UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 1-K

ANNUAL REPORT PURSUANT TO REGULATION A OF

THE SECURITIES ACT OF 1933

For the fiscal year ended: December 31, 2024

PHOENIX ENERGY ONE, LLC

(Exact name of issuer as specified in its charter)

Delaware	83-4526672
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

4643 South Ulster Street, Suite 1510

Denver, CO 80237

18575 Jamboree Road, Suite 830

Irvine, CA 92612

152 North Durbin Street, Suite 220

Casper, WY

(Full mailing address of principal executive offices)

(303) 749-0074

(Issuer’s telephone number, including area code)

STATEMENTS REGARDING FORWARD-LOOKING INFORMATION AND FIGURES

This Annual Report on Form 1-K (this “Annual Report”) of Phoenix Energy One, LLC, a Delaware limited liability company, contains certain forward-looking statements that are subject to various risks and uncertainties. Forward-looking statements are generally identifiable by use of forward-looking terminology such as “may,” “will,” “should,” “potential,” “intend,” “expect,” “outlook,” “seek,” “anticipate,” “estimate,” “approximately,” “believe,” “could,” “project,” “predict,” or other similar words or expressions. Forward-looking statements are based on certain assumptions, discuss future expectations, describe future plans and strategies, contain financial and operating projections, or state other forward-looking information. Our ability to predict results or the actual effect of future events, actions, plans or strategies is inherently uncertain. Although we believe that the expectations reflected in our forward-looking statements are based on reasonable assumptions, our actual results and performance could differ materially from those set forth or anticipated in our forward-looking statements. Factors that could have a material adverse effect on our forward-looking statements and upon our business, results of operations, financial condition, funds derived from operations, cash flows, liquidity, and prospects include, but are not limited to, the factors referenced in our offering circular on Form 1-A, filed with the U.S. Securities and Exchange Commission (the “SEC”) on March 18, 2024 pursuant to Rule 253(g)(2) (the “Offering Circular”), under the caption “Risk Factors” and which are incorporated herein by reference (https://www.sec.gov/Archives/edgar/data/1818643/000119312524069740/d540270dpartiiandiii.html).

When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements contained or incorporated by reference in this Annual Report. Readers are cautioned not to place undue reliance on any of these forward-looking statements, which reflect our views as of the date of this Annual Report. The matters summarized below and elsewhere in this Annual Report could cause our actual results and performance to differ materially from those set forth or anticipated in forward-looking statements. Accordingly, we cannot guarantee future results or performance. Furthermore, except as required by law, we are under no duty to, and we do not intend to, update any of our forward-looking statements after the date of this Annual Report, whether as a result of new information, future events, or otherwise.

As used herein, “we,” “us,” “our,” the “Company,” “Phoenix Energy,” and similar references refer to Phoenix Energy One, LLC, formerly known as Phoenix Capital Group Holdings, LLC, and, where appropriate, its subsidiaries.

Item 1. Business

Overview

Phoenix Energy One, LLC, a Delaware limited liability company, was formed on April 23, 2019. We operate in the oil and gas industry and execute on a three-pronged strategy involving (i) direct drilling operations of operated working interests, (ii) the acquisition of royalty assets, and (iii) the acquisition of non-operated working interest assets. Our direct drilling operations are currently primarily focused on development efforts in the Williston Basin in North Dakota and Montana and the Powder River and Denver Julesburg Basins in Wyoming. Our royalty and working interest acquisitions center around a variety of assets, including mineral interests, leasehold interests, overriding royalty interests, and perpetual royalty interests. These efforts have historically targeted assets in the Williston, Permian, Powder River, Uintah, and DJ Basins. We are agnostic as to geography and prioritize operational and asset potential when executing on our strategy.

We began operations in 2019 with the development of our specialized software system, which we have designed and improved over time to support our ability to identify, analyze, underwrite, transact, and manage our oil and gas assets. In 2019, we acquired our first mineral interest asset and began to generate revenue. In 2020, we expanded our operations and team to include specialists across a variety of key focus areas. From 2020 to 2024, we experienced significant growth in operations. For example, in 2020, the exploration and production (“E&P”) operators of our properties operated 725 gross and 2.8 net productive development wells on the acreage underlying our mineral and royalty interests, and the total acreage underlying our gross and net royalty interests was 177,824 and 1,506, respectively. In the four years since then, the E&P operators of our properties have operated an additional 6,312 gross and 75.1 net productive development wells on the acreage underlying our mineral and royalty interests, of which approximately 463 gross and 43.2 net productive development wells were drilled in 2024 alone. As of December 31, 2024, we had 3,962,065 and 531,120 acres underlying our gross and net royalty interests, respectively, as compared to 177,824 and 1,506 acres underlying our gross and net royalty interests, respectively, at December 31, 2020. Furthermore, our total production for the year ended December 31, 2020 was under 0.2 million Boe (as defined below) as compared to over 4.7 million Boe for the year ended December 31, 2024. In the same period, our number of employees grew from 21 at December 31, 2020 to 135 at December 31, 2024. Additionally, we commenced direct drilling operations and spudded our first wells in the third quarter of 2023 and drilled a total of 42 gross and 38.6 net productive development wells in 2024. We expect these direct drilling operations to be a core component of our business strategy going forward.

Since our initial mineral interest asset acquisition in 2019, we have leveraged our specialized software system and experienced management team to identify asset opportunities that fit our desired criteria and potential for returns. While we evaluate and acquire a wide variety of assets, we have historically prioritized assets with potential for high monthly recurring cashflows and primarily target assets that have a potential payback within the short to medium-term and long-term cashflows.

Since 2019, we have completed 3,074 mineral, royalty, and leasehold interest acquisitions from landowners and other mineral interest owners, representing approximately 531,120 net royalty acres (“NRAs”) of royalty assets and 476,473 of net mineral acres (“NMAs”) of leasehold assets as of December 31, 2024. Over that same period, in addition to completing numerous small transactions, we completed more than 56 transactions larger than 1,000 NMAs that account for approximately 72% of our NMAs. We have acquired mineral, royalty, and leasehold interests from individuals, families, trusts, partnerships, small minerals aggregators, minerals brokers, large private minerals companies, private oil and gas E&P companies, and public minerals companies. We also actively manage our portfolio of assets and, as of December 31, 2024, have sold 3,152 NMAs since 2019.

Following the acquisition of an asset, we typically share in the proceeds of the natural resources extracted and sold by a third-party E&P operator. For certain assets, we operate our own direct drilling operations through our direct wholly owned subsidiary, Phoenix Operating LLC, a Delaware limited liability company (“PhoenixOp”).

For the years ended December 31, 2022, 2023, and 2024, we had revenue of $54.6 million, $118.1 million, and $281.2 million, respectively, net income (loss) of $5.7 million, $(16.2) million, and $(24.8) million, respectively, and EBITDA (as defined below) of $29.7 million, $65.9 million, and $150.7 million, respectively. As of December 31, 2022, 2023, and 2024, we had total assets of $157.0 million, $493.2 million, and $1,029.1 million, respectively, total liabilities of $148.3 million, $498.0 million, and $1,063.1 million, respectively (inclusive of total indebtedness of $117.4 million, $447.9 million, and $987.9 million, respectively), and retained earnings (accumulated deficit) of $6.5 million, $(9.7) million, and $(34.5) million, respectively. In 2023 and 2024, we incurred a significant amount of debt in order to accelerate the growth of our business by acquiring additional assets and establishing our direct drilling operations. As a result, our cash flows from operations alone would not have been sufficient to service the required cash interest and principal payment obligations under our then-existing debt in 2023 and 2024. Although we expect our cash flows from operations to be sufficient to service such obligations going forward, there can be no assurance as to the sufficiency of our cash flows for that purpose, and we may require additional liquidity to service our debt. As a result, we may use the proceeds of additional debt to make interest and principal payments on our existing debt.

Market Opportunity

Our royalty and working interest acquisitions generally focus on specific subsets of mineral and leasehold assets in the United States. From a market perspective, we focus on highly attractive and defined basins, currently serviced by top-tier operators, with assets that we believe will generate high near-term cash flow. All the assets we seek to acquire are purchased at what management believes are attractive price points and have a liquidity profile that is desirable in the secondary market. We generally seek to acquire assets that have near-term payback and long-term residual cash flow upside.

Business Strategy

Our three-pronged strategy centers around (i) direct drilling operations of operated working interests, (ii) the acquisition of royalty assets, and (iii) the acquisition of non-operated working interest assets.

Direct Drilling Operations

We currently run our own direct drilling activities through PhoenixOp. Throughout 2024, we increased the extent to which we run our own direct drilling operations and expect to continue to grow our drilling activities going forward. We intend to actively drill and develop select assets in an effort to maximize value and resource potential, and we will generally seek to increase our production, reserves, and cash flow from operations over time. We have identified a number of potential drilling locations that we believe have the potential for attractive growth and opportunities. In accordance with that business plan, we acquired our second drilling rig in October 2024 and signed an agreement in January 2025 to take possession of our third drilling rig in April 2025.

As we rely more on our own direct drilling operations, our capital expenditures and operating expenses have also increased significantly, and we expect this increase in capital and operating expenses to continue as compared to our previous business model, which relied heavily on royalty and working interest acquisitions. As such, in 2025, we expect to have increased needs for additional capital in excess of cash flows from operating activities. We expect to require additional outside funding to successfully execute this business strategy. Although we believe that running our own direct drilling operations will require significantly greater funds than partnering with a third-party operator, we believe that this strategy will provide greater control of cashflow, increased revenue, and larger potential for shorter payback periods as compared to returns on royalty assets and working interest assets. We expect that this shift in our business model will allow us to capture more of the upside from the use of our specialized software system. As of February 28, 2025 we estimate that our direct drilling operations will require approximately $450.3 million in additional capital throughout the rest of 2025 in order to achieve our intended business plan. We expect that these capital needs will be met in the near to medium term by capital contributions to PhoenixOp by us, which we expect to fund from time to time in varying amounts through a combination of cash from operations and the proceeds from loans and offerings of debt securities. As of February 28, 2025, we had contributed approximately $188.3 million in cash and $43.6 million in lease assets to PhoenixOp. As of February 28, 2025, we had $217.6 million available for us to borrow under that certain Loan Agreement, dated as

of September 14, 2023, by and among the Company and PhoenixOp, as borrowers, and Adamantium Capital LLC, a Delaware limited liability company and a direct, wholly owned subsidiary of the Company (“Adamantium”), as lender (as amended and supplemented from time to time, the “Adamantium Loan Agreement”) (assuming Adamantium is able to issue the corresponding amount of Adamantium Securities) (as defined below). We also continue to issue August 2023 506(c) Bonds (as defined below) and have $98.5 million of additional headroom until we reach the announced target offering amount of $750.0 million. In the near term, we intend to raise the target offering amount of the August 2023 506(c) Bonds to $1,500.0 million. Our funding of additional amounts to PhoenixOp will not be subject to specific milestones or triggering events, but instead will be guided by our business judgment in order to execute on our intended business plan. We intend to make such capital contributions to PhoenixOp until such time as PhoenixOp procures its own financing, if any, or has sufficient cash from operations to operate without supplemental financing from us. PhoenixOp is currently a borrower under certain of our loan agreements, including that certain Amended and Restated Senior Secured Credit Agreement, dated as of August 12, 2024, by and among the Company, PhoenixOp, as borrower, each of the lenders from time to time party thereto, and Fortress Credit Corp., a Delaware corporation (“Fortress”), as administrative agent for the lenders (as the same may be amended or supplemented from time to time, the “Fortress Credit Agreement”), and the Adamantium Loan Agreement, and could borrow amounts under such agreements directly. There is currently no committed amount of additional financing under the Fortress Credit Agreement. Although we have issued over $189 million of Adamantium Securities to date, there can be no assurance that we will be successful in issuing additional Adamantium Securities and utilizing then-available commitments under the Adamantium Loan Agreement.

Leases are contributed to PhoenixOp at a value equal to our cost of acquisition of the contributed asset, and we anticipate contributing additional oil and gas properties to PhoenixOp in the future. Leases are generally contributed in order for PhoenixOp to operate extraction activities on such assets with the requisite title and permissions. We expect to only contribute oil and gas properties to PhoenixOp that are located in an area where we own or lease enough continuous productive acreage to support meaningful mineral extraction activities. Whether and when we have properties we decide to contribute to PhoenixOp will depend on, among other things, our ability to acquire properties from multiple owners, the amount and quality of mineral reserves discovered on such properties, the presence of or proximity to third-party operators with existing extraction activities, and the suitability of the area’s topography for drilling and operating producing wells.

Royalty and Working Interest Acquisitions

For our royalty and working interest acquisitions, we have developed a process for the identification, acquisition, and monetization of assets. Below is a general illustration of our process:

Our specialized software provides market intelligence to identify and rank potential assets and support our acquisition strategy and functions.

• We make contact with the owner of the asset and begin the conversation on how we can increase the value of the property for the owner. We provide the potential seller with a packet detailing our business, industry data, property valuation, and an all-cash offer based on the valuation. Our sales team engages the potential seller to discuss the terms of the sale and the value of the property.

• We handle the closing of the property, and the property is migrated to our portfolio.

• We utilize our land rights to extract natural resources from the property through third-party operators or determine to proceed with our own direct drilling operations.

• We collect a portion of the revenue generated from the natural resources extracted and sold by a third-party operator. Our share of the revenue depends on the type of asset, either mineral rights or non-operated working interests, and the underlying contract with the third-party operator.

• We continue to operate the property to extract the minerals through third-party operators or PhoenixOp until we decide to sell the property rights.

Separate from the ordinary royalty income assets, we maintain a structural discipline to participate in non-operated working interests, in part for their tax benefits. Due to favorable U.S. Internal Revenue Service treatment, marrying this asset class to our pure royalty income creates an augmented “write off” strategy whereby the balanced portfolio effectively creates little to no annual taxable income. Functionally, the transactions we enter into are similar to traditional real estate transactions with respect to the mechanics. A seller agrees to sell to us, a purchase and sale agreement is executed, earnest money is conveyed, and manual diligence and title review is conducted as an audit function prior to closing. Upon closing, the funds are conveyed to the seller and the title is recorded by us in the applicable jurisdiction. Assets can produce for upwards of 20 years; however, there is a considerable regression/depletion curve over the life of the asset. As such, we tend to focus on wells that have recently begun producing or are likely to have new production in the near term. We focus on a closed-loop process from discovery to acquisition to long-term balance sheet ownership. We believe the recurring nature of these cash flows will allow for considerable scale without material increases in fixed overhead.

Our Specialized Software System

Our software system is designed to be scalable and process inputs from a variety of internal and external sources, supports our ability to identify, analyze, underwrite, and formally transact in the purchasing of oil and gas assets. Our software system operates across three key facets of our business:

Asset Discovery – The data-driven system has customized inputs that are selected by management to pull in and incorporate data sets from multiple third-party sources through custom application interfaces that automatically retrieve updated information on a regular basis. For example, the system retrieves detailed land and title data and well-level data, including operator, production metrics, well status, dates of activities, well-specific activities, and historical reporting. The software system compiles these inputs and creates dashboards that can be accessed by management to analyze and review granular data on an asset-by-asset level. These dashboards present certain key information, including, among others, the geography of the asset, the estimated probability of future oil wells, the estimated predictability of the timing and value of cashflows, and local and national oil prices. We believe this process provides us with key market intelligence and insights, tailored to prioritize asset traits curated and targeted by management, to identify and rank potential assets. We believe this provides us with a competitive advantage because we are able to identify potentially valuable assets, based on our own hierarchy and prioritization of asset traits and data inputs, that may otherwise be overlooked by other industry participants.

Asset Grading and Estimates – The outputs from the asset discovery process are then run through a discounted cash flow model, using management inputs for discount rate and the price of oil to generate asset value and pricing estimates. The software system grades these assets based on management’s desired target criteria for high probability of high near-term cash flow, and generates a summary version of assets to prospect for acquisition for our sales team. The system also generates an acquisition price for each asset, which informs the sales team as to the maximum price that we may be willing to offer in any prospective transaction. This process is used to further characterize high-priority targets for sales and acquisition efforts.

Asset Acquisition – Based on management input, the software system then routes the pricing and asset information from the asset grading and estimates process through an automated document generator to create customized, asset-specific document packages for utilization and distribution by our sales team. The workflow for these document packages is then processed and monitored using our internally developed software, which distributes the documents to our operations team for the preparation of an offering and sale package, which is then delivered to the prospective seller. Using relationship management features within our internally developed software, the sales team is able to record notes and each opportunity can be tracked from its original data upload through the lifecycle of the sales process.

