | **$9,600** | **$16,086** | **168%** |

(1) Not meaningful.

***Interest income.*** Interest income of $78,544 was accrued from excess cash balances in bank sweep accounts beginning in May 2023.

***Interest expense.*** Interest expense increased from $10.4 million to $11.5 million primarily due to the result of higher amounts outstanding on our Credit Facility, with a weighted average daily debt of approximately $428.8 million during the three months ended March 31, 2024 compared to approximately $424.3 million during the three months ended March 31, 2023. Additionally, the increase in interest expense was due to higher interest rates, with a weighted average annual interest rate of 9.3% during the three months ended March 31, 2024 compared to 8.2% during the three months ended March 31, 2023.

***Gain (loss) on derivative contracts.*** We recorded a loss on derivative contracts of $19.0 million for the three months ended March 31, 2024 and a gain on derivative contracts of $9.5 million for the three months ended March 31, 2023. For the derivative contract settlements, we recorded a realized loss of $1.5 million for the three months ended March 31, 2024 and a realized loss of $0.7 million for the three months ended March 31, 2023. The increase of $0.8 million in the realized loss was a result of less favorable settlements of derivative contracts during the current year. For the marked-to-market contracts, we recorded an unrealized loss of $17.6 million for the three months ended March 31, 2024 and an unrealized gain of $10.1 million for the three months ended March 31, 2023. This change in unrealized derivatives primarily was due to losses on higher crude oil futures prices on derivative contracts in the Company's portfolio.

***Gain (loss) on disposal of assets.*** We recognized a gain of $38,355 on disposal from selling multiple Company owned vehicles.

***Other income.*** This income primarily resulted from the Company's charge card rebate program.

### Benefit from (Provision for) Income Taxes for the Three Months Ended March 31, 2024 and 2023

| Benefit from (Provision for) Income Taxes: | For the Three Months Ended March 31, 2024 | March 31, 2023 | Change | % Change |
| --- | ---: | ---: | ---: | ---: |
| Deferred federal income tax benefit (provision) | $(1,551,759) | $(1,529,249) | $(22,510) | 1% |
| Current state income tax benefit (provision) | (102,633) | (57,291) | (45,342) | 79% |
| Deferred state income tax benefit (provision) | (74,494) | (443,403) | 368,909 | (83)% |
| **Benefit from (Provision for) Income Taxes** | **$(1,728,886)** | **$(2,029,943)** | **$301,057** | **(15)%** |

***Benefit from (Provision for) income taxes.*** The benefit from (provision for) income taxes changed from a provision of $2.0 million for the three months ended March 31, 2023 to a provision of $1.7 million for the three months ended March 31, 2024. Current income taxes reflect estimated state and federal income taxes due for 2024 which is based on our estimated earnings, taking into account all applicable tax rates and laws.

### Liquidity and Capital Resources

As of March 31, 2024, we had cash on hand of $1.4 million, compared to $0.3 million as of December 31, 2023. We had net cash provided by operating activities for the three months ended March 31, 2024 of $45.2 million, compared to net cash provided by operating activities of $43.7 million for the same period in 2023, which was primarily due to higher year to date revenues, which resulted in more cash received from purchasers. We had net cash used in investing activities of $39.5 million for the three months ended March 31, 2024, compared to net cash used in investing activities of $55.5 million for the same period in 2023, driven by the deferred cash payment made for the Stronghold Acquisition in the first quarter of 2023, with no comparable payment made to date in 2024. Net cash used in financing activities was $4.6 million for the three months ended March 31, 2024 during which time $3 million was the net pay down of principal on our Credit Facility.

We will continue to focus on maximizing cash flow in 2024 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.

During the remainder of 2024, we will remain focused on maximizing cash flow, reducing our debt level, and maximizing our liquidity.

