RING ENERGY INC

General Background

Ring is engaged in oil and natural gas development, production, acquisition, and exploration activities currently focused in the Permian Basin of Texas.

Management’s Business Strategy Related to Properties

Our goal is to increase stockholder value by investing in oil and natural gas projects with attractive rates of return on capital employed. We plan to achieve this goal by developing our existing oil and natural gas properties and pursuing strategic acquisitions of additional properties.

Developing Existing Properties

We believe that there is significant value to be created by drilling the undeveloped opportunities on our properties. As of December 31, 2024, we owned interests in a total of 76,284 gross (65,342 net) developed acres and operate the vast majority of our acreage position. In addition, as of December 31, 2024, we owned interests in approximately 21,315 gross (15,577 net) undeveloped acres. While our near-term plans are focused on drilling wells on our existing acreage to develop the potential contained therein, our long-term plans also include continuing to evaluate acquisition and leasing opportunities that can earn attractive rates of return on capital employed.

Within the Northwest Shelf, we have a total of 35 proved undeveloped locations (100% horizontal) and 3 PDNP opportunities based on the reserve report as of December 31, 2024. Our reserve estimates account for the capital costs required to develop these wells and the future plugging and abandonment costs. We believe the Northwest Shelf leases contain additional potential drilling locations.

Within the Central Basin Platform, we had a total of 176 proved undeveloped locations (13% horizontal and 88% vertical) and 217 PDNP opportunities based on the reserve report as of December 31, 2024. Our reserve estimates account for the capital costs required to develop these wells and the future plugging and abandonment costs. We believe the Central Basin Platform leases contain additional potential drilling locations.

Pursuing Profitable Acquisitions

We have historically pursued acquisitions of properties that we believe to have exploitation and development potential comparable to our existing inventory of drilling locations. We have an experienced team of management, engineering, geoscience, and land professionals who identify and evaluate acquisition opportunities, negotiate and close purchases and manage acquired properties.

Summary of Oil and Natural Gas Properties and Projects

Significant Operations

The Company's significant operations are in two core areas which it has actively drilled over the last several years located in the Northwest Shelf and the Central Basin Platform of the Permian Basin.

Northwest Shelf – Yoakum County, Texas and Lea County, New Mexico –In 2019, we acquired properties consisting of 49,754 gross (38,230 net) acres with an average working interest of 77% and an average net revenue interest of 58%. As of December 31, 2024, we owned interests in a total of 12,572 gross (8,722 net) developed acres and 14,979 gross (11,548 net) undeveloped acres with an average proved operated working interest of 91% and net revenue interest of 69%. As of December 31, 2024, the Company had interests in approximately five gross vertical and 151 gross horizontal producing wells, of which we operate five vertical and 116 horizontal wells. The horizontal wells predominately produce from the San Andres conventional reservoir and the verticals produce from Wolfcamp reservoir.

Central Basin Platform – Andrews, Gaines, Crane, Ector, Winkler, and Ward Counties, Texas – In 2011, we acquired a 100% working interest and a 75% net revenue interest in our initial leases in Andrews County. Since that time, we have acquired working and net revenue interests in additional producing leases and acquired additional undeveloped acreage in and around our Andrews County and Gaines County leases. In 2022, we acquired properties consisting of approximately 37,000 net acres, with an average working interest of 99% and an average net revenue interest of 88% for oil and 96% for natural gas in our initial leases in Crane, Winkler, and Ward counties. In 2023, we acquired properties in Ector County. As of December 31, 2024, we owned interests in a total of 63,712 gross (56,620 net) developed acres and 6,336 gross (4,029 net) undeveloped acres with an average proved operated working interest of 97% and net revenue interest of 83% in the area. As of December 31, 2024, the Company had interests in approximately 581 gross vertical and 198 gross horizontal producing wells, of which we operate 470 vertical and 196 horizontal wells. The horizontal wells predominately produce from the San Andres conventional reservoir and the vertical wells produce from a variety of conventional pay sands including Holt, Glorieta, Clear Fork, Wichita Albany, Tubb, Wolfcamp and Devonian reservoirs.