While the data inputs utilized by our software system are largely based on public information, considerable customization and coding has been undertaken to generate a system that we can successfully leverage in our business. This software was designed and built by us to address our specific needs, and we are not aware of a similar competitive product. We rely on trade secret laws to protect our software system and do not own any registered copyright, patent, or other intellectual property rights regarding our software. However, we believe the investment of significant monetary and intellectual resources have created a system that would be difficult to replicate. We currently have no intention of licensing or selling our software.

Our Oil and Natural Gas Properties

Productive Wells

Productive wells consist of producing wells, wells capable of production, and exploratory, development, or extension wells that are not dry wells. As of December 31, 2024, we owned mineral, royalty, and working interests in 7,036 productive wells, the majority of which are oil wells that produce natural gas and natural gas liquids (“NGL”).

As of December 31, 2024, we had 105 wells that fall under our “wells in progress” (“WIP”) category and we had 35.1 net WIP. We define a WIP as a development well in a stage preliminary to production. We utilize both proprietary and public systems to identify WIPs based on four distinct criteria: (1) a well that is not actively being drilled but is in the process of being developed; (2) a well currently being drilled and awaiting completion; (3) a drilled well in the completion process; and (4) a drilled well that has been completed but is not yet producing. This term serves as a guide in our acquisition strategy, enabling us to pinpoint lower-risk investment opportunities for our stakeholders.

Drilling Results

In the year ended December 31, 2024, the E&P operators of our properties, including PhoenixOp, drilled 463 gross and 43.2 net productive development wells on the acreage underlying our mineral and royalty interests. This compares to 1,965 and 971 gross productive development wells and 19.2 and 8.7 net productive development wells drilled by E&P operators on the acreage underlying our mineral and royalty interests in the years ended December 31, 2023 and 2022, respectively.

Included in our total drilled wells figures, as of December 31, 2024, PhoenixOp had drilled a total of 42 gross and 38.6 net productive development wells, all of which were drilled in the Williston Basin in North Dakota and Montana. PhoenixOp has also drilled a total of six gross and six net saltwater disposal wells, and had 39 gross and 30.1 net development wells in progress as of December 31, 2024.

As a holder of mineral and royalty interests, we generally are not provided information as to whether any wells drilled on the properties underlying our acreage are classified as exploratory. We are not aware of any dry holes drilled on the acreage underlying our mineral and royalty interests during the relevant periods.

Wells

As of December 31, 2024, we had 7,037 total gross wells and 77.9 total net wells. The following table sets forth information about the productive wells in which we have a mineral or royalty interest as of December 31, 2024:

	Well Count
	Oil				Gas
Basin or Producing Region	Gross		Net		Gross		Net
Bakken/Williston Basin		3,857		56.4		3		0.0
DJ Basin/Rockies/Niobrara		1,160		15.6		12		0.0
Permian Basin		682		1.3		3		0.0
Other		700		2.0		620		2.5
Total		6,399		75.3		638		2.6

Acreage of Mineral and Royalty Interests

The following tables set forth information relating to the acreage underlying our mineral and working interests as of December 31, 2024:

Acreage of Mineral Interest

	Net Royalty Acres
Basin	Developed Acreage		Undeveloped Acreage		Total Acreage
Bakken/Williston Basin		16,187		64,402		80,589
DJ Basin/Rockies/Niobrara/PRB		4,855		9,549		14,404
Permian Basin		657		356		1,013
Other		470		434,644		435,115
Total Net Royalty Acres		22,170		508,950		531,120

	Gross Royalty Acres
Basin	Developed Acreage		Undeveloped Acreage		Total Acreage
Bakken/Williston Basin		497,152		785,084		1,282,236
DJ Basin/Rockies/Niobrara/PRB		83,031		244,236		327,267
Permian Basin		94,083		24,603		118,685
Other		17,579		2,216,297		2,233,876
Total Gross Royalty Acres		691,844		3,270,220		3,962,065

Acreage of Working Interest

	Net Mineral Acres
Basin	Developed Acreage		Undeveloped Acreage		Total Acreage
Bakken/Williston Basin		25,047		159,402		184,449
DJ Basin/Rockies/Niobrara/PRB		1,630		31,873		33,503
Permian Basin		28		36		64
Other		349		258,109		258,458
Total Net Mineral Acres		27,054		449,419		476,473

	Gross Mineral Acres
Basin	Developed Acreage		Undeveloped Acreage		Total Acreage
Bakken/Williston Basin		246,979		633,661		880,640
DJ Basin/Rockies/Niobrara/PRB		43,179		183,381		226,560
Permian Basin		7,680		1,280		8,960
Other		15,872		1,309,568		1,325,440
Total Gross Mineral Acres		313,710		2,127,890		2,441,600

Beginning with the period ended December 31, 2023 and for all subsequent periods, each land holding in which we have a net royalty interest is reviewed and associated with a specific drilling spacing unit. This allows for the estimation of gross royalty acres to be as accurate as possible. For the period ended December 31, 2022 and for all prior periods, the drilling spacing unit was estimated based on average development within a basin and applied to each land holding in which we had a net royalty interest.

Acreage Expirations

As of December 31, 2024, we have 4,179 working interest acres expiring in the next three years with an additional 44,731 acres and 34 acres expiring in the following two years, respectively. The remaining 62 working interest acres expire in years 2029 and beyond.

Evaluation and Review of Estimated Proved and Probable Reserves

Set forth below are certain definitions commonly used in the oil and natural gas industry and useful in understanding our reserves and related disclosures.

“Bbl” refers to one stock tank barrel of 42 U.S. gallons liquid volume, used in this Annual Report in reference to crude oil or other liquid hydrocarbons.

“Boe” means barrel of oil equivalent.

“Btu” refers to British thermal unit, which is the heat required to raise the temperature of one pound of liquid water by one degree Fahrenheit.

“Mcf” means one thousand cubic feet.

“MMBtu” refers to one million Btus.

We use the term “probable reserves” herein to refer to those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. The probable reserves disclosed herein have been quantified using deterministic methods and, when combined with proved reserves, have at least a 50% probability that actual quantities recovered will equal or exceed the proved plus probable reserves estimates in accordance with Rule 4-10(a)(18) of Regulation S-X. The probable reserves are adjacent to quantifiable proved reserves but where data control is present but is less certain. Our probable reserves are assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Our probable reserves are also assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. The proved plus probable estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects. Where direct observation has defined a highest known oil (“HKO”) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

We use the term “proved reserves” herein to refer to quantities of oil and gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data, and reliable technology established a lower contact with reasonable certainty. Where direct observation from well penetrations has defined an HKO elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data, and reliable technology establish the higher contact with reasonable certainty. Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (a) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (b) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

The proved and probable reserves estimates reported herein are as of December 31, 2024, and December 31, 2023. The technical persons primarily responsible for preparing the estimates disclosed herein each have over 15 years of industry experience. Each meet or exceed 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 and are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations, as well as applying SEC and other industry reserves definitions and guidelines. Mr. Brandon Allen, who is our Chief Operating Officer and who, prior to that role, served as the President of PhoenixOp from February 2024 until December 2024 and its Vice President of Reservoir Engineering from March 2023 to February 2024, is primarily responsible for overseeing the preparation of the reserves estimation. He has approximately 19 years of oil and gas operations and reserves estimation and reporting experience. He has earned Bachelor of Science degrees in Biochemistry and Chemical Engineering from the University of Colorado, Boulder, and is an active member of the Society of Petroleum Engineers.

Proved and probable reserve estimates are based on the unweighted arithmetic average prices on the first day of each month for the 12-month period ended December 31, 2024, or December 31, 2023, as applicable. Average prices for the 12-month periods were as follows: West Texas Intermediate (“WTI”) crude oil spot price of $76.32 per Bbl as of December 31, 2024, adjusted by lease or field for quality, transportation fees, and market differentials, and a Henry Hub natural gas spot price of $2.130 per MMBtu as of December 31, 2024, adjusted by lease or field for energy content, transportation fees, and market differentials. All prices and costs associated with operating wells were held constant in accordance with SEC guidelines.

We estimate the quantity or perceived cashflow of proved and probable undeveloped reserves for financial reporting purposes in accordance with the five-year rule as set forth by the SEC. Most proved undeveloped properties are operated by our subsidiary, PhoenixOp, whereby we and PhoenixOp have the property on the most current drill schedule. Non-operated proved and probable undeveloped properties represent properties that we have high confidence will be converted to producing properties within five years based on our diligence and review of public and non-public data sources. As it relates to a majority of our mineral and non-operated interest holdings, we do not always have the ability to accurately estimate when undeveloped reserves may be extracted and instead take a conservative approach whereby we only classify such reserves as proved when such reserves are either currently producing or where we have knowledge of a close date of extraction, such as upon our receipt of a notice from the operators of such reserves providing a specific timeframe for near-term production. We classify the remaining reserves as probable reserves. For example, for probable undeveloped reserves, we have a high confidence that the properties are on a development plan and/or will be converted to producing properties within the next five years based on, among other factors, our discussions with service providers, the location of nearby drilling rigs, permits obtained by the operators that are generally valid for one to two years, and the terms of the respective leases, which typically expire within five years.

Estimates of probable reserves, and the future cash flows related to such estimates, are inherently imprecise and are more uncertain than estimates of proved reserves, and the future cash flows related to such estimates, but have not been adjusted for risk due to that uncertainty. Because of such uncertainty, estimates of probable reserves, and the future cash flows related to such estimates, may not be comparable to estimates of proved reserves, and the future cash flows related to such estimates, and should not be summed arithmetically with estimates of proved reserves, and the future cash flows related to such estimates. When producing an estimate of the amount of natural gas and oil that is recoverable from a particular reservoir, an estimated quantity of probable reserves is an estimate of those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Estimates of probable reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes, and other factors. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

The reserves information in this disclosure represents only estimates. Reserve evaluation is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. In addition, results of drilling, testing, and production subsequent to the date of an estimate may lead to revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. Except to the extent we acquire additional properties containing proved reserves or conduct successful exploration and development activities or both, our proved reserves will decline as reserves are produced.

In addition, we anticipate that the preparation of our proved and probable reserve estimates is completed in accordance with internal control procedures, including the following:

• review and verification of historical production data, which data is based on actual production as reported by the operators of our properties;

• preparation of reserves estimates by Mr. Brandon Allen or under his direct supervision;

• review by Mr. Brandon Allen and Mr. Curtis Allen, our Chief Financial Officer, of all of our reported proved and probable reserves at the close of the calendar year, including the review of all significant reserve changes and all new proved and probable undeveloped reserves additions;

• verification of property ownership by our land department; and

• no employee’s compensation being tied to the amount of reserves booked.

Oil, Natural Gas, and NGL Reserves

The following table presents our estimated proved and probable oil, natural gas, and NGL reserves as of each of the dates indicated:

	As of December 31,
	2024(1)(2)			2023(2)(3)
Estimated proved developed reserves
Oil (Bbl)		18,624,758			7,124,194
Natural gas (Mcf)		20,819,874			12,250,285
Natural gas liquids (Bbl)		2,848,355			1,514,761
Total (Boe)(6:1)(4)		24,943,093			10,680,669
PV-10(5)	$	644,098		$	289,809
Estimated proved undeveloped reserves
Oil (Bbl)		31,197,795			24,925,841
Natural gas (Mcf)		17,491,089			19,565,808
Natural gas liquids (Bbl)		4,753,257			6,648,747
Total (Boe)(6:1)(4)		38,866,233			34,835,556
PV-10(5)	$	424,595		$	257,472
Estimated proved reserves
Oil (Bbl)		49,822,554			32,050,035
Natural gas (Mcf)		38,310,963			31,816,093
Natural gas liquids (Bbl)		7,601,611			8,163,508
Total (Boe)(6:1) (4)		63,809,326			45,516,225
Percent proved developed		39	%		23	%
PV-10(5)	$	1,068,692		$	547,281
Estimated probable undeveloped reserves
Oil (Bbl)		107,769,309			74,877,268
Natural gas (Mcf)		134,083,603			88,184,111
Natural gas liquids (Bbl)		—			—
Total (Boe)(6:1) (4)		130,116,577			89,574,620

(1) Estimates of reserves of oil and natural gas as of December 31, 2024 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month of the last 12 months ended December 31, 2024, in accordance with SEC guidelines applicable to reserve estimates as of the end of such period. The unweighted arithmetic average first day of the month prices were $76.32 per Bbl for oil and $2.130 per MMBtu for natural gas at December 31, 2024. Estimates of reserves of NGL as of December 31, 2024 were calculated using the average of realized wellhead prices of such reserves. The average NGL price realized at December 31, 2024 was $25.22 per Bbl. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, production costs, and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

(2) In early 2023, PhoenixOp was established with the intention that certain leaseholds held by us would be developed by PhoenixOp. PhoenixOp executed a contract for a drilling rig with Patterson-UTI Drilling Company on June 20, 2023. This allowed for previously unbooked reserves as of December 31, 2022 to be estimated and booked as of December 31, 2023 as proved undeveloped in accordance with SEC guidelines for reserves categorization and estimation and in adherence to the five-year rule as set forth in Rule 4-10(a)(31) of Regulation S-X.

(3) Estimates of reserves of oil and natural gas as of December 31, 2023 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month of the last 12 months ended December 31, 2023, in accordance with SEC guidelines applicable to reserve estimates as of the end of such period. The unweighted arithmetic average first day of the month prices were $78.21 per Bbl for oil and $2.637 per MMBtu for natural gas at December 31, 2023. Estimates of reserves of NGL as of December 31, 2023 were calculated using the average of realized wellhead prices of such reserves. The average NGL price realized at December 31, 2023 was $19.21 per Bbl. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, production costs, and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

(4) Estimated proved reserves are presented on an oil-equivalent basis using a conversion of six Mcf per barrel of “oil equivalent.” This conversion is based on energy equivalence and not price or value equivalence. If a price equivalent conversion based on the 12-month average prices for the period ended December 31, 2024 was used, the conversion factor would be approximately 35.8 Mcf per Bbl of oil.

(5) We calculate PV-10 as the discounted future net cash flows attributable to our proved oil and natural gas reserves before income taxes, discounted at 10% annually. PV-10 differs from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure, because it is calculated on a pre-tax basis. We use PV-10 when assessing the potential return on investment related to our oil and natural gas properties. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future income taxes, and is useful for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize PV-10 as a basis for comparison of the relative size and value of our reserves to other companies without regard to the specific tax characteristics of such entities.

Because the Company is a limited liability company and has currently elected to be treated as a partnership for income tax purposes, the pro rata share of taxable income or loss is included in the individual income tax returns of members based on their percentage of ownership. Consequently, no provision for income taxes is made in our standardized measure of discounted future net cash flows, and so currently our PV-10 is identical to the standardized measure of discounted future net cash flows. Notwithstanding the foregoing, we believe that the presentation of PV-10 is useful to investors because it is a commonly utilized measure in our industry for assessing the value of reserves.

PV-10 is not a substitute for the standardized measure of discounted future net cash flows. Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of our oil and natural gas reserves.

The following table includes a reconciliation of PV-10 to the standardized measure of discounted future net cash flows, the most directly comparable financial measure calculated and presented in accordance with GAAP, for the periods presented:

	For the Years Ended December 31,
	2024		2023
	(in thousands)
Estimated proved developed reserves:
Standardized measure of discounted future net cash flows	$	644,098	$	289,809
Discounted future income taxes		—		—
PV-10	$	644,098	$	289,809
Estimated proved undeveloped reserves:
Standardized measure of discounted future net cash flows	$	424,595	$	257,472
Discounted future income taxes		—		—
PV-10	$	424,595	$	257,472
Estimated total proved reserves:
Standardized measure of discounted future net cash flows	$	1,068,692	$	547,281
Discounted future income taxes		—		—
PV-10	$	1,068,692	$	547,281

At December 31, 2024, total estimated proved reserves were approximately 63,809,326 Boe, a 18,293,101 Boe net increase from the previous year end’s estimate of 45,516,225 Boe. Proved developed reserves of 24,943,092 Boe increased approximately 14,262,423 Boe from December 31, 2023 as a result of proved developed reserves acquisitions of 1,047,809 Boe, extensions of 3,268,997 Boe, and total positive revisions of previous estimates of 14,759,886 Boe, offset by divestitures of 71,887 Boe and production from proved developed reserves of 4,742,381 Boe. The total positive revisions of previous estimates comprised: (i) positive price revisions of 1,263 Boe; (ii) positive transfer of 14,871,911 Boe from proved undeveloped to proved developed reserves; (iii) negative well performance revisions of (481,161) Boe; (iv) positive revisions of 715,795 Boe due to interest changes; and (v) negative revisions of (347,922) Boe due to changes in lifting cost. Proved undeveloped reserves of 38,866,233 Boe increased approximately 4,030,677 Boe from December 31, 2023 as a result of proved undeveloped reserves extensions of 21,207,289 and total negative revisions of previous estimates of 17,176,612 Boe. The total negative revisions of previous estimates comprised: (i) positive price revisions of 48,935 Boe; (ii) negative transfer of (14,871,911) Boe

from proved undeveloped to proved developed reserves; and (iii) negative well performance revisions of (2,353,636) Boe due to asset development reconfiguration and type curve adjustments. During the year ended December 31, 2024, approximately $450.0 million in capital expenditures went toward the acquisition and development of proved developed reserves, which includes drilling, completion, and other facility costs associated with acquiring and developing wells. All proved undeveloped reserves disclosed as of December 31, 2024 are scheduled to be converted to proved developed status within five years of initial disclosure.