### Availability of Capital Resources under Credit Facility

As of March 31, 2024, $422 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 August 2026. The borrowing base under our Credit Facility is $600 million. The borrowing base is redetermined semi-annually on 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 March 31, 2024 (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) Q2 2024 | Q3 2024 | Q4 2024 | Q1 2025 | Q2 2025 | Q3 2025 | Q4 2025 | Q1 2026 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Hedged volume (Bbl) | 156,975 | 282,900 | 368,000 | — | — | 184,000 | — | 387,000 |
| Weighted average swap price | $66.40 | $65.49 | $68.43 | $— | $— | $73.35 | $— | $70.11 |
| **Deferred premium puts:** |  |  |  |  |  |  |  |  |
| Hedged volume (Bbl) | 45,500 | — | — | — | — | — | — | — |
| Weighted average strike price | $82.80 | $— | $— | $— | $— | $— | $— | $— |
| Weighted average deferred premium price | $17.49 | $— | $— | $— | $— | $— | $— | $— |
| **Two-way collars:** |  |  |  |  |  |  |  |  |
| Hedged volume (Bbl) | 334,947 | 230,000 | 128,800 | 474,750 | 464,100 | 225,400 | 404,800 | — |
| Weighted average put price | $64.32 | $64.00 | $60.00 | $57.06 | $60.00 | $65.00 | $60.00 | $— |
| Weighted average call price | $79.16 | $76.50 | $73.24 | $75.82 | $69.85 | $78.91 | $75.68 | $— |

| NYMEX Swaps: | Gas Hedges (Henry Hub) Q2 2024 | Q3 2024 | Q4 2024 | Q1 2025 | Q2 2025 | Q3 2025 | Q4 2025 | Q1 2026 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Hedged volume (MMBtu) | 86,059 | 121,587 | 644,946 | 616,199 | 591,725 | 285,200 | — | — |
| Weighted average swap price | $3.62 | $3.59 | $4.45 | $3.78 | $3.43 | $3.73 | $— | $— |
| **Two-way collars:** |  |  |  |  |  |  |  |  |
| Hedged volume (MMBtu) | 405,650 | 584,200 | 27,600 | 27,000 | 27,300 | 308,200 | 598,000 | 553,500 |
| Weighted average put price | $3.94 | $3.94 | $3.00 | $3.00 | $3.00 | $3.00 | $3.00 | $3.50 |
| Weighted average call price | $6.16 | $6.17 | $4.15 | $4.15 | $4.15 | $4.75 | $4.15 | $5.03 |

| Argus basis swaps: | Oil Hedges (basis differential) Q2 2024 | Q3 2024 | Q4 2024 | Q1 2025 | Q2 2025 | Q3 2025 | Q4 2025 | Q1 2026 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Hedged volume (Bbl) | 244,000 | 368,000 | 368,000 | 270,000 | 273,000 | 276,000 | 276,000 | — |
| Weighted average spread price (1) | $1.15 | $1.15 | $1.15 | $1.00 | $1.00 | $1.00 | $1.00 | $— |

(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.

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 March 31, 2024, 100% of our derivative instruments are 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 March 31, 2024, 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 possibly increase our debt. 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 proforma information regarding such oil and gas properties. Even though we may incur such costs, there is no assurance that we will ultimately be able to consummate other acquisitions of oil and gas producing properties.

## Market risk

As filed, 3,662 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 adverse changes in oil and natural gas prices. Realized pricing is primarily driven by the prevailing domestic price for crude oil and spot prices applicable to the region in which we produce oil and natural gas. 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 decline 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 $34.4 million as of March 31, 2024). 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 three months ended March 31, 2024. We believe that the loss of any of these purchasers would not materially impact our business because we could readily find other purchasers for our oil and natural gas.

| Purchaser: | For the Three Months Ended March 31, 2024 Percentage of Oil, Natural Gas, and Natural Gas Liquids Revenues | As of March 31, 2024 Percentage of accounts receivables from the sale of our oil and natural gas production |
| --- | ---: | ---: |
| Phillips 66 Company ("Phillips") | 61% | 59% |
| Concord Energy LLC ("Concord") | 13% | 12% |
| LPC Crude III, LLC ("LPC Crude") | 12% | 11% |

### 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 March 31, 2024, we had $422 million outstanding on our Credit Facility with a weighted average annual interest rate for the three months ended March 31, 2024 of 9.3%. A 1% change in the interest rate on our Credit Facility would result in an estimated $4.2 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, 2,493 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 March 31, 2024 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, 2023 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 May 6, 2024.
Source: SEC EDGAR, the filing index for accession 0001628280-24-020695. Last ingested by Listed: Nov 3, 2026, 20:51 ET. No prices; not investment advice.