Title to Properties

We generally conduct a preliminary title examination prior to the acquisition of properties or leasehold interests. Prior to commencement of operations on such acreage, a thorough title examination is usually conducted and any significant defects are remedied before proceeding with operations. We believe the title to our leasehold properties is good, defensible, and customary with practices in the oil and natural gas industry, subject to such exceptions that we believe do not materially detract from the use of such properties. With respect to our properties of which we are not the record owner, we rely on contracts with the owner or operator of the property or assignment of leases, pursuant to which, among other things, we generally have the right to have our interest placed on record.

Our properties are generally subject to royalty, overriding royalty and other interests customary in the industry, liens incident to lending agreements, current taxes and other customary burdens, minor encumbrances, easements, and restrictions. We do not believe any of these burdens materially interfere with our use of these properties.

Summary of Oil and Natural Gas Reserves

As of December 31, 2024, our estimated proved reserves had a pre-tax PV-10 value (present value discounted at 10%) of approximately $1,462.8 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $1,232.9 million, over 99.7% of which relates to our properties in the Permian Basin in Texas. We spent approximately $391.6 million on acquisitions and capital projects during 2024 and 2023. We expect to further develop these properties through additional drilling.

The following table summarizes our total net proved reserves, pre-tax PV-10 value and Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2024. Approximately 99.8% of our proved reserves are in the Permian Basin in Texas.

(1) Six Mcf is deemed the equivalent of one Boe.

(2) PV-10 is a non-GAAP financial measure. See below for a reconciliation.

We present the pre-tax PV-10 value, which is a non-GAAP financial measure, because it is a widely used industry standard which we believe is useful to those who may review this Report when comparing our asset base and performance to other comparable oil and natural gas exploration and production companies. PV-10 is a non-GAAP measure that differs from a measure under accounting principles generally accepted in the United States ("GAAP") known as “standardized measure of discounted future net cash flows” in that PV-10 is calculated without including future income taxes. PV-10 does not necessarily represent the fair market value of oil and natural gas properties. PV-10 is not a measure of financial or operational performance under GAAP, nor should it be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.

The table below provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows:

Reserve Quantity Information

Our estimates of proved reserves and related valuations are based on reports independently determined and prepared by Cawley, Gillespie & Associates, Inc. ("CGA"), independent petroleum engineers. These reserves are attributable solely to properties within the United States. A summary of the changes in quantities of proved (developed and undeveloped) oil, natural gas, and natural gas liquid reserves is shown below.

(1)Six Mcf is deemed the equivalent of one Boe.

(2)At year-end 2022, we began reporting reserves on a three-stream basis, including NGLs separately from natural gas.

Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history, a rule that undeveloped reserves must be drilled within five years of originally being booked, and/or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.

Notable changes in proved reserves for the year ended December 31, 2024 included the following:

•Extensions. In 2024, extensions of 16.0 MMBoe were primarily the result of the successful operated drilling program in the Northwest Shelf and Central Basin Platform.

•Purchase of minerals in place. In 2024, the Company did not purchase any additional reserves.

•Sales of minerals in place. In 2024, the Company sold 1.2 MMBoe from the divestiture of certain oil and gas properties, including vertical wells and associated facilities, within the Central Basin Platform in Andrews and Gaines Counties.

•Revision of previous estimates. In 2024, the negative revisions of prior reserves of 3.2 MMBoe consisted of a positive 0.2 MMBoe related to changes in price (including differentials and gathering related contract change that effects differentials), offset by a negative 3.4 MMBoe related to changes in performance and other economic factors.

Our proved oil, natural gas, and natural gas liquid reserves are shown below.

(1) Six Mcf is deemed the equivalent of one Boe.

Our standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves and changes in the standardized measure as described below were prepared in accordance with GAAP.

Future income tax expenses are calculated by applying appropriate year-end tax rates to future pre-tax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences, tax credits, and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value of our oil and natural gas properties.

Our estimates of reserves and future cash flow as of December 31, 2024 and 2023 were prepared using an average price equal to the unweighted arithmetic average of the first day of the month price for each month within the 12-month periods ended December 31, 2024 and 2023, respectively, in accordance with SEC guidelines. As of December 31, 2024, our reserves were based on an SEC average price of $71.96 per Bbl of WTI oil posted and $2.130 per MMBtu of Henry Hub natural gas. As of December 31, 2023, our reserves were based on an SEC average price of $74.70 per Bbl of WTI oil posted and $2.637 per MMBtu Henry Hub natural gas. Prices are adjusted by local field and lease level differentials and are held constant for life of reserves in accordance with SEC guidelines.