At December 31, 2023, total estimated proved reserves were approximately 45,516,225 Boe, a 40,553,802 Boe net increase from the previous year end’s estimate of 4,962,424 Boe. Proved developed reserves of 10,680,669 Boe increased approximately 5,718,245 Boe from December 31, 2022 as a result of proved developed reserves acquisitions of 1,426,545 Boe, extensions of 5,682,894 Boe, and total positive revisions of previous estimates of 616,010 Boe, offset by production from proved reserves of 2,007,205 Boe. The total positive revisions of previous estimates comprised: (i) negative price revisions of (13,622) Boe; (ii) transfer of (89,378) Boe from proved developed to proved undeveloped due to previous misclassifications of reserve; (iii) positive well performance revisions of 515,938 Boe; and (iv) positive revisions of 203,072 Boe due to changes in lifting cost. Proved undeveloped reserves of 34,835,556 Boe increased approximately 34,835,556 Boe from December 31, 2022 as a result of revisions due to previous misclassification of 89,378 Boe of reserves as proved developed reserves and due to the addition of 34,746,179 Boe of operated proved undeveloped reserves stemming from the signing of a drilling rig contract in June 2023. During the year ended December 31, 2023, approximately $171.2 million in capital expenditures went toward the acquisition and development of proved developed reserves, which includes drilling, completion, and other facility costs associated with acquiring and developing wells. At December 31, 2022, there were no proved undeveloped reserves and therefore all capital expenditures for the year ended December 31, 2023 were related to the development of non-proved reserves or the acquisition of proved developed reserves.

Delivery Commitments

As of February 28, 2025, PhoenixOp is subject to arrangements pursuant to which it has committed to provide a total of 6.57 million barrels of crude oil, with the highest yearly minimum of 2,372,500 barrels of crude oil, from January 1, 2024 to December 31, 2030. PhoenixOp will be subject to a shortfall fee for failure to meet this commitment. As a part of these arrangements, PhoenixOp has dedicated to the counterparties certain rights to all oil extracted from our wells in certain properties in Dunn County, Williams County, and Divide County, North Dakota. PhoenixOp has assessed the productivity potential of its leasehold in the area, as well as the feasibility of executing an operational plan to extract oil on its leasehold within the commitment period and dedication area, and deemed it to be reasonable to enter into such an agreement.

Oil and Natural Gas Production Prices and Production Costs

Select Production and Operating Statistics

The following table presents information regarding our production of oil, natural gas, and NGL and certain price and cost information for each of the periods indicated:

	For the Years Ended December 31,
	2024			2023			2022
Production Data:
Bakken
Oil (Bbl)		3,022,810			943,930			360,604
Natural gas (Mcf)		1,301,782			1,123,859			522,523
Natural gas liquids (Bbl)		270,219			88,762			—
Total (Boe)(6:1)(1)		3,509,992			1,220,003			447,691
Average daily production (Boe/d)(6:1)		9,590			3,342			1,227
All Properties
Oil (Bbl)		3,830,461			1,446,928			523,416
Natural gas (Mcf)		2,979,341			2,152,939			1,058,506
Natural gas liquids (Bbl)		415,363			201,454			—
Total (Boe)(6:1)(1)		4,742,381			2,007,205			699,834
Average daily production (Boe/d)(6:1)		12,993			5,499			1,917
Average Realized Prices:
Bakken
Oil (Bbl)	$	71.77		$	71.43		$	80.67
Natural gas (Mcf)	$	2.12		$	3.47		$	3.77
Natural gas liquids (Bbl)	$	23.53		$	26.70		$	—
All Properties
Oil (Bbl)	$	68.49		$	73.10		$	91.01
Natural gas (Mcf)	$	1.86		$	3.15		$	6.66
Natural gas liquids (Bbl)	$	25.22		$	27.50		$	—
Average Unit Cost per Boe (6:1):
All Properties
Operating costs, production and ad valorem taxes	$	16.11		$	16.18		$	19.89
Operating costs excluding taxes	$	10.75		$	10.86		$	12.58
Percentage of revenue		26.4	%		16.7	%		21.9	%

(1) “Btu-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel of “oil equivalent,” which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas.

Depletion of Oil and Natural Gas Properties

We account for our oil and gas properties under the successful efforts method of accounting. Under this method, the costs of development wells are capitalized to proved properties whether those wells are successful or unsuccessful. Capitalized drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities, are depleted using the units-of-production method based on estimated proved developed reserves. Proved leasehold costs are also depleted; however, the units-of-production method is based on estimated total proved reserves. The computation of depletion expense takes into consideration restoration, dismantlement, and abandonment costs, as well as the anticipated proceeds from salvaging equipment.

Depletion expense was $86.0 million, $34.2 million, and $12.1 million for the years ended December 31, 2024, 2023, and 2022, respectively. On a per unit basis, depletion expense was $18.13 per Boe, $17.06 per Boe, and $17.34 per Boe for the years ended December 31, 2024, 2023, and 2022, respectively. The decrease in our depletion rate for the year ended December 31, 2023 compared to 2022 was primarily due to increased proved reserves relative to the change in aggregated proved leasehold and development costs associated with those proved reserves, whereas the increase in our depletion rate for the year ended December 31, 2024 compared to 2023 was primarily due to the incurrence of significant capital expenditures related to developing operated wells under our operating entity, PhoenixOp. The depletion rate for the development capital is depleted at a higher rate as compared to leasehold due to the use of proved developed reserves versus total proved reserves under the successful efforts accounting method. We expect depletion to continue to increase in subsequent periods as our gross production of oil, gas, and other products increase.

Our E&P Operators

Our management team strives to acquire mineral and royalty interests in properties with top-tier third-party E&P operators. We seek third-party E&P operators that are well-capitalized, have a strong operational track record, and we believe will continue to produce through the application of the latest drilling and completion techniques across our mineral and royalty interests. Over 100 third-party E&P operators are currently producing oil and gas at our assets. As of December 31, 2024, our top ten third-party E&P operators operate on 7.1% of our NRAs.

Industry Operating Environment

The oil and natural gas industry is a global market impacted by many factors, such as government regulations, particularly in the areas of taxation, energy, climate change, and the environment, political and social developments in the Middle East and Russia, demand in Asian and European markets, and the extent to which members of the Organization of the Petroleum Exporting Countries (“OPEC”) and other oil exporting nations manage oil supply through export quotas. Natural gas prices are generally determined by North American supply and demand and are also affected by imports and exports of liquefied natural gas. Weather also has a significant impact on demand for natural gas because it is a primary heating source.

Oil and natural gas prices have been, and we expect may continue to be, volatile. Lower oil and gas prices not only decrease our revenues, but an extended decline in oil or gas prices may affect planned capital expenditures and the oil and natural gas reserves that our assets can economically produce. Among other things, drilling operations and related activities can be significantly impacted by the accuracy of the estimation of reserves and the effect on those reserves of fluctuating market prices. If commodity prices decline, the cost of developing, completing, and operating a well may not decline in proportion to the prices that are received for the production, resulting in higher operating and capital costs as a percentage of revenues. While lower commodity prices may reduce the future net cash flow from operations of the assets in which we invest, we expect to have sufficient liquidity to continue participation in development of our oil and gas properties.

Competition

The oil and gas industry is intensely competitive, and we compete with other oil and natural gas exploration and production companies, some of which have substantially greater resources than we have and may be able to pay more for exploratory prospects and productive oil and natural gas properties, and competition for our target asset classes is subject to increase in the future. Our larger or more integrated competitors may be better able to absorb the burden of existing, as well as any changes to, federal, state, and local laws and regulations than we can, which would adversely affect our competitive position. Our ability to acquire additional assets in the future is dependent on the success of our software platform, our ability and resources to evaluate and select suitable properties, and our ability to consummate transactions in this highly competitive environment.

Marketing and Customers

The market for oil and natural gas that will be produced from our assets depends on many factors, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of pipelines and other transportation and storage facilities, demand for oil and natural gas, the marketing of competitive fuels, and the effects of state and federal regulation. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial, and individual consumers.

Our oil and natural gas production is expected to be sold under short-term contracts and priced based on first of the month index prices or on daily spot market prices. We rely on our third-party operating and service partners to market and sell our production. Our operating partners include a variety of exploration and production companies, from large, publicly traded companies to small, privately owned companies. Our service partners include a variety of oil and natural gas gathering, transportation, processing, and marketing companies. We do not believe the loss of any single operator or service partner would have a material adverse effect on our company as a whole.

Seasonality

Winter weather events and conditions, such as ice storms, freezing conditions, droughts, floods, tornados, breeding and nesting seasons, and lease stipulations can limit or temporarily halt our and our operating partners’ drilling and producing activities and other oil and natural gas operations. These constraints and the resulting shortages or high costs could delay or temporarily halt our and our operating partners’ operations and materially increase our operating and capital costs. Such seasonal anomalies can also pose challenges for meeting well drilling objectives and may increase competition for equipment, supplies, and personnel during the spring and summer months, which could lead to shortages and increase costs or delay or temporarily halt our and our operating partners’ operations.

Title to Properties

Prior to completing an acquisition of mineral and royalty interests, we perform due diligence title reviews on a majority of tracts to be acquired. Our title review is meant to confirm the quantum of mineral and royalty interest owned by a prospective seller, the property’s lease status and royalty amount, and encumbrances or other related burdens. Said title review consists of a patent to present title search on the prospective tract and a “grantor/grantee” search of the prospective seller in county records, in addition to a lien/judgment search related to the seller’s ownership.

In addition to our initial title work and due diligence title review, E&P operators will conduct a thorough title examination prior to leasing and/or drilling a well and paying out the royalty owner. Should an E&P operator’s title work uncover any further title defects, either we or the E&P operator will perform curative work with respect to such defects. An E&P operator generally will not pay out royalty payments on the property until any material title defects on such property have been cured.

We believe that the title to our assets is satisfactory in all material respects. Although title to these properties is, in some cases, subject to encumbrances, such as customary interests generally retained in connection with the acquisition of crude oil and gas interests, non-participating royalty interests, and other burdens, easements, restrictions, or minor encumbrances customary in the crude oil and natural gas industry, we believe that none of these encumbrances will materially detract from the value of these properties or from our interest in these properties.

Governmental Regulation and Environmental Matters

Our operations are subject to various rules, regulations, and limitations impacting the oil and natural gas exploration and production industry as a whole, including those associated with E&P operators and other owners of working interests in crude oil and natural gas properties. The legislation and regulation affecting the crude oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the crude oil and natural gas industry increases the cost of doing business.

Environmental Matters

Crude oil and natural gas exploration, development, and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have the potential to impact production on the properties in which we own mineral interests, which could materially adversely affect our business and prospects. Numerous federal, state, and local governmental agencies, such as the United States Environmental Protection Agency (the “EPA”), issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil, and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities, and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive, and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing earthen pits, result in the suspension or revocation of necessary permits, licenses, and authorizations, require that additional pollution controls be installed, and impose substantial liabilities for pollution resulting from operations. The strict, joint, and several liability nature of such laws and regulations could impose liability upon the E&P operators of our properties, including PhoenixOp, regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons, or other waste products into the environment. In the opinion of our management, we are in substantial compliance with current applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements. However, changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal, or cleanup requirements could materially adversely affect our business and prospects.

Non-Hazardous and Hazardous Waste

The Federal Resource Conservation and Recovery Act (the “RCRA”) and comparable state statutes and regulations promulgated thereunder affect crude oil and natural gas exploration, development, and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of the RCRA, sometimes in conjunction with their own, more stringent requirements. Administrative, civil, and criminal penalties can be imposed for failure to comply with waste handling requirements. Although most wastes associated with the exploration, development, and production of

crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, these wastes typically constitute nonhazardous solid wastes that are subject to less stringent requirements. From time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for nonhazardous wastes, including crude oil and natural gas wastes. Moreover, it is possible that some wastes generated in connection with E&P of oil and gas that are currently classified as nonhazardous may, in the future, be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly management and disposal requirements. Any changes in the laws and regulations could have a material adverse effect on the E&P operators of our properties’ capital expenditures and operating expenses, including those of PhoenixOp, which in turn could affect production from the acreage underlying our mineral and royalty interests and adversely affect our business and prospects.

Remediation

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and analogous state laws generally impose strict, joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject to strict, joint, and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources, and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In addition, the risk of accidental spills or releases could expose the operators of the acreage underlying our mineral interests to significant liabilities that could have a material adverse effect on the operators’ businesses, financial condition, and results of operations. Liability for any contamination under these laws could require the operators of the acreage underlying our mineral interests to make significant expenditures to investigate and remediate such contamination or attain and maintain compliance with such laws and may otherwise have a material adverse effect on their results of operations, competitive position, or financial condition.

Water Discharges

The Clean Water Act (“CWA”), Safe Drinking Water Act (“SDWA”), the Oil Pollution Act of 1990 (the “OPA”), and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other crude oil and natural gas wastes, into regulated waters. The definition of regulated waters has been the subject of significant controversy in recent years, with different definitions proposed under the Obama and Trump Administrations. Both of these definitions have been subject to litigation. In January 2023, the EPA and the U.S. Army Corps of Engineers (the “Corps”) released a final revised definition of “waters of the United States” founded upon a pre-2015 definition and included updates to incorporate existing Supreme Court decisions and regulatory guidance. However, the January 2023 rule was challenged and is currently enjoined in 27 states. In May 2023, the U.S. Supreme Court released its opinion in Sackett v. EPA, which involved issues relating to the legal tests used to determine whether wetlands qualify as waters of the United States. The Sackett decision invalidated certain parts of the January 2023 rule and significantly narrowed its scope, resulting in a revised rule being issued in September 2023. However, due to the injunction of the January 2023 rule, the implementation of the September 2023 rule currently varies by state. In March 2025, the EPA announced that it will work with the Corps to deliver on President Trump’s promise to review and revise the definition of “waters of the United States,” guided by the Sackett decision. To the extent the implementation of the final rule, results of the litigation, or any further action expands the scope of jurisdiction, it may impose greater compliance costs or operational requirements on our operators, including PhoenixOp. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. In addition, spill prevention, control, and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak. The EPA has also adopted regulations requiring certain crude oil and natural gas E&P facilities to obtain individual permits or coverage under general permits for stormwater discharges, and in June 2016, the EPA finalized effluent limitation guidelines for the discharge of wastewater from hydraulic fracturing.

The OPA is the primary federal law for crude oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into regulated waters, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of crude oil into surface waters.

Noncompliance with the CWA, the SDWA, or the OPA may result in substantial administrative, civil, and criminal penalties, as well as injunctive obligations for the E&P operators of the acreage underlying our mineral interests, including PhoenixOp.

Air Emissions

The Clean Air Act (“CAA”) and comparable state laws and regulations regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, in June 2016, the EPA established criteria for aggregating multiple small surface sites into a single source for air quality permitting purposes, which could cause small facilities, on an aggregate basis, to be deemed a major source subject to more stringent air permitting processes and requirements. These laws and regulations may increase the costs of compliance for crude oil and natural gas producers and impact production of the acreage underlying our mineral and royalty interests. In addition, federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with air permits or other requirements of the federal CAA and associated state laws and regulations. Moreover, obtaining or renewing permits has the potential to delay the development of crude oil and natural gas projects.

Climate Change

Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional, and state levels of government to monitor and limit emissions of carbon dioxide, methane, and other GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, Greenhouse Gas (“GHG”) reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources.

In the United States, besides the Inflation Reduction Act (the “IRA”) 2022, no comprehensive climate change legislation has been implemented at the federal level. Although former President Biden’s administration highlighted addressing climate change as a priority and issued several executive orders to that effect, President Trump’s administration has taken a different stance, has revoked many of President Biden’s executive orders, and imposed a regulatory freeze. Additionally, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and, together with the U.S. Department of Transportation, implements GHG emissions limits on vehicles manufactured for operation in the United States. The regulation of methane from oil and gas facilities has been subject to uncertainty in recent years. However, in response to former President Biden’s executive order calling on the EPA to revisit federal regulations regarding methane, the EPA finalized more stringent methane rules for new, modified, and reconstructed facilities, known as OOOOb, as well as standards for existing sources, known as OOOOc, in December 2023. Under those rules, states would have two years to prepare and submit their plans to impose methane emissions controls on existing sources. On November 12, 2024, the EPA finalized the methane emissions charge rule, implementing the IRA 2022. The Trump Administration may challenge, repeal, or revise the EPA rule. Additionally, the U.S. Congress may take action to repeal or revise the IRA 2022, including with respect to the methane charge rule, which timing or outcome similarly cannot be predicted. The final methane charge rule is currently being challenged by 23 U.S. states and a coalition of industry groups in the U.S. Circuit Court of Appeals for the D.C. Circuit.

As of March 2025, President Trump has not rolled back any methane regulations, but the future of such regulations and any enforcement of those regulations at the federal level is murky, given the Trump Administration’s skeptical approach to climate change-related regulations. The presumptive standards established under the final rule are generally the same for both new and existing sources and include enhanced leak detection survey requirements using optical gas imaging and other advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions, reduction of emissions by 95% through capture and control systems, zero-emission requirements for certain devices, and the establishment of a “super emitter” response program that would allow third parties to make reports to the EPA of large methane emissions events, triggering certain investigation and repair requirements. It is likely, however, that the final rule and its requirements will be subject to legal challenges if ever implemented. Moreover, compliance with these rules may affect the amount oil and gas companies owe under the IRA 2022, which amended the CAA to impose a first-time fee on the emission of methane from sources required to report their GHG emissions to the EPA. The methane emissions fee applies to excess methane emissions from certain facilities and starts at $900 per metric ton of leaked methane in 2024 and increases to $1,200 in 2025 and $1,500 in 2026 and thereafter. Compliance with the EPA’s new final rules would exempt an otherwise covered facility from the requirement to pay the methane fee. Failure to comply with the requirements of the EPA’s new rules and the methane fee could adversely affect the costs of compliance and operations and result in the imposition of substantial fines and penalties, as well as costly injunctive relief.

Separately, various states and groups of states have adopted or are considering adopting legislation, regulation, or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. For example, New Mexico has adopted regulations to restrict the venting or flaring of methane from both upstream and midstream operations. At the international level, the Paris Agreement requires member states to submit non-binding, individually determined reduction goals known as Nationally Determined Contributions every five years after 2020. Although former President Biden recommitted the United States to the Paris Agreement during his presidency and, in April 2021, announced a goal of reducing the United States’ emissions by 50 to 52% below 2005 levels by 2030, President Trump has signed an executive order directing the United States’ withdrawal from the Paris Agreement. The Trump Administration’s stance makes it unclear whether the Global Methane Pledge announced by the United States and the European Union at the 26th Conference of the Parties to the United Nations Framework Convention on Climate Change in Glasgow in November 2021—an initiative committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including “all feasible reductions” in the energy sector—will move forward. In December 2023, the United Arab Emirates hosted the 28th Conference of the Parties, where parties signed onto an agreement to transition “away from fossil fuels in energy systems in a just, orderly, and equitable manner” and increase renewable energy capacity so as to achieve net zero by 2050, although no timeline for doing so was set. In November 2024, Azerbaijan hosted the 29th Conference of the Parties, which concluded with an agreement calling on developed countries to deliver at least $300 billion per year to developing countries by 2035 to drastically reduce greenhouse gas emissions and protect lives and livelihoods from the impacts of climate change. The full impact of these various orders, pledges, agreements, and actions cannot be predicted at this time.

Whereas on January 27, 2021, former President Biden’s administration called for restrictions on leasing on federal land, and issued an executive order that called for substantial action on climate change, including, among other things, the increased use of zero-emission vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risks across government agencies and economic sectors, the new Trump administration has revoked many such related rules and executive orders focusing on greenhouse emissions and fossil fuel energy regulations. For example, on January 21, 2025, the Trump Administration lifted the former administration’s pause on liquefied natural gas exports. However, we cannot predict whether and to what extent the Trump Administration will continue to act favorably to the energy sector.

Litigation risks are also increasing as a number of entities have sought to bring suit against various oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to climate change or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts.

Historically, there have also been increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into non-fossil fuel related sectors. Institutional lenders who provide financing to fossil fuel energy companies have also become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. There is also a risk that financial institutions will be required to adopt policies that reduce the funding provided to the fossil fuel sector. For example, in October 2023, the Federal Reserve, Office of the Comptroller of the Currency, and the Federal Deposit Insurance Corp. released a finalized set of principles guiding financial institutions with $100 billion or more in assets on the management of physical and transition risks associated with climate change. The limitation of investments in and financing for fossil fuel energy companies could result in the restriction, delay, or cancellation of drilling programs or development or production activities. Additionally, on March 6, 2024, the SEC adopted rules to enhance and standardize climate-related disclosures by public companies and in public offerings. However, on April 4, 2024, the SEC voluntarily stayed the implementation of these rules pending completion of judicial review of consolidated challenges to the rules by the U.S. Court of Appeals for the Eighth Circuit and is expected to withdraw these rules in the near future. Although the application and viability of the proposed rules are not yet known, any adoption of such rules either by the Trump Administration or a future administration may result in additional costs to comply with any such disclosure requirements, alongside increased costs of and restrictions on access to capital.

The adoption and implementation of new or more stringent international, federal, or state legislation, regulations, or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for oil and natural gas, which could reduce the profitability of our interests. Additionally, political, litigation, and financial risks may result in our oil and natural gas operators restricting or canceling production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing their ability to continue to operate in an economical manner, which also could reduce the profitability of our interests. One or more of these developments could have a material adverse effect on our business, financial condition, and results of operation.

Climate change may also result in various physical risks, such as the increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patterns, that could adversely impact our operations, as well as those of our operators, including PhoenixOp, and their supply chains. Such physical risks may result in damage to operators’ facilities or otherwise adversely impact their operations, such as if they become subject to water-use curtailments in response to drought, or demand for their products, such as to the extent warmer winters reduce the demand for energy for heating purposes. Extreme weather conditions can interfere with production and increase costs, and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our business.

Regulation of Hydraulic Fracturing

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing operations have historically been overseen by state regulators as part of their crude oil and natural gas regulatory programs. However, several agencies have asserted regulatory authority over certain aspects of the process. For example, in August 2012, the EPA finalized regulations under the federal CAA that established new air emission controls for crude oil and natural gas production and natural gas processing operations. Federal regulation of methane emissions from the oil and gas sector has been subject to substantial controversy in recent years.

In addition, governments have studied the environmental aspects of hydraulic fracturing practices. These studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. For example, in December 2016, the EPA issued its final report on a study it had conducted over several years regarding the effects of hydraulic fracturing on drinking water sources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water under certain limited circumstances.

Several states where we operate, including North Dakota, Montana, Utah, Texas, Colorado, and Wyoming, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, the Texas Rail Road Commission (“RRC”) has previously issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down, and cementing wells. Local governments may also seek to adopt ordinances within their jurisdictions regulating the time, place, and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular.

In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general or hydraulic fracturing in particular. For example, in November 2020, the Colorado Oil and Gas Conservation Committee (the “COGCC”), as part of Senate Bill 181’s mandate for the COGCC to prioritize public health and environmental concerns in its decisions, adopted revisions to several regulations to increase protections for public health, safety, welfare, wildlife, and environmental resources. Most significantly, these revisions establish more stringent setbacks (2,000 feet instead of the prior 500-foot) on new oil and gas development and eliminate routine flaring and venting of natural gas at new or existing wells across the state, each subject to only limited exceptions. Some local communities have adopted, or are considering adopting, further restrictions for oil and gas activities, such as requiring greater setbacks. The Colorado Department of Public Health and the Environment also finalized rules related to the control of emissions from certain pre-production activities; namely, curbing methane emissions by setting limits of per 1,000 barrels of oil equivalent produced, more frequent inspections, and limits on emissions during maintenance. These and other developments related to the implementation of Senate Bill 181 could adversely impact our revenues and future production from our properties.

State and federal regulatory agencies recently have focused on a possible connection between hydraulic fracturing-related activities, particularly the disposal of produced water in underground injection wells, and the increased occurrence of seismic activity. When caused by human activity, such events are called “induced seismicity.” In some instances, operators of injection wells in the vicinity of seismic events have been ordered to reduce injection volumes or suspend operations. Some state regulatory agencies, including those in Colorado and Texas, have modified their regulations to account for induced seismicity. For example, in October 2014, the Texas RRC published a new rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections, and structure maps relating to the disposal area in question. The Texas RRC has used this authority to deny permits for waste disposal wells. In some instances, regulators may also order that disposal wells be shut in. In late 2021, the Texas RRC issued a notice to operators of disposal wells in the Midland area to reduce saltwater disposal well actions and provide certain data to the Texas RRC. In December 2021, the Texas RRC suspended all disposal well permits to inject oil and gas waste within the boundaries of the Gardendale Seismic Response Area. Relatedly, in March 2022, the Texas RRC began implementation of its Northern Culberson-Reeves Seismic Response Area Plan to

address injection-induced seismicity with the goal to eliminate 3.5 magnitude or greater earthquakes no later than December 31, 2023. From November 8 through December 17, 2023, the TexNet Seismic Monitoring Program reported seven earthquakes with magnitudes greater than 3.5 and, in April 2024, a 4.4 magnitude earthquake was recorded in the Stanton Seismic Response Area, an area where the Texas RRC is also monitoring seismic activity linked to disposal of saltwater. In January 2024, the RRC banned saltwater disposal injection in the Northern Culberson-Reeves Seismic Area, which applied to 23 disposal wells in the area. As a result of these developments, our operators may be required to curtail operations or adjust development plans, which may adversely impact our business. In May 2024, the EPA announced it would review the Texas RRC’s oversight of disposal wells used for injecting oil drilling wastewater and carbon dioxide into the ground.

The United States Geological Survey has identified six states with the most significant hazards from induced seismicity, including Texas and Colorado. In addition, a number of lawsuits have been filed alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells and hydraulic fracturing. Such regulations and restrictions could cause delays and impose additional costs and restrictions on the E&P operators of our properties, including PhoenixOp, and on their waste disposal activities.

If new laws or regulations that significantly restrict hydraulic fracturing and related activities are adopted, such laws could make it more difficult or costly to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting, and recordkeeping obligations, plugging and abandonment requirements, and to attendant permitting delays and potential increases in costs. Such legislative changes could cause E&P operators to incur substantial compliance costs, and compliance or the consequences of any failure to comply by E&P operators could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

Endangered Species Act

The Endangered Species Act (the “ESA”) restricts activities that may affect endangered and threatened species or their habitats. The designation of previously unidentified endangered or threatened species could cause E&P operators to incur additional costs or become subject to operating delays, restrictions, or bans in the affected areas. As part of a stipulated settlement agreement in a case challenging its failure to timely make a 12-month finding on a petition to list the dunes sagebrush lizard, whose habitat includes parts of the Permian Basin, the United States Fish and Wildlife Service (the “FWS”). In June 2024, the FWS issued a final rule listing the dunes sagebrush lizard as endangered under the ESA. Additionally, in June 2021, the FWS proposed to list two distinct population sections of the Lesser Prairie Chicken, including one in portions of the Permian Basin, under the ESA. In November 2022, following an extensive review, the FWS listed the northern distinct population segment of the Lesser Prairie Chicken, encompassing southeastern Colorado, southcentral to western Kansas, western Oklahoma, and the northeast Texas Panhandle, as threatened, and the southern district population segment, covering eastern New Mexico and the southwest Texas Panhandle, as endangered. The FWS listing decisions for both the lesser prairie chicken and the dunes sagebrush lizard are subject to ongoing litigation in the U.S. District Court for the Western District of Texas. To the extent species are listed under the ESA or similar state laws, or previously unprotected species are designated as threatened or endangered in areas where our properties are located, operations on those properties could incur increased costs arising from species protection measures and face delays or limitations with respect to production activities thereon.

Employee Health and Safety

Operations on our properties are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (the “OSHA”) and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require that information be maintained concerning hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities, and citizens.

Other Regulation of the Crude Oil and Natural Gas Industry

The crude oil and natural gas industry is extensively regulated by numerous federal, state, and local authorities. Legislation affecting the crude oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the crude oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the crude oil and natural gas industry increases the cost of doing business, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities, and locations of production.

The availability, terms and conditions, and cost of transportation significantly affect sales of crude oil and natural gas. The interstate transportation of crude oil and natural gas and the sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions, and rates for interstate transportation, storage, and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms for access to crude oil and natural gas pipeline transportation. FERC’s regulations for interstate crude oil and natural gas transmission in some circumstances may also affect the intrastate transportation of crude oil and natural gas.

We cannot predict whether new legislation to regulate crude oil and natural gas might be proposed, what proposals, if any, might actually be enacted by the U.S. Congress or various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of crude oil, condensate, and NGL are not currently regulated and are made at market prices.

Drilling and Production

The operations of the E&P operators of our properties, including PhoenixOp, are subject to various types of regulation at the federal, state, and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds, and reports concerning operations. The states and some counties and municipalities in which we operate also regulate one or more of the following:

• the location of wells;

• the method of drilling and casing wells;

• the timing of construction or drilling activities, including seasonal wildlife closures;

• the rates of production or “allowables”;

• the surface use and restoration of properties upon which wells are drilled;

• the plugging and abandoning of wells; and

• notice to, and consultation with, surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of crude oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from crude oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of crude oil and natural gas that the E&P operators of our properties can produce from our wells or limit the number of wells or the locations at which E&P operators can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of crude oil, natural gas, and NGL within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of crude oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells, or limit the number of locations E&P operators can drill.

Federal, state, and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines, and site restoration in areas where the E&P operators of our properties operate. The Corps and many other state and local authorities also have regulations for plugging and abandonment, decommissioning, and site restoration. Although the Corps does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

Natural Gas Sales and Transportation

FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (the “NGA”) and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted that have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales.”

Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which the E&P operators of our properties may use interstate natural gas pipeline capacity, as well as the revenues such E&P operators receive for release of natural gas pipeline capacity. Interstate pipeline companies are required to provide non-discriminatory transportation services to producers, marketers, and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open-access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines.

Gathering services, which occur upstream of jurisdictional transmission services, are regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC under the NGA. FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which may increase the E&P operators’ costs of transporting gas to point-of-sale locations. This may, in turn, affect the costs of marketing natural gas that the E&P operators of our properties produce.

Historically, the natural gas industry was more heavily regulated; therefore, we cannot guarantee that the regulatory approach currently pursued by FERC and the U.S. Congress will continue indefinitely into the future, nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

Crude Oil Sales and Transportation

Crude oil sales are affected by the availability, terms, and cost of transportation. The transportation of crude oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate crude oil pipeline transportation rates under the Interstate Commerce Act, and intrastate crude oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate crude oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate crude oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of crude oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.

Further, interstate and intrastate common carrier crude oil pipelines must provide service on a non-discriminatory basis. Under this open-access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When crude oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to crude oil pipeline transportation services by E&P operators of our properties will not materially differ from our competitors’ access to crude oil pipeline transportation services.