The standardized measure of discounted future net cash flows relating to the proved oil, natural gas, and NGLs reserves are shown below.

(1) Future development costs include not only development costs but also future asset retirement costs.

The changes in the standardized measure of discounted future net cash flows relating to the proved oil, natural gas and natural gas liquid reserves are shown below.

Changes in Standardized Measure of Discounted Future Net Cash Flows

Our proved reserves by state as of December 31, 2024 are summarized in the table below.

Proved Reserves

As of December 31, 2024, we had approximately 134.2 MMBoe of proved reserves, consisting of approximately 60% oil, 19% natural gas, and 21% NGLs, as summarized in the table above. Our reserve estimates have not been filed with any Federal authority or agency (other than the SEC).

As of December 31, 2024, approximately 69% of the proved reserves were classified as PD and the remaining 31% were PUD.

As of December 31, 2024, our total proved reserves had a net pre-tax PV-10 value of approximately $1,462.8 million and a Standardized Measure of Discounted Future Net Cash Flows ("SMOG") of approximately $1,232.9 million. Approximately $1,130.2 million pre-tax PV-10 and $952.6 million SMOG, respectively, of total proved reserves are associated with the PD reserves, which is approximately 77% of the total proved reserves’ pre-tax PV-10 value. The remaining $332.7 million pre-tax PV-10 and $280.4 million SMOG, respectively, are associated with PUD reserves.

Proved Undeveloped Reserves

Our reserve estimates as of December 31, 2024 include approximately 41.6 MMBoe as PUDs. As of December 31, 2023, our reserve estimates included approximately 41.6 MMBoe as PUDs. In accordance with our December 31, 2024 year-end independent engineering reserve report, we plan to drill our PUD drilling locations within five years of original classification. Below is a description of the changes in our PUD reserves from December 31, 2023 to December 31, 2024.

Notable changes in proved undeveloped reserves for the year ended December 31, 2024 included the following:

•Conversions to developed. During the year ended December 31, 2024, we incurred costs of approximately $64.7 million to convert 33 properties from PUD to PD through development. These 33 properties produced 893 MBoe during the year ended December 31, 2024, and have reserves of 6,538 MBoe as of December 31, 2024.

•Extensions. In 2024, extensions of 12.8 MMBoe were primarily the result of the successful operated drilling program in the Northwest Shelf and Central Basin Platform.

•Purchase of minerals in place. In 2024, we did not purchase any additional reserves.

•Sales of minerals in place. In 2024, we sold 0.1 MMBoe from the divestiture of certain oil and gas properties within the Central Basin Platform.

•Revision of previous estimates. In 2024, the negative revisions of prior reserves of 5.6 MMBoe consisted of a positive 0.2 MMBoe (4%) related to changes in price (including differentials and gathering related contract change that effects differentials) offset by a negative 5.8 MMBoe (104%) related to changes in performance and other economic factors.

The following table indicates projected reserves that we currently estimate will be converted from proved undeveloped to proved developed, as well as the estimated costs per year involved in such development. Our PUD reserves are part of a management adopted development plan that schedules PUD reserves to be developed within five years of initial disclosure as proved reserves. As of December 31, 2024, no material amount of proved undeveloped reserves were not scheduled to be converted to proved developed status within five years of when they were initially disclosed.

Estimated Costs Related to Conversion of Proved Undeveloped Reserves to Proved Developed Reserves

Preparation and Internal Controls Over Reserves Estimates

All the proved oil and natural gas reserves disclosed in this Report are based on reserve estimates determined and prepared by our independent reserve engineers, Cawley, Gillespie & Associates, Inc. (“CGA”), a leader of petroleum property analysis for industry and financial institutions. CGA was founded in 1960 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-693. Within CGA, the technical person primarily responsible for preparing the estimates set forth in the CGA letter dated January 24, 2025, filed as an exhibit to this Annual Report, was Mr. Zane Meekins. Mr. Meekins has been a practicing consulting petroleum engineer at CGA since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas (License No. 71055) and has over 37 years of practical experience in petroleum engineering, with over 35 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a Bachelor of Science degree in Petroleum Engineering. Mr. Meekins meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