Certain State Regulations and Developments

North Dakota

On July 6, 2020, the U.S. District Court for the District of Columbia ordered vacatur of the Dakota Access Pipeline’s (“DAPL”) easement from the Corps and further ordered the shutdown of the pipeline by August 5, 2020 while the Corps completes a full environmental impact statement for the project. On January 26, 2021, the Court of Appeals for the District of Columbia affirmed the vacatur of the easement, but declined to require the pipeline to shut down while an Environmental Impact Statement is prepared. On May 21, 2021, the District Court denied the Plaintiff’s request for an injunction and, on June 22, 2021, terminated the consolidated lawsuits and dismissed all remaining outstanding counts without prejudice. Following the denial of a rehearing en banc by the Court of Appeals for the District of Columbia, on September 20, 2021, Dakota Access filed a petition with the U.S. Supreme Court to hear the case. Oppositions were filed by the Solicitor General and Plaintiffs and Dakota Access filed its reply, although in February 2022, the U.S. Supreme Court denied certiorari, declining to hear the appeal. The pipeline continues to operate pending completion of the Environmental Impact Statement, which the Corps released in September 2023. The Draft Environmental Impact Statement was subject to public comment until December 2023, and the final Environmental Impact Statement is expected to be released in 2025. Additional lawsuits challenging the legality of the DAPL have been filed by various stakeholders. We cannot determine when or how these or future lawsuits will be resolved or the impact they may have on the DAPL. If future legal challenges to DAPL are successful, we may be adversely affected by increased transportation costs, well shut ins, and future productive, negatively impacting our revenue costs.

Montana

In April 2020, a Montana federal judge vacated the Corps’ Nationwide Permit (“NWP”) 12 and enjoined the Corps from authorizing any dredge or fill activities under NWP 12 until the agency completed formal consultation with the FWS under the ESA regarding NWP 12 generally. The court later revised its order to vacate NWP 12 only as it relates to the construction of new oil and natural gas pipelines, and that order went on appeal in the Ninth Circuit Court of Appeals. The United States Supreme Court narrowed the applicability of the order to the Keystone XL pipeline pending the outcome of the Ninth Circuit’s decision, and in May 2021, the Biden Administration argued that the suit was moot given the discontinuation of the Keystone XL pipeline. In March 2022, the Corps announced its formal review of NWP 12. The Corps’ review of NWP 12 may adversely affect our business, preventing the advancement of our oil and gas infrastructure projects due to public interest review and studies of the impacts of our projects on the climate. There have been no recent updates of the Corps’ review.

In December 2024, the Montana Supreme Court affirmed a lower court decision in Held v. State of Montana, holding that the right to a clean and healthful environment under the Montana Constitution includes a stable climate system, and that the law at question banning state agencies from weighing the impact of climate change and GHG emissions in environmental reviews was unconstutional under state law. The policy impacts of the ruling remain unclear; however, it may lead to adverse changes in the permitting process for oil and gas development in Montana, and may lead to further lawsuits, which may negatively impacting our operations in the state.

Utah

In recent years, Utah has experienced persistent and severe drought conditions. Various local governments in Utah have implemented water restrictions. Water management and our access to water, in each case at a reasonable cost, in a timely manner and in compliance with applicable laws, regulations and permits, is an essential component of our operations due to water’s significance in shale oil and natural gas development. As such, any limitations or restrictions on wastewater disposal or water availability could have an adverse impact on our operations. Our third party E&P operators may use water supplied from various local and regional sources to support operations like steam injection in certain fields. While our third party E&P operators’ production to date has not been materially impacted by restrictions on wastewater disposals or access to third-party water sources, we cannot guarantee that there may not be restrictions in the future.

Texas

Texas regulates the drilling for, and the production, gathering, and sale of, crude oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on the market value of crude oil production and a 7.5% severance tax on the market value of natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells, and the prevention of waste of crude oil and natural gas resources.

States may regulate rates of production and may establish maximum daily production allowables from crude oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. Should direct economic regulation or regulation of wellhead prices by the states increase, this could limit the amount of crude oil and natural gas that may be produced from wells on our properties and the number of wells or locations the E&P operators of our properties can drill.

The petroleum industry is also subject to compliance with various other federal, state, and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not currently believe that compliance with these laws will have a material adverse effect on our business.

Colorado

A number of municipalities in other states, including Colorado and Texas, have enacted bans on hydraulic fracturing. In Colorado, the Colorado Supreme Court has ruled the municipal bans were preempted by state law. However, in April 2019, the Colorado legislature subsequently enacted “SB 181” that gave significant local control over oil and gas well head operations. Municipalities in Colorado have enacted local rules restricting oil and gas operations based on SB 181; nevertheless, in November 2020, a Colorado district court upheld the prior Colorado Supreme Court ruling in finding that a hydraulic fracking ban in the City of Longmont was preempted by state law. Additionally, in May 2024, the Colorado legislature enacted a bill that mandates a 50% reduction in nitrogen oxide emissions from upstream oil and gas operations by 2030, relative to 2017 levels. Oil and gas operators are

required to obtain and maintain a license to conduct operations, in addition to necessary permits. The Colorado Energy and Carbon Management Commission (the “ECMC”) will enforce these requirements. The bill authorizes the ECMC to adopt rules requiring enhanced systems and practices to minimize emissions of ozone precursors at new oil and gas locations, particularly in areas designated as ozone nonattainment zones. The bill increases civil penalties for violations. It also allows for more stringent enforcement actions, including license suspension or revocation for severe violations. The bill also expands efforts to plug, reclaim, and remediate orphaned and marginal wells, with a focus on those at high risk of becoming orphaned, to mitigate environmental and public health risks. During the same legislative session, Colorado enacted a bill that imposes a “Production Fee for Clean Transit” and a “Production Fee for Wildlife and Land Remediation” on oil and gas produced in the state. Oil and gas producers are required to register and file returns detailing their production volumes and corresponding fees. Failure to comply with these requirements can result in penalties. In October 2024, the ECMC introduced rules to scrutinize the cumulative impacts of GHG emissions and set emissions intensity targets for operators. Local communities are considering additional restrictions, such as greater setbacks. The Colorado Department of Public Health and the Environment also set rules to curb methane emissions from pre-production activities. We cannot predict whether other similar legislation in other states will ever be enacted and if so, what the provisions of such legislation would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal or state level, it could lead to delays, increased operating costs and process prohibitions that would materially adversely affect our operating partners and our revenue and results of operations.

Wyoming

On May 7, 2024, the Wyoming Department of Environmental Quality (“DEQ”) – Air Quality Division issued an emergency rule in response to EPA new air regulation 40 CFR Part 60 subpart OOOOb – “Standards of Performance for Crude Oil and Natural Gas Facilities for Which Construction, Modification, or Reconstruction Commenced After December 6, 2022” (the “Methane Rule”). The Methane Rule establishes emission standards and compliance schedules for the control of GHGs. Subpart OOOOb requirements became federally effective on May 7, 2024, and as a result, oil and gas operators across the nation, including in Wyoming, must implement them. To assist Wyoming’s regulated community with implementing EPA’s new requirements, DEQ issued an Oil and Gas Emergency Rulemaking. Given EPA’s shortened timeframes and deadlines, the division initiated the emergency rulemaking process before initiating the regular rulemaking process. The regular rulemaking process will provide the public and stakeholders the opportunity to comment and participate in the rulemaking process.

Human Capital Resources

As of December 31, 2024, we had 135 total employees, all of whom were full-time employees and all of whom were located in the United States. From time to time, we utilize the services of independent contractors to perform various field and other services. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. In general, we believe that employee relations are satisfactory.

We are focused on attracting, engaging, developing, retaining, and rewarding top talent. We strive to enhance the economic and social well-being of our employees and the communities in which we operate. We are committed to providing a welcoming, inclusive environment for our workforce, with training and career development opportunities to enable employees to thrive and achieve their career goals. The health, safety, and well-being of our employees is of the utmost importance.

As part of our efforts to hire and retain highly qualified employees, we have structured compensation and benefits programs that, we believe, are extremely competitive and reward outstanding performance. In addition to the incentive programs in place for our named executive officers, which are described in detail under “Compensation of Managers and Executive Officers—Details of Our Compensation Program,” we have structured an incentive bonus program for non-officer employees that is dependent on an employee’s individual performance and our performance as a company. We also provide a robust suite of benefits to our employees covering all aspects of life, including 401(k) contributions, medical-insurance options, and programs to encourage and support the employees’ development.

Our Offices

Our principal executive office is located in Irvine, California, and we have additional offices located in Denver, Colorado, Dallas, Texas, Fort Lauderdale, Florida, and Casper, Wyoming. We currently lease this office space and believe that the condition and size of our offices are adequate for our current needs, and that additional or alternative space will be available on commercially reasonable terms for future use and expansion.

Legal Proceedings

On June 15, 2022, we filed a civil lawsuit against William Francis and Incline Energy Partners, L.P. (“Incline Energy”) in the 116th District Court of Dallas County, Texas, asserting claims of (i) defamation, (ii) business disparagement, (iii) tortious interference with contract, (iv) tortious interference with prospective contract/relations, (v) unfair competition, and (vi) civil conspiracy, and seeking damages of $50 million. Francis and Incline Energy moved to dismiss all claims under the Texas Citizen Participation Act. On October 9, 2022, the District Court dismissed the tortious interference with contract claim, and the defamation and business disparagement claims to the extent they were based on a specific document. Francis and Incline Energy appealed the portions of the Court’s decision that denied their motion to dismiss. On August 30, 2023, the Court of Appeals for the Fifth District of Texas reversed the District Court’s decision in part, dismissing all claims other than defamation per se. On December 28, 2023, we filed a petition for review by the Texas Supreme Court. On June 21, 2024, the Supreme Court of Texas denied the petition for review. On remand, the trial court dismissed our remaining claims with prejudice. We are evaluating an appeal of this ruling.

On October 20, 2023, we filed a civil lawsuit against Incline Energy in the United States District Court for the District of North Dakota, asserting (i) tortious interference with contract, (ii) tortious interference with business expectancy, (iii) unfair competition, and (iv) unjust enrichment, and seeking damages in excess of $10 million. On November 28, 2023, Incline Energy filed a motion to dismiss these claims. We opposed Incline Energy’s motion. The court has permitted additional filings, including a motion for leave to amend the complaint that would add antitrust claims against Incline Energy. The court has not yet ruled on the parties’ pleading-stage motions.

From time to time, we may be involved in various legal proceedings, lawsuits, regulatory investigations, and other claims in the ordinary course of business. In particular, due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment-related disputes. Such matters are subject to many uncertainties, and outcomes are not predictable with certainty. In the opinion of our management, none of the other pending litigation matters, disputes, or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows, or results of operations.

Company Information

We are a wholly owned subsidiary of Phoenix Equity Holdings, LLC, a Delaware limited liability company (“Phoenix Equity”). Phoenix Equity is our sole member and, as such, directs our business and operations, including appointment and compensation of our officers. Lion of Judah Capital, LLC, a Delaware limited liability company (“LJC”), controls Phoenix Equity and, therefore, indirectly has control over our management.

The Company’s principal executive offices are located at 18575 Jamboree Road, Suite 830, Irvine, CA 92612, and its telephone number is (303) 376-9778. For more information about the Company, please visit its website at https://www.phoenixenergy.com. The information on, or otherwise accessible through, our website does not constitute a part of this Annual Report.

General Offering Information

We filed an offering statement on Form 1-A (the “Offering Statement”) with the SEC on November 19, 2021, as amended by Form 1-A/A amendments, filed on December 8, 2021 and December 20, 2021 respectively, which offering statement was qualified by the SEC on December 23, 2021. We filed our most recent post-qualification amendment to the Offering Statement on March 18, 2024, which was qualified by the SEC on March 29, 2024. Pursuant to the Offering Statement, as amended, we offered up to a maximum of $75,000,000 in the aggregate of the Company’s 9.0% unsecured bonds (the “Reg A Bonds”) in any 12-month period. The purchase price per Reg A Bond was $1,000, with a minimum purchase amount of $1,000. The offering pursuant to the Offering Statement terminated on December 23, 2024. In total, we have issued $129.8 million of Reg A Bonds in the offering. As of December 31, 2024, we had $104.9 million aggregate principal amount of the Reg A Bonds outstanding, with maturities ranging from January 10, 2025 to August 10, 2027.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

You should read the following management’s discussion and analysis of financial condition and results of operations in conjunction with our consolidated financial statements, and the related notes thereto included elsewhere in this Annual Report. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs, and expected performance. These forward-looking statements are dependent upon events, risks, and uncertainties that may be outside of our control. Our actual results could differ materially from those disclosed in these forward-looking statements. Factors that could cause or contribute to such differences include those described in “Statements Regarding Forward-Looking Information and Figures” above and “Risk Factor,” and “Cautionary Statement Regarding Forward-Looking Statement,” included in the Offering Circular. Our historical results are not necessarily indicative of the results that may be expected for any period in the future.

Overview

We operate in the oil and gas industry and execute on a three-pronged strategy involving (i) direct drilling operation, of operated working interests (ii) the acquisition of royalty assets, and (iii) the acquisition of non-operated working interest assets. Our direct drilling operations are currently primarily focused on development efforts in the Williston Basin in North Dakota and Montana and the Powder River and Denver Julesburg Basins in Wyoming. Our royalty and working interest acquisitions center around a variety of assets, including mineral interests, leasehold interests, overriding royalty interests, and perpetual royalty interests. These efforts have historically targeted assets in the Williston, Permian, Powder River, Uintah, and DJ Basins. We are agnostic as to geography and prioritize operational and asset potential when executing on our strategy.

We began operations in 2019 with the development of our specialized software system, which we have designed and improved over time to support our ability to identify, analyze, underwrite, transact, and manage our oil and gas assets. In 2019, we acquired our first mineral interest asset and began to generate revenue. In 2020, we expanded our operations and team to include specialists across a variety of key focus areas. From 2020 to 2024, we experienced significant growth in operations. For example, in 2020, the E&P operators of our properties operated 725 gross and 2.8 net productive development wells on the acreage underlying our mineral and royalty interests, and the total acreage underlying our gross and net royalty interests was 177,824 and 1,506, respectively. In the four years since then, the E&P operators of our properties have operated an additional 6,312 gross and 75.1 net productive development wells on the acreage underlying our mineral and royalty interests, of which approximately 463 gross and 43.2 net productive developments wells were drilled in 2024 alone. As of December 31, 2024, we had 3,962,065 and 531,120 acres underlying our gross and net royalty interests, respectively, as compared to 177,824 and 1,506 acres underlying our gross and net royalty interests, respectively, at December 31, 2020. Furthermore, our total production for the year ended December 31, 2020 was under 0.2 million Boe as compared to over 4.7 million Boe for the year ended December 31, 2024. In the same period, our number of employees grew from 21 at December 31, 2020 to 135 at December 31, 2024. Additionally, we commenced direct drilling operations and spudded our first wells in the third quarter of 2023 and drilled a total of 42 gross and 38.6 net productive development wells in 2024. We expect these direct drilling operations to be a core component of our business strategy going forward.

Since our initial mineral interest asset acquisition in 2019, we have leveraged our specialized software system and experienced management team to identify asset opportunities that fit our desired criteria and potential for returns. While we evaluate and acquire a wide variety of assets, we have historically prioritized assets with potential for high monthly recurring cashflows and primarily target assets that have a potential payback within the short to medium term and long-term cashflows.

Since 2019, we have completed 3,074 mineral, royalty, and leasehold interest acquisitions from landowners and other mineral interest owners, representing approximately 531,120 NRAs of royalty assets and 476,473 of NMAs of leasehold assets as of December 31, 2024. Over that same period, in addition to completing numerous small transactions, we completed more than 56 transactions larger than 1,000 NMAs that account for approximately 72% of our NMAs. We have acquired mineral, royalty, and leasehold interests from individuals, families, trusts, partnerships, small minerals aggregators, minerals brokers, large private minerals companies, private oil and gas E&P companies, and public minerals companies. We also actively manage our portfolio of assets and, as of December 31, 2024, have sold 3,152 NMAs since 2019.

Following the acquisition of an asset, we typically share in the proceeds of the natural resources extracted and sold by a third-party E&P operator. For certain assets, we operate our own direct drilling operations through PhoenixOp.

For the years ended December 31, 2022, 2023, and 2024, we had revenue of $54.6 million, $118.1 million, and $281.2 million, respectively, net income (loss) of $5.7 million, $(16.2) million, and $(24.8) million, respectively, and EBITDA of $29.7 million, $65.9 million, and $150.7 million, respectively. As of December 31, 2022, 2023, and 2024 we had total assets of $157.0 million, $493.2 million, and $1,029.1 million, respectively, total liabilities of $148.3 million, $498.0 million, and $1,063.1 million, respectively (inclusive of total indebtedness of $117.4 million, $447.9 million, and $987.9 million, respectively), and retained earning (accumulated deficit) of $6.5 million, $(9.7) million, and $(34.5) million, respectively. In 2023 and 2024, we incurred a significant amount of debt in order to accelerate the growth of our business by acquiring additional assets and establishing our direct drilling operations. As a result, our cash flows from operations alone would not have been sufficient to service required cash interest and

principal payment obligations under our then-existing debt in 2023 and 2024. Although we expect our cash flows from operations to be sufficient to service such obligations going forward, there can be no assurance as to the sufficiency of our cash flows for that purpose, and we may require additional liquidity to service our debt. As a result, we may use the proceeds of additional debt to make interest and principal payments on our existing debt.

Our Segments

We operate under three segments: mineral and non-operating; operating; and securities. Our mineral and non-operating segment comprises our operations for the acquisition of mineral interests and non-operated working interests in oil and gas properties, through which we share in the proceeds of the natural resources extracted and sold by the operator. Our operating segment comprises our operations related to our drilling, extraction, and production activities, which today are conducted through PhoenixOp. Our securities segment comprises our operations related to our capital raising activities associated with our debt securities offerings. Our management evaluates our performance and allocates resources based in part on segment operating profit, which is calculated as total segment revenue less operating expenses attributable to the segment, which includes allocated corporate costs.

Sources of Our Revenue

Our revenues have historically primarily constituted mineral and royalty payments received from our E&P operators based on the sale of crude oil, natural gas, and NGL production from our interests. In 2024, we commenced sales of crude oil, natural gas, and NGL and began generating product sales in our operating segment through our wholly owned subsidiary, PhoenixOp, which was formed for the purposes of drilling, extracting, and operating producing wells. Product sales accounted for over 45% of our total revenues for the year ended December 31, 2024, and we expect to derive a greater portion of our total revenues from product sales of crude oil, natural gas, and NGL to PhoenixOp’s customers in the future. Our revenues may vary significantly from period to period because of changes in commodity prices, production mix, and volumes of production sold by our E&P operators, including PhoenixOp. We also derive revenues from performing saltwater disposal services on wells operated by PhoenixOp, as well as redemption fees charged to investors, generally in connection with the early redemption of their investments. Other revenue in the securities segment is derived almost exclusively from intersegment interest expense to the mineral and non-operating segment and the operating segment, and is eliminated in consolidation.

Principal Components of Our Cost Structure

As a mineral, royalty, and non-operated working interest owner, we may incur lease operating expenses and our proportionate share of production, severance, and ad valorem taxes. In those circumstances, revenues are recognized net of production taxes and post-production expenses. Through PhoenixOp’s operations, we also incur certain production costs, including gathering, processing, and transportation costs, which are presented as a component of cost of sales on our consolidated statements of operations. Shared corporate costs that are overhead in nature and not directly associated with any one of our segments, including certain general and administrative expenses, executive or shared-function payroll costs, and certain limited marketing activities, are allocated to our segments based on usage and headcount, as appropriate. Cost of sales and depreciation, depletion, and amortization are not applicable to the securities segment.

Cost of Sales

Lease Operating Expenses

We incur lease operating expenses through: (i) our ownership of non-operated working interests, paying our pro rata share of cost of labor, equipment, maintenance, saltwater disposal, workover activity, and other miscellaneous costs; and (ii) PhoenixOp, where such costs are directly incurred through our own drilling and extraction activities. We generally expect that these expenses will increase as our number of mineral interest and non-operated working interests in oil and gas properties increase, and as our operating activities on wells operated by PhoenixOp continue to increase.

Production and Ad Valorem Taxes

Production taxes are paid at fixed rates on produced crude oil, natural gas, and NGL based on a percentage of revenues from our volume of products sold, established by federal, state, or local taxing authorities. Where we utilize third-party operators, the E&P companies that operate on our interests withhold and pay our pro rata share of production taxes on our behalf. We directly pay ad valorem taxes in the counties where our properties are located. Ad valorem taxes are generally based on the appraised value of our crude oil, natural gas, and NGL properties. We generally expect that these expenses will increase as our number of mineral interest and non-operated working interests in oil and gas properties increase, as we commence oil and gas operating activities on operated properties, and as production from such properties increases.

Production Costs

Production costs include gathering, processing, and transportation costs that we incur to gather and transport our oil and gas production to a point of sale. We generally expect that these costs will increase as our activities in our operating segment increase and as our oil and gas operating activities result in increased production volumes. For example, our production costs increased throughout 2024 as our oil and gas operating activities came online and PhoenixOp operated production from our first operated properties.

Depreciation, Depletion, and Amortization

Depreciation, depletion, and amortization is the systematic expensing of the capitalized costs incurred to acquire, explore, and develop crude oil, natural gas, and NGL. We follow the successful efforts method of accounting, pursuant to which we capitalize the costs of our proved crude oil, natural gas, and NGL mineral interest properties, which are then depleted on a unit-of-production basis based on proved crude oil, natural gas, and NGL reserve quantities. Our estimates of crude oil, natural gas, and NGL reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data, as well as the projection of future rates of production. Any significant variance in these assumptions could materially affect the estimated quantity of the reserves, which could affect the rate of depletion related to our crude oil, natural gas, and NGL properties. Depreciation, depletion, and amortization also includes the expensing of office leasehold costs and equipment. We expect depletion to continue to increase in subsequent periods as our gross production of oil, gas, and other products increases.

Selling, General, and Administrative Expense

Selling, general, and administrative expenses consist of costs incurred related to overhead, office expenses, and fees for professional services such as audit, tax, legal, and other consulting services. We have publicly filed a Registration Statement on Form S-1 with respect to an offering of up to $750.0 million aggregate principal amount of unsecured debt securities (the “Registered Offering”). In connection with the Registered Offering, we expect to incur additional costs related to being a public company. See “—Factors Affecting the Comparability of Our Financial Condition and Results of Operations.”

General and administrative expenses are allocated directly to a segment when there is a clear cost-benefit relationship between the expense and the segment that received the benefit. All other costs are aggregated within pools and allocated to each segment using a level-of-effort formula. We expect general and administrative expense to continue to increase period over period as we continue to grow and capitalize on opportunities within each segment; however, we do expect the percentage of growth to begin to decline as our business matures.

Payroll and Payroll-Related Expense

Payroll and payroll-related expenses consist of personnel costs for executive and employee compensation and related benefits. Payroll and payroll-related expenses are allocated directly to the segment associated with a respective employee, with the exception of corporate personnel, whose costs are allocated to the segments based on a reasonable level-of-effort formula. We expect payroll expenses to continue to increase period over period as we continue to grow; however, we do expect the percentage of growth to begin to decline as our business matures.

Advertising and Marketing Expense

We incur advertising and marketing costs primarily in our securities segment. Advertising and marketing costs include third-party services related to public relations, market research, and the development of strategic initiatives, brand messaging, and communication materials that are produced for our investors to generate greater awareness and promote investor engagement. We expect advertising and marketing costs to vary from period to period as we undertake targeted campaigns or initiatives. Advertising and marketing costs are expensed as incurred.

Interest Expense

We have financed a significant portion of our working capital requirements and acquisitions with borrowings under credit facilities and the issuance of debt securities. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to the lenders under credit facilities and holders of our debt securities and amortization of debt discount and debt issuance costs in interest expense in our consolidated statements of operations. Interest expense is primarily incurred within the securities segment and allocated to the mineral and non-operating segment and the operating segment based on the carrying value of the oil and gas properties owned by the respective segment at the balance sheet date. Allocated intersegment interest expense is eliminated in consolidation. We expect interest expense to continue to increase period over period as we raise additional capital to meet our objectives.

How We Evaluate Our Operations

We use a variety of operational and financial measures to assess our performance. Among the measures considered by management are the following:

• volumes of oil, natural gas, and NGL produced;

• number of producing wells, spud wells, and permitted wells;

• commodity prices; and

• revenue and EBITDA.

Volumes of Oil, Natural Gas, and NGL Produced

In order to track and assess the performance of our assets, we monitor and analyze our production volumes from our mineral and royalty interests. We also regularly compare projected volumes to actual reported volumes and investigate unexpected variances.

Producing Wells, Spud Wells, and Permitted Wells

In order to track and assess the performance of our assets, we monitor the number of permitted wells, spud wells, completions, and producing wells on our mineral and royalty interests in an effort to evaluate near-term production growth.

Commodity Prices

Historically, oil, natural gas, and NGL prices have been volatile and may continue to be volatile in the future. During the past five years, the posted price for WTI has ranged from a low of negative $36.98 per barrel in April 2020 to a high of $123.64 per barrel in March 2022. The Henry Hub spot market for natural gas has ranged from a low of $1.21 per MMBtu in November 2024 to a high of $23.86 per MMBtu in February 2021. Lower prices may not only decrease our revenues, but also potentially the amount of oil, natural gas, and NGL that our operators can produce economically.

Oil. The substantial majority of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. The majority of our oil production is priced at the prevailing market price with the final realized price affected by both quality and location differentials. The chemical composition of crude oil plays an important role in its refining and subsequent sale as petroleum products. As a result, variations in chemical composition relative to the benchmark crude oil, usually WTI, will result in price adjustments, which are often referred to as quality differentials. The characteristics that most significantly affect quality differentials include the density of the oil, as characterized by its American Petroleum Institute gravity, and the presence and concentration of impurities, such as sulfur. Location differentials generally result from transportation costs based on the produced oil’s proximity to consuming and refining markets and major trading points.

Natural Gas. The U.S. New York Mercantile Exchange (“NYMEX”) price quoted at Henry Hub is a widely used benchmark for the pricing of natural gas in the United States. The actual prices realized from the sale of natural gas differ from the quoted NYMEX price as a result of quality and location differentials. Quality differentials result from the heating value of natural gas measured in Btu and the presence of impurities, such as hydrogen sulfide, carbon dioxide, and nitrogen. Natural gas containing ethane and heavier hydrocarbons has a higher Btu value and will realize a higher volumetric price than natural gas that is predominantly methane, which has a lower Btu value. Natural gas with a higher concentration of impurities will realize a lower price due to the presence of the impurities in the natural gas when sold or the cost of treating the natural gas to meet pipeline quality specifications. Natural gas, which currently has limitations on transportation in certain regions, is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end-user markets.

NGL. NGL pricing is generally tied to the price of oil, but varies based on differences in liquid components and location.

EBITDA

We calculate EBITDA by adding back to net income (loss), interest income and expense and depreciation, depletion, amortization, and accretion expense for the respective periods. EBITDA is a non-GAAP supplemental financial measure used by our management to understand and compare our operating results across accounting periods, for internal budgeting and forecasting purposes, and to evaluate financial performance and liquidity, in each case, without regard to financing methods, capital structure, or historical cost basis. EBITDA is presented as supplemental disclosure as we believe it provides useful information to investors and others in understanding and evaluating our results, prospects, and liquidity period over period, including as compared to results of other companies. EBITDA does not represent and should not be considered an alternative to, or more meaningful than, net income (loss), income from operations, cash flows from operating activities, or any other measure of financial performance presented in

accordance with GAAP as measures of financial performance. EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect net income (loss), the most directly comparable GAAP financial measure. Other companies may not publish this or similar metrics, and our computation of EBITDA may differ from computations of similarly titled measures of other companies.

Factors Affecting the Comparability of Our Financial Condition and Results of Operations

Our historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward, primarily for the following reasons:

Acquisitions

As of December 31, 2024, we had completed 3,074 acquisitions from landowners and other mineral interest owners. There is typically a lag (e.g., six to eighteen months) between when acquisitions are made and when those investments generate meaningful revenue. As a result, many of the investments we made in 2023 began generating revenue in 2024, and we anticipate the same delayed effect will occur from 2024 to 2025 and in the future as we continue to invest in new opportunities. We intend to pursue potential accretive acquisitions of additional mineral and royalty interests by capitalizing on our specialized software, as well as our management team’s expertise and relationships. We believe we will be well-positioned to acquire such assets and, should such opportunities arise, identifying and executing acquisitions will be a key part of our strategy. However, if we are unable to make acquisitions on economically acceptable terms, our future growth may be limited, and any acquisitions we make may reduce, rather than increase, our cash flows and ability to make further investments in our business and satisfy our debt obligations. Additionally, it is possible that we will effect divestitures of certain of our assets. Any such acquisitions or divestitures affect the comparability of our results of operations from period to period.

Supply, Demand, Market Risk, and Their Impact on Oil Prices

Commodity prices are the most significant factor impacting our revenues, profitability, operating cash flows, the amount of capital we invest in our business, and redemption of our debt. The oil industry is cyclical and commodity prices are highly volatile. During the period from January 1, 2021 through December 31, 2024, prices for crude oil reached a high of $123.70 per Bbl and a low of $47.47 per Bbl. Over the same time period, natural gas prices reached a high of $23.86 per MMBtu and a low of $1.21 per MMBtu. These prices experience large swings, sometimes on a day-to-day or week-to-week basis. For the year ended December 31, 2024, the average NYMEX crude oil and natural gas prices were $76.63 per Bbl and $2.19 per MMBtu, respectively, representing decreases of 1.2% and 13.5%, respectively, from the average NYMEX prices for the year ended December 31, 2023. For the year ended December 31, 2023, the average NYMEX crude oil and natural gas prices were $77.58 per Bbl and $2.53 per MMBtu, respectively, representing decreases of 18.3% and 60.7%, respectively, from the average NYMEX prices for the year ended December 31, 2022.

Crude oil prices over that time period were impacted by a variety of factors affecting current and expected supply and demand dynamics, including strong demand for crude oil, domestic supply reductions, OPEC control measures, and market disruptions resulting from the Russia-Ukraine war and sanctions on Russia. Market prices for NGL are influenced by the components extracted, including ethane, propane, and butane and natural gasoline, among others, and the respective market pricing for each component. Other factors impacting supply and demand include weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials, export capacity, and the strength of the U.S. dollar, as well as other factors, the majority of which are outside of our control.

Commodity prices experienced significant volatility in 2022 after the Russia/Ukraine conflict began and this has continued into 2025. Recent conflicts and tensions in the Middle East have added further volatility to energy prices and the outlook for that region remains extremely uncertain. Ongoing OPEC petroleum supply limitations and economic sanctions involving producer countries continue to add uncertainty to the price outlook. We expect commodity price volatility to continue given the complex global dynamics of supply and demand that exist in the market.

Reporting and Compliance Expenses

In connection with the Registered Offering, we expect to incur incremental non-recurring costs related to our transition to being a public company, including the costs of the Registered Offering and the costs associated with the initial implementation of our improved internal controls and testing. We also expect to incur additional significant and recurring expenses as a public reporting company, such as expenses associated with SEC reporting requirements, including annual and quarterly reports, Sarbanes-Oxley Act of 2002 compliance expenses, costs associated with the employment of additional personnel, increased independent auditor fees, increased legal fees, investor relations expenses, and increased director and officer insurance expenses. Certain of these general and administrative expenses are not included in our historical financial statements.

Derivatives

To reduce the impact of fluctuations in oil, NGL, and natural gas prices on our revenues, we periodically enter into commodity derivative contracts with respect to certain of our oil, NGL, and natural gas production through various transactions that limit the risks of fluctuations of future prices. We plan to continue our practice of entering into such transactions to reduce the impact of commodity price volatility on our cash flows from operations.

Impairment

We evaluate our producing properties for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. When assessing proved properties for impairment, we compare the expected undiscounted future cash flows of the proved properties to the carrying amount of the proved properties to determine recoverability. If the carrying amount of proved properties exceeds the expected undiscounted future cash flows, the carrying amount is written down to the properties’ estimated fair value, which is measured as the present value of the expected future cash flows of such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, and a risk-adjusted discount rate. The proved property impairment test is primarily impacted by future commodity prices, changes in estimated reserve quantities, estimates of future production, overall proved property balances, and depletion expense. If pricing conditions decline or are depressed, or if there is a negative impact on one or more of the other components of the calculation, we may incur proved property impairments in future periods.

Debt and Interest Expense

We have a significant amount of debt and may incur significantly more in the future to finance, among other things, acquisitions, investments in PhoenixOp, and payments on our debt. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. Increases in interest rates as a result of inflation and a potentially recessionary economic environment in the United States could have a negative effect on the demand for oil and natural gas, as well as our borrowing costs.