The proved oil and natural gas reserves disclosed in this Annual Report are based on reserve estimates determined and prepared by our independent reserve engineers primarily using decline curve analysis to determine the reserves of individual producing wells. To establish reasonable certainty with respect to our estimated proved reserves, the independent reserve engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using volumetric estimates or performance from analogous wells in the surrounding area. These wells were considered to be analogous based on production performance from the same formation and completions using similar techniques. The technologies and economic data used to estimate our proved reserves include, but are not limited to, well logs, geological maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests. This data was reviewed by various levels of our management for accuracy before consultation with our independent reserve engineers. This consultation included review of properties, assumptions, and available data. Internal reserve estimates were compared to those prepared by CGA to test the estimates and conclusions before the reserves were included in this Annual Report. The accuracy of the reserve estimates is dependent on many factors, including the following:

•the quality and quantity of available data and the engineering and geological interpretation of that data;

•estimates regarding the amount and timing of future costs, which could vary considerably from actual costs;

•the accuracy of economic assumptions; and

•the judgment of the personnel preparing the estimates.

Our Executive Vice President of Engineering and Corporate Strategy, Mr. Alex Dyes, is the technical professional primarily responsible for overseeing the preparation of our reserves estimates. He has a Bachelor of Science degree in Petroleum Engineering from the University of Texas with over 18 years of practical industry experience, including over 14 years of estimating and evaluating reserve information. He has been a member of the Society of Petroleum Engineers since 2013 and his qualifications meet or exceed the Society of Petroleum Engineers’ standard requirements to be a professionally qualified Reserve Estimator and Auditor.

We encourage ongoing professional education for our engineers and reservoir analysts on new technologies and industry advancements as well as refresher training on basic skill sets. In order to ensure the reliability of reserves estimates, our Corporate Reserves department follows comprehensive SEC-compliant internal controls and policies to determine, estimate, and report proved reserves including:

•confirming that we include reserves estimates for all properties owned and that they are based upon proper working and net revenue interests;

•ensuring the information provided by other departments within the Company, such as accounting, land, and operations is accurate;

•communicating, collaborating, and analyzing with technical personnel in our business units;

•comparing and reconciling the internally generated reserves estimates to those prepared by third parties; and

•utilizing experienced reservoir engineers or those under their direct supervision to prepare reserve estimates.

Each quarter, the Corporate Reserves team along with the Executive Vice President of Engineering and Corporate Strategy presents the status of the Company’s reserves to senior executives, and subsequently obtains approval of significant changes from key executives. Additionally, our five-year PUD development plan is reviewed and approved annually by the Company’s Chief Executive Officer; Chief Financial Officer; Executive Vice President of Engineering and Corporate Strategy; Vice President of Operations; Executive Vice President, Exploration and Geosciences; and Vice President, General Counsel.

The Corporate Reserves department works closely with independent reserve engineers from CGA at each fiscal year end to ensure the integrity, accuracy, and timeliness of annual independent reserves estimates. These independently developed reserves estimates are presented to the Audit Committee. In addition to reviewing the independently developed reserve reports, the Audit Committee also meets with CGA annually at a minimum.

Summary of Oil and Natural Gas Properties and Projects

Acreage

The following table summarizes our gross and net developed and undeveloped acreage as of December 31, 2024 by region (net acreage is our percentage ownership of gross acreage). Acreage in which our interest is limited to royalty and overriding royalty interests is excluded, as it is de minimis.

Leases of undeveloped acreage will generally expire at the end of their respective primary terms unless production from such leasehold acreage has been established prior to expiration of such primary terms. If production is established on the acreage, the lease will generally remain in effect until the cessation of production from the acreage and is referred to in the industry as HBP. Leases of undeveloped acreage may terminate or expire as a result of not meeting certain drilling commitments, if any, or otherwise by not complying with the terms of a lease depending on the specific terms that are negotiated between the lessor and the lessee.