PhoenixOp

Our wholly owned subsidiary, PhoenixOp, was formed to manage and conduct drilling, extraction, and related oil and gas operating activities. PhoenixOp commenced the spudding of its first wells in the third quarter of 2023. The first five wells completed by PhoenixOp began production in the first quarter of 2024, and the next five wells began production in the second quarter of 2024. As of December 31, 2024, PhoenixOp placed an additional 22 wells in production, and had an additional 39 wells in various stages of development. Given its limited operations in 2023, PhoenixOp’s revenue was $1.2 million for that year. For the year ended December 31, 2024, PhoenixOp’s operations increased and its revenue was $125.6 million. As more wells continue to commence production, and more properties are contributed to PhoenixOp for potential future production, we expect to derive a greater portion of our total revenues from PhoenixOp and our operating segment. We believe these operations represent a significant source of potential revenue growth. In addition, as PhoenixOp is an E&P operator, it incurs greater operating costs related to drilling, extraction, and related oil and gas operating activities than our mineral and non-operating activities. As a result, we expect our operating costs to increase as PhoenixOp’s operations expand and become a greater portion of our overall business.

2025 Outlook

The following table presents our current estimates of certain financial and operating results for the full year of 2025. These forward-looking statements reflect our expectations as of the date of this Annual Report, and are subject to substantial uncertainty. Our results are inherently unpredictable, may fluctuate significantly, and may be materially affected by many factors, such as fluctuations in commodity prices, changes in global economic and geopolitical conditions, and changes in governmental regulations, among others. The following estimates are based on, among other things, our anticipated capital expenditures and drilling and operations programs, our ability to drill and complete wells consistent with our expectations, certain drilling, completion, and equipping cost assumptions, and certain well performance assumptions. In addition, achieving these estimates and maintaining the required drilling activity to achieve these estimates will depend on the availability of capital, the existing regulatory environment, commodity prices and differentials, rig and service availability, and actual drilling results, as well as other factors. Factors that could cause or contribute to changes of such estimates include those described in the sections entitled “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statement” in the Offering Circular and in “Statements Regarding Forward-Looking Information and Figures” presented elsewhere in this Annual Report. If any of these risks and uncertainties actually occur or the assumptions underlying our estimates are incorrect, our actual operating results, costs and activities may be materially and adversely different from our expectations or guidance. In addition, investors should recognize that the reliability of any guidance diminishes in as much as it involves estimates for figures farther in the future, and so the farther we are from the end of 2025 the more likely that our actual results will differ materially from our guidance. In light of the foregoing, investors are urged to put our guidance in context and not to place undue reliance upon it.

	Year Ending December 31, 2025
(in thousands)	Lower Range		Upper Range
Revenue(1)	$	595,000	$	625,000
Total operating expenses		442,000		430,000
Net income		10,000		35,000
Interest expense, net		143,000		160,000
Depreciation, depletion, amortization, and accretion expense		157,000		180,000
EBITDA(2)	$	310,000	$	375,000
Total outstanding debt(3)	$	1,550,000	$	1,800,000
Production:
Crude oil (MBbls)		8,231		8,404
Natural gas (MMcf)(4)		10,600		10,845
NGLs (MBbls)		396		406
Total (MBOE) (6:1)		10,394		10,618
Average daily production (BOE/d) (6:1)		28,476		29,089

(1) Based on an average benchmark commodity price of $71.98/Bbl for crude oil and $3.94/Mcf for natural gas for the corresponding period.

(2) EBITDA is a non-GAAP measure. See “—Non-GAAP Financial Measures.”

(3) Assumes repayment of an aggregate of $103.3 million of debt outstanding as of December 31, 2024 and maturing prior to December 31, 2025, without any prepayments of debt not maturing prior to December 31, 2025, and the issuance of between $665.4 million and $915.4 million of new debt during the year ending December 31, 2025.

(4) Revenue from natural gas has not historically represented a significant portion of our total revenues. We anticipate this trend to continue and as a result, we currently estimate 844 MMcf to 866 MMcf of natural gas volumes (of the production range presented above) will be sold and recognized as revenues for the year ending December 31, 2025.

Results of Operations for the Year Ended December 31, 2024 Compared to the Year Ended December 31, 2023

The following table summarizes our consolidated results of operations for the periods indicated:

	Year Ended December 31,				Change
(in thousands)	2024		2023 (As Restated)		$			%
Revenues
Mineral and royalty revenues	$	152,999	$	118,088	$	34,911			30	%
Product sales		125,649		—		125,649			NM
Water services		2,478		—		2,478			NM
Other revenues		101		17		84			494	%
Total revenues	$	281,227	$	118,105	$	163,122			138	%
Operating expenses
Cost of sales	$	63,947	$	19,733	$	44,214			224	%
Depreciation, depletion, amortization, and accretion		85,977		34,228		51,749			151	%
Advertising and marketing		679		4,136		(3,457	)		(84	)%
Selling, general, and administrative		29,167		14,314		14,853			104	%
Payroll and payroll-related		27,934		12,733		15,201			119	%
Loss on sale of assets		564		—		564			NM
Impairment expense		564		974		(410	)		(42	)%
Total operating expenses	$	208,832	$	86,118	$	122,714			142	%
Income from operations	$	72,395	$	31,987	$	40,408			126	%
Other expenses

	Year Ended December 31,						Change
(in thousands)	2024			2023 (As Restated)			$			%
Interest income	$	705		$	66		$	639			968	%
Interest expense, net		(90,210	)		(47,882	)		(42,328	)		(88	)%
Loss on derivatives		(5,986	)		(32	)		(5,954	)		18606	%
Loss on debt extinguishment		(1,697	)		(328	)		(1,369	)		417	%
Total other expenses	$	(97,188	)	$	(48,176	)	$	(49,012	)		(102	)%
Net loss	$	(24,793	)	$	(16,189	)	$	(8,604	)		(53	)%

NM – not meaningful.

The following tables summarize our segment operating profit (loss) for the periods indicated:

	Year Ended December 31, 2024
(in thousands)	Mineral and Non-operating			Operating			Securities			Eliminations			Total
Total revenues	$	153,135		$	128,127		$	102,131		$	(102,166	)	$	281,227
Total operating expenses		(109,636	)		(83,982	)		(15,350	)		136			(208,832	)
Segment operating profit (loss)	$	43,499		$	44,145		$	86,781		$	(102,030	)	$	72,395

	Year Ended December 31, 2023
(in thousands)	Mineral and Non-operating			Operating			Securities			Eliminations			Total
Total revenues	$	116,902		$	1,225		$	40,509		$	(40,531	)	$	118,105
Total operating expenses		(67,884	)		(6,725	)		(11,548	)		39			(86,118	)
Segment operating profit (loss)	$	49,018		$	(5,500	)	$	28,961		$	(40,492	)	$	31,987

The following table summarizes our production data and average realized prices for the periods indicated:

	Year Ended December 31,				Change
(in thousands)	2024		2023		Amount			%
Production Data:
Crude oil (Bbls)		3,830,461		1,446,928		2,383,533			165	%
Natural gas (Mcf)		2,979,341		2,152,939		826,402			38	%
NGL (Bbls)		415,363		201,454		213,909			106	%
Total (BOE)(6:1)		4,742,381		2,007,205		2,735,176			136	%
Average daily production (BOE/d) (6:1)		12,993		5,499		7,494			136	%
Average Realized Prices(a):
Crude oil (Bbl)	$	68.49	$	73.10	$	(4.61	)		(6	)%
Natural gas (Mcf)	$	1.86	$	3.15	$	(1.29	)		(41	)%
NGL (Bbl)	$	25.22	$	27.50	$	(2.28	)		(8	)%

(a) Average realized prices are net of certain post-production costs that are deducted from our royalties.

Revenues

The following table shows the components of our revenue for the periods presented:

	Year Ended December 31,				Change
(in thousands)	2024		2023		$			%
Mineral and royalty revenues
Crude oil	$	138,640	$	105,771	$	32,869			31	%
Natural gas		5,424		6,790		(1,366	)		(20	)%
NGL		8,935		5,527		3,408			62	%
Total mineral and royalty revenues	$	152,999	$	118,088	$	34,911			30	%
Product sales
Crude oil	$	123,340	$	—	$	123,340			NM
Natural gas		315		—		315			NM
NGL		1,994		—		1,994			NM
Total product sales	$	125,649	$	—	$	125,649			NM

	Year Ended December 31,				Change
(in thousands)	2024		2023		$		%
Water services	$	2,478	$	—	$	2,478		NM
Other revenue		101		17		84		494	%
Total revenues	$	281,227	$	118,105	$	163,122		138	%

NM – not meaningful.

Revenue was $281.2 million for the year ended December 31, 2024, as compared to $118.1 million for the same period in 2023, an increase of $163.1 million, or 138%. The increase was primarily attributable to a $125.6 million increase in product sales generated from our direct drilling, extraction, and related oil and gas operating activities and a $34.9 million increase in mineral and royalty revenues generated from our mineral and non-operating activities.

Mineral and Non-Operating Segment

Mineral and non-operating segment revenue was $153.1 million for the year ended December 31, 2024, as compared to $116.9 million for the same period in 2023, an increase of $36.2 million, or 31%. The increase in segment revenue was primarily driven by an overall increase in our mineral interests and non-operated working interests in oil and gas properties, which have expanded significantly in recent years. Acquisitions of such interests generally generate revenue in subsequent periods (e.g., on a six to eighteen-month lag). As a result, our mineral and non-operating segment revenue has increased over time as our portfolio of mineral interests and non-operated working interests in oil and gas properties has expanded. During the year ended December 31, 2024, we closed 1,802 unique transactions that added 134,809 NMAs of leasehold interests and 52,959 NRAs of mineral interests to our portfolio, as compared to 790 unique transactions, 64,569 NMA of leasehold interests, and 15,086 NRAs of mineral interests for the same period in 2023. The increase in our mineral and non-operating segment revenue was partially offset by lower commodity prices and higher post-production costs passed through to us relative to the increase in production volumes.

Operating Segment

Operating segment revenue was $128.1 million for the year ended December 31, 2024, as compared to $1.2 million for the same period in 2023. The increase in segment revenue was driven by the commencement of drilling activities by PhoenixOp. PhoenixOp began its operations in the third quarter of 2023 with the acquisition of five producing wells from another operator. As a result, segment revenues for the year ended December 31, 2023 were not material. PhoenixOp commenced production on its operated wells in 2024 and placed into service 32 additional wells as of December 31, 2024, resulting in increased segment revenue for the year ended December 31, 2024 as compared to the same period in 2023.

Operating Expenses

The following table shows the components of our cost of sales for the periods presented:

Cost of Sales

	Year Ended December 31,				Change
(in thousands)	2024		2023		$		%
Cost of sales
Lease operating expenses	$	26,424	$	9,011	$	17,413		193	%
Production taxes		25,457		10,672		14,785		139	%
Production costs		12,066		50		12,016		24,032	%
Total	$	63,947	$	19,733	$	44,214		224	%

Cost of sales was $63.9 million for the year ended December 31, 2024, as compared to $19.7 million for the same period in 2023, an increase of $44.2 million, or 224%. The increase was primarily driven by the commencement of our direct drilling, extraction, and related oil and gas operating activities in 2024, as well as an increase in our mineral interests and non-operated working interests in oil and gas properties.

Mineral and Non-Operating Segment

Mineral and non-operating segment cost of sales was $30.2 million for the year ended December 31, 2024, as compared to $19.3 million for the same period in 2023, an increase of $10.9 million, or 57%. The increase in segment cost of sales was primarily driven by an overall increase in our mineral interests and non-operated working interests in oil and gas properties and the resulting increase in lease operating expenses and production taxes.

Operating Segment

Operating segment cost of sales was $33.8 million for the year ended December 31, 2024, as compared to $0.5 million for the same period in 2023. The increase in segment cost of sales was driven by the commencement of operated production from newly drilled wells by PhoenixOp in the first quarter of 2024, at which time we began to recognize lease operating expenses, production and ad valorem taxes, and production costs in our operating segment. PhoenixOp began its operations in the third quarter of 2023, when it became the operator of five producing wells acquired from another operator. As a result, there were no material cost of sales incurred for the year ended December 31, 2023.

Depreciation, Depletion, Amortization, and Accretion Expense

The following table shows the components of our depletion, depreciation, amortization, and accretion expense for the period presented:

	Year Ended December 31,				Change
(in thousands)	2024		2023		$			%
Depletion, depreciation, amortization, and accretion
Depletion	$	85,706	$	34,035	$	51,671			152	%
Depreciation		91		136		(45	)		(33	)%
Accretion on asset retirement obligations		180		57		123			216	%
Total	$	85,977	$	34,228	$	51,749			151	%

Depreciation, depletion, amortization, and accretion expense was $86.0 million for the year ended December 31, 2024, as compared to $34.2 million for the same period in 2023, an increase of $51.7 million, or 151%, primarily due to an increase in our depletable bases within both the mineral and non-operating segment and the operating segment. On a per unit basis, depletion expense was $18.13 per Boe and $17.05 per Boe for the years ended December 31, 2024 and 2023, respectively. The increase in our depletion expense per Boe was predominantly driven by a higher depletion rate for the year ended December 31, 2024 as compared to the year ended December 31, 2023, as a direct result of the incurrence of significant capital expenditures related to developing operated wells under our operating entity, PhoenixOp. The depletion rate for the development capital is depleted at a higher rate as compared to leasehold due to the use of proved developed reserves versus total proved reserves under the successful efforts accounting method.

Mineral and Non-Operating Segment

Depletion for the mineral and non-operating segment was $50.6 million for the year ended December 31, 2024, as compared to $34.2 million for the same period in 2023. The increase in our segment depletion expense was predominantly driven by increased production and increased capital expenditures.

Operating Segment

Depletion for the operating segment was $35.4 million for the year ended December 31, 2024, as compared to less than $0.1 million for the same period in 2023 due to limited operations in the period.

Selling, General, and Administrative Expense

Selling, general, and administrative expense was $29.2 million for the year ended December 31, 2024, as compared to $14.3 million for the same period in 2023, an increase of $14.9 million, or 104%.

The increase was primarily due to a $9.8 million increase in corporate overhead costs not directly associated with the segments but which have been allocated to the segments based on headcount and a level-of-effort formula, including a $8.8 million increase in legal, accounting and consulting professional services fees, a $2.8 million increase in costs associated with our capital raise initiatives in our securities segment and a $2.8 million increase in fees associated with land acquisition and title work in our mineral and non-operating segment, as further described below.

Mineral and Non-Operating Segment

Selling, general, and administrative expense for the mineral non-operating segment was $14.5 million for the year ended December 31, 2024, as compared to $6.8 million for the same period in 2023, an increase of $7.7 million, or 113%. The increase was primarily due to higher allocated corporate overhead of $4.5 million and increased fees associated with land acquisition and title work of $2.8 million during the year ended December 31, 2024 as compared to the same period in the prior year. This was primarily associated with our increased activity in acquiring leasehold and mineral assets.

Operating Segment

Selling, general, and administrative expense for the operating segment was $6.2 million for the year ended December 31, 2024, as compared to $2.8 million for the same period in 2023, an increase of $3.4 million, or 121%. The increase was due to PhoenixOp’s first full year period of full-time operations. PhoenixOp began its drilling and completion activities in September 2023 and operations continually grew throughout 2024.

Securities Segment

Selling, general, and administrative expense for the securities segment was $8.5 million for the year ended December 31, 2024, as compared to$4.7 million for the same period in 2023, an increase of $3.8 million, or 81%. The increase was primarily due to increased legal costs associated with our securities offerings of $2.0 million, increased securities administration costs of $0.8 million, and increased allocated corporate overhead of $0.9 million.

Payroll and Payroll-Related Expense

Payroll and payroll-related expense was $27.9 million for the year ended December 31, 2024, as compared to $12.7 million for the same period in 2023, an increase of $15.2 million, or 119%, primarily as a result of increased employee headcount, which increased from 118 employees at December 31, 2023 to 135 employees at December 31, 2024.

Mineral and Non-Operating Segment

Payroll and payroll-related expense for the mineral and non-operating segment was $13.3 million for the year ended December 31, 2024, as compared to $6.4 million for the same period in 2023, an increase of $6.9 million, or 108%, due to increased activity in acquiring leasehold and mineral assets.

Operating Segment

Payroll and payroll-related expense for the operating segment was $8.6 million for the year ended December 31, 2024, as compared to $3.2 million for the same period in 2023, an increase of $5.4 million, or 171%, due to PhoenixOp’s first full year period of full time operations.