The following table sets forth our gross and net undeveloped acreage, as of December 31, 2024, under lease that will expire over the next three years unless (i) production is established on the lease or within a spacing unit of which the lease is participating, or (ii) the lease is renewed or extended prior to the relevant expiration dates:

Production History

The following table presents the historical information regarding our produced oil, natural gas and natural gas liquid volumes for the years ended December 31, 2024, 2023, and 2022:

(1) Due to our acquisition of Stronghold's assets, which reported its volumes and revenues on a three-stream basis, beginning July 1, 2022, we began reporting volumes and revenues on a three-stream basis, separately reporting crude oil, natural gas, and NGL sales. For periods prior to July 1, 2022, sales and reserve volumes, prices, and revenues for NGLs were presented with natural gas.

(2)The Delaware Basin assets were sold with a closing date of May 11, 2023 and an effective date of March 1, 2023.

Production Prices and Production Costs

The following tables provides historical pricing and costs statistics for the years ended December 31, 2024, 2023, and 2022.

(1) Due to our acquisition of Stronghold's assets, which reported its volumes and revenues on a three-stream basis, beginning July 1, 2022, we began reporting volumes and revenues on a three-stream basis, separately reporting crude oil, natural gas, and NGL sales. For periods prior to July 1, 2022, sales and reserve volumes, prices, and revenues for NGLs were presented with natural gas.

(2) In accordance with the IRA, the EPA implemented a waste emission charge ("WEC") on methane emitted from applicable oil and gas facilities that exceed certain thresholds. The methane charge became effective in 2024 at $900 per metric ton of methane, and is set to increase to $1,200 per metric ton of methane for 2025, and $1,500 per metric ton of methane by 2026 and thereafter. For the year ended December 31, 2024, we accrued for $527,687 in methane taxes within Ad valorem taxes in our Statements of Operations.

The average oil sales price amounts above are calculated by dividing revenue from oil sales by the volume of oil sold, in Bbls. The average natural gas sales price amounts above are calculated by dividing revenue from natural gas sales by the volume of natural gas sold, in Mcf. The average NGL sales price amounts above are calculated by dividing revenue from NGL sales by the volume of NGLs sold, in Bbls. The total average sales price amounts are calculated by dividing total revenues by total volume sold, in Boe. The average production costs above are calculated by dividing production costs by total production in Boe.

Productive Wells

The following table presents our ownership as of December 31, 2024 in productive oil and natural gas wells (a net well is our percentage ownership of a gross well). Approximately 99.8% of such wells are in the Permian Basin in Texas.

Drilling Activities

During 2024, as operator, we drilled a total of 44.00 gross (43.94 net) wells. Of this, 5.00 gross (4.94 net) horizontal San Andres wells were in the Northwest Shelf in Yoakum County (four 1.0-mile laterals and one 1.5-mile lateral) and 39.00 gross (39.00 net) wells were in the Central Basin Platform, of which seventeen were horizontal San Andres wells in Andrews County and Crane County, Texas (all 1.0-mile laterals) and 22.00 were vertical wells in Crane County, and Ector County, Texas. These wells were successful and there were no dry wells(1).

The table below contains information regarding the number of operated wells drilled and/or participated in during the periods indicated.

(1)One of the 44.00 drilled wells has been drilled but not yet completed as of December 31, 2024.

The table below contains information regarding the number of non-operated wells drilled and participated in during the periods indicated.

Present Activities

We had one operated well waiting on completion as of December 31, 2024.

Cost Information

We conduct our oil and natural gas activities entirely in the United States. As can be calculated from the table under “Production Prices and Production Costs”, our average production costs including lease operating expenses, gathering, transportation and transportation ("GTP") and ad valorem, per Boe, were $12.08 and $11.70 for the years ended December 31, 2024 and 2023, respectively. As shown in the aforementioned table, our average production taxes, per Boe, were $2.24 and $2.74 for the years ended December 31, 2024 and 2023, respectively. These amounts are calculated by dividing our total production costs or total production taxes by our total volume sold, in Boe.

Costs incurred for property acquisition, exploration and development activities for the years ended December 31, 2024, 2023 and 2022 are shown below:

Other Properties and Commitments

Effective January 1, 2021, the Company moved its corporate headquarters to The Woodlands, Texas. Prior to this, our principal offices were in Midland, Texas. Those offices now serve as an operations office.