Securities Segment

Payroll and payroll-related expense for the securities segment was $6.1 million for the year ended December 31, 2024, as compared to $3.2 million for the same period in 2023, an increase of $2.9 million, or 91%, primarily due to the increased number of personnel engaged in the administration and management of our securities offerings.

Advertising and Marketing Expense

Advertising and marketing expense was $0.7 million for the year ended December 31, 2024, as compared to $4.1 million for the same period in 2023, a decrease of $3.5 million, or 84%. The decrease was primarily the result of spending $3.6 million on an audio marketing campaign in 2023 attributable to the securities segment that did not recur in 2024.

Loss on Sale of Assets

Loss on sale of assets was $0.6 million for the year ended December 31, 2024 as a result of the disposition of certain mineral interests in the Williston basin within the mineral and non-operating segment, with no comparable activity in the prior-year period.

Impairment Expense

Impairment expense was $0.6 million for the year ended December 31, 2024, as compared to $1.0 million for the same period in 2023. In 2024, impairment expense was a result of write-offs associated with title defects and lease expirations within the mineral and non-operating segment, whereas impairment expense in 2023 was attributable to a decrease in natural gas prices and the resulting impairment of the carrying value of our proved natural gas properties within the mineral and non-operating segment.

Other Expenses

Interest Expense

Interest expense was $90.2 million for the year ended December 31, 2024, as compared to $47.9 million for the same period in 2023, an increase of $42.3 million, or 88%. The increase was primarily due to increased sales of our unregistered debt securities,

which increased from $421.8 million outstanding at December 31, 2023 to $737.9 million outstanding at December 31, 2024, with no significant changes in interest rates between the periods, and a $2.9 million increase in amortized debt discount and debt issuance costs for the year ended December 31, 2024 as compared to the prior-year period.

Loss on Derivatives

Loss on derivatives was $6.0 million for the year ended December 31, 2024, as compared to less than $0.1 million for the same period in 2023. The increase was primarily a result of unfavorable changes in the mark-to-market value of commodity derivatives entered into during the second half of 2024, with limited comparable activity for the same period in 2023.

Loss on Debt Extinguishment

Loss on debt extinguishment was $1.7 million for the year ended December 31, 2024, as compared to $0.3 million for the same period in 2023. The increase was primarily due to increased write-offs of debt issuance costs associated with the early redemptions of bonds issued pursuant to Regulation A (“Regulation A”) under the U.S. Securities Act of 1933, as amended (the “Securities Act”), and Regulation D under the Securities Act (“Regulation D”), of which $17.7 million of bonds were redeemed during the year ended December 31, 2024, as compared to $4.3 million of bonds redeemed for the same period in 2023.

	Year Ended December 31,				Change
(in thousands)	2024		2023		$			%
August 2023 506(c) Bonds	$	12,426	$	265	$	12,161			4589	%
Reg A Bonds		2,306		2,122		184			9	%
December 2022 506(c) Bonds		1,592		1,004		588			59	%
Adamantium Bonds		1,319		—		1,319			NM
July 2022 506(c) Bonds		100		915		(815	)		(89	)%
Total	$	17,743	$	4,306	$	13,437			312	%

NM – not meaningful.

Non-GAAP Financial Measures

Our management uses EBITDA to understand and compare our operating results across accounting periods, for internal budgeting and forecasting purposes, and to evaluate financial performance and liquidity, in each case, without regard to financing methods, capital structure, or historical cost basis. EBITDA is presented as supplemental disclosure as we believe it provides useful information to investors and others in understanding and evaluating our results, prospects, and liquidity period over period, including as compared to results of other companies. By providing this non-GAAP financial measure, together with a reconciliation to GAAP results, we believe we are enhancing investors’ understanding of our business and our operating performance, as well as assisting investors in evaluating how well we are executing strategic initiatives.

EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect net income (loss), the most directly comparable GAAP measure. In particular, EBITDA excludes certain material costs, such as interest expense, and certain non-cash charges, such as depreciation, depletion, amortization, and accretion expense, which have been necessary elements of our expenses. Because EBITDA does not account for these expenses, its utility as a measure of our operating performance has material limitations. Other companies may not publish this or similar metrics, and our computation of EBITDA may differ from computations of similarly titled measures of other companies. Therefore, our EBITDA should be considered in addition to, and not as a substitute for, in isolation from, or superior to, our financial information prepared in accordance with GAAP, and should be read in conjunction with our consolidated financial statements and the related notes included elsewhere in this Annual Report.

The following table shows a reconciliation of EBITDA to net income (loss), the most comparable GAAP measure, as presented in the consolidated statements of operations for the periods presented:

	Year Ended December 31,
(in thousands)	2024			2023
Net loss	$	(24,793	)	$	(16,189	)
Interest income		(705	)		(66	)
Interest expense		90,210			47,882
Depreciation, depletion, amortization, and accretion expense		85,977			34,228
EBITDA	$	150,689		$	65,855

EBITDA was $150.7 million for the year ended December 31, 2024, as compared to $65.9 million for the same period in 2023, an increase of $84.8 million, or 129%. The increase in EBITDA was primarily driven by a $163.1 million increase in consolidated revenues, partially offset by a $71.0 million increase in operating expense (excluding depreciation, depletion, amortization and accretion expense), primarily driven by increased cost of sales and increased legal, accounting and land-related professional service fees and other corporate overhead costs, and a increase $6.0 million increase in loss on derivatives primarily due to unfavorable changes in the mark-to-market value of commodity derivatives entered into during the second half of 2024.

We expect our EBITDA to grow substantially in 2025 as the capital raised and deployed by us is expected to produce meaningful revenues. In 2024, the majority of revenues were produced from our properties acquired in 2023. Our management expects that the $864.0 million raised during the year ended December 31, 2024, and the corresponding investments in properties acquired and, in the case of properties and cash contributed to PhoenixOp, developed through the year ended December 31, 2024, will continue producing substantial revenues in 2025.

Liquidity and Capital Resources

Overview

Our primary sources of liquidity are cash flows from operations, borrowings under credit agreements, and issuances of debt securities pursuant to Regulation D and Regulation A, including the Adamantium Securities, the Reg D Bonds, and Reg A Bonds. Future sources of liquidity may also include other credit facilities, additional capital contributions, and continued issuances of debt or equity securities. Our primary uses of cash have been the acquisition of mineral and royalty interests, lease operating expenses, and our proportionate share of production, severance, and ad valorem taxes for mineral and royalty interests, production costs, including gathering, processing, and transportation costs, debt service payments, the reduction of outstanding debt balances, general overhead and other corporate expenses, and distributions to our members. As we continue to engage in increased drilling and direct production activities through PhoenixOp, we expect development and operation of PhoenixOp’s properties to become an increasingly significant use of our cash. As of December 31, 2024, we had cash and cash equivalents of $120.8 million and outstanding indebtedness of $987.9 million.

As of February 28, 2025, we had $119.1 million of debt coming due and $78.7 million of interest payable within the next 12 months. Over the next 12 months, we expect to drill between 75 to 80 gross and 49.7 to 53.0 net wells across our operated leasehold acreage in the Bakken/Willison Basin in North Dakota and Montana, and expect to participate in the drilling of approximately between 125 to 175 gross and 9.8 to 13.7 net wells across our non-operated leasehold. We estimate that these direct drilling operations and non-operated activity will require between $716.0 million and $746.0 million of capital expenditures over the next 12 months.

Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations, or to refinance our indebtedness, will depend on our ability to generate cash in the future. Although we expect that our cash flows from operations will be sufficient to meet our fixed obligations, to fully realize our business plan we expect that we will need to raise approximately $400 million in capital in 2025 through the incurrence of additional debt. We believe that these sources of liquidity will be sufficient to meet our cash requirements, including normal operating needs, debt service obligations, and capital expenditures, for at least the next 12 months, and will allow us to continue to execute on our strategy of expanding our direct drilling operations through PhoenixOp and acquiring attractive mineral and royalty interests in order to position us to grow our cash flows.

We periodically assess changes in current and projected cash flows, acquisition and divestiture activities, and other factors to determine the effects on our liquidity. Our ability to generate cash is subject to a number of factors, many of which are beyond our control, including commodity prices, weather, and general economic, financial, competitive, legislative, regulatory, and other factors. If cash flow from operations does not meet our expectations, we may reduce our expected level of capital expenditures. If we require additional capital for acquisitions or other reasons, we may raise such capital through additional borrowings, asset sales, offerings of equity and debt securities, or other means. We cannot assure you that necessary capital will be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness could be limited by covenants in our debt arrangements. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that are favorable to us or finance the capital expenditures necessary to maintain our production or proved reserves.

We or our affiliates may from time to time seek to repurchase or retire our debt securities or our other indebtedness through cash purchases and/or exchanges for equity or debt securities, in open-market purchases, privately negotiated transactions, tender or exchange offers, or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity, contractual restrictions, and other factors. The amounts involved may be material. For more information regarding the material terms of our outstanding indebtedness, see “—Indebtedness” below.

Cash Flows

The following table summarizes our cash flows for the periods indicated:

	Year Ended December 31,
	2024			2023 (As Restated)
				(in thousands)
Net cash provided by (used in)
Operating activities	$	95,239		$	(1,826	)
Investing activities		(437,703	)		(278,661	)
Financing activities		457,850			281,308
Net increase in cash and cash equivalents	$	115,386		$	821

Operating Activities

Net cash provided by operating activities for the year ended December 31, 2024 was $95.2 million, as compared to $1.8 million used in operations for the same period in 2023, an increase of $97.0 million in cash provided by operating activities. The increase was primarily due to a $54.7 million increase in net income, adjusted for non-cash charges of $63.3 million, and net favorable fluctuations of $41.8 million from changes in operating assets and liabilities. The $41.8 million cash inflow from changes in operating assets and liabilities was primarily due to a net increase of $28.6 million in accounts receivable, accounts payable, and accrued and other liabilities, primarily due to the timing of cash receipts and payments, and a $13.8 million increase in accrued interest from the increased amount of debt securities issued during the year ended December 31, 2024 as compared to the same period in 2023.

Investing Activities

Net cash used in investing activities for the year ended December 31, 2024 was $437.7 million, as compared to $278.7 million for the same period in 2023, an increase of $159.0 million. The increase was primarily driven by a $165.2 million increase in additions to oil and gas properties, primarily due to increased drilling and completion activities in our operating segment during the year ended December 31, 2024, with limited operations for the same period in 2023, and $6.2 million of proceeds received in connection with the disposition of mineral interests during the year ended December 31, 2024 that did not occur in the prior-year period.

Financing Activities

Net cash provided by financing activities for the year ended December 31, 2024 was $457.9 million, as compared to $281.3 million for the same period in 2023, an increase of $176.6 million. The increase was primarily driven by increased proceeds from issuances of debt, net of debt discount, of $399.5 million and a $2.7 million decrease in members’ distributions, partially offset by a $188.7 million increase in repayments of debt, a $20.3 million increase in payments of debt issuance costs, a $9.8 million decrease in members’ contributions, and a $6.9 million increase in payments of deferred closings associated with mineral interest acquisitions.

Indebtedness

Set forth below is a chart of our outstanding third-party indebtedness as of December 31, 2024 (dollars in thousands):

Indebtedness

Offering Commencement

Principal Amount Outstanding

Term

Earliest Maturity

Latest Maturity

Interest Rate

Secured

Fortress Credit Agreement(1)

N/A

$

250,000

3 years

—

12/18/2027

Term SOFR + 7.10

%

Adamantium Secured Notes(2)

N/A

7,000

7 years

—

11/1/2031

16.5

%

Unsecured

Reg A Bonds(3)

12/23/2021

104,884

3 years

1/10/2025

8/10/2027

9.0

%

2020 506(b) Bonds(4)

7/20/2020

940

2 years

—

3/31/2025

5.0

%

2020 506(c) Bonds(4)

10/22/2020

2,098

1-4 years

9/30/2025

6/27/2027

13.0-15.0

%

July 2022 506(c) Bonds(4)

7/20/2022

10,457

5 years

7/31/2027

12/31/2027

11.0

%

December 2022 506(c) Bonds(5)

Series B

12/22/2022

17,324

3 years

4/10/2025

10/10/2026

10.0

%

Series C

12/22/2022

9,984

5 years

12/10/2027

9/10/2028

11.0

%

Series D

12/22/2022

41,666

7 years

12/10/2029

10/10/2030

12.0

%

August 2023 506(c) Bonds(5):

Series U, AA, and FF

8/29/2023

74,254

1 year

1/10/2025

12/10/2025

9.0% - 10.0

%

Series V, BB, and GG

8/29/2023

59,383

3 years

8/10/2026

12/10/2027

10.0% - 11.0

%

Series W, CC, and HH

8/29/2023

31,265

5 years

8/10/2028

12/10/2029

11.0% - 12.0

%

Series X, DD, and II

8/29/2023

62,056

7 years

9/10/2030

12/10/2031

12.0% - 13.0

%

Indebtedness

Offering Commencement

Principal Amount Outstanding

Term

Earliest Maturity

Latest Maturity

Interest Rate

Series Y

8/29/2023

4,043

9 years

9/10/2032

9/10/2033

12.5

%

Series Z, EE, and JJ

8/29/2023

184,353

11 years

8/10/2034

12/10/2035

13.0% - 14.0

%

Total Reg D Bonds and Reg A Bonds

$

602,707

Adamantium Bonds(6)

9/29/2023

128,180

5-11 years

1/10/2029

12/10/2035

13.0% - 16.0

%

Total Unsecured Debt

$

730,887

Total Debt

$

987,887

(1) The Fortress Credit Agreement provides for a $100.0 million term loan facility, borrowed in full on August 12, 2024, a $35.0 million delayed draw term loan facility, which was fully drawn in October 2024, and a $115.0 million term loan facility, borrowed in full on December 18, 2024. Amount displayed does not include amounts drawn after September 30, 2024. The Fortress Credit Agreement also provides for an $8.5 million tranche of loans that represents a contingent principal obligation that is only due and payable (together with accrued interest thereon) upon certain conditions occurring, including payment defaults under the Fortress Credit Agreement or a bankruptcy filing by the obligors thereunder. See “ — Fortress Credit Agreement.”

(2) The Adamantium Secured Note (as defined below) is contractually subordinated to amounts under the Fortress Credit Agreement, contractually senior to the Adamantium Bonds (as defined below), and structurally senior to the Reg D Bonds (as defined below) and Reg A Bonds to the extent of the value of Adamantium’s assets, including the collateral securing the Adamantium Loan Agreement.

(3) The Reg A Bonds are pari passu obligations with the Senior Reg D Bonds (as defined below), and are contractually senior to obligations under the Subordinated Reg D Bonds (as defined below).

(4) The Senior Reg D Bonds are pari passu obligations with the Reg A Bonds, are contractually subordinated to amounts under the Fortress Credit Agreement, and are contractually senior to obligations under the Subordinated Reg D Bonds.

(5) The Subordinated Reg D Bonds are contractually subordinated to obligations under the Fortress Credit Agreement, the Reg A Bonds, and the Senior Reg D Bonds. Between January 1, 2025 and February 28, 2025, we issued an additional $91.3 million of August 2023 506(c) Bonds (as defined below), with maturities ranging from December 2025 to February 2036 and interest rates between 9.0% and 14.0% per annum.

(6) The Adamantium Bonds are contractually subordinated to amounts under the Fortress Credit Agreement and the Adamantium Secured Note, structurally senior to the Reg D Bonds and Reg A Bonds to the extent of the value of Adamantium’s assets, including the collateral securing the Adamantium Loan Agreement. Between January 1, 2025 and February 28, 2025, we issued an additional $26.3 million of Adamantium Bonds (and borrowed a corresponding amount under the Adamantium Loan Agreement), with maturities ranging from December 2029 to February 2036 and interest rates between 13.0% and 16.0% per annum.

ANB Credit Agreement

The Company and PhoenixOp were borrowers under that certain Commercial Credit Agreement (the “ANB Credit Agreement”), which they entered into with Amarillo National Bank, a national banking association (“ ANB”) on July 24, 2023. The ANB Credit Agreement provided for a $30.0 million revolving credit loan by ANB, and, as of June 30, 2024, the outstanding balance was $30.0 million. The proceeds from the borrowing under the ANB Credit Agreement were used in part to repay in full our outstanding facility with Cortland Credit Lending Corporation. ANB’s commitments under the ANB Credit Agreement and the loans thereunder were initially scheduled to terminate and mature, and be due and payable in full, on July 24, 2024. On July 24, 2024, we entered into an agreement that extended ANB’s commitments and the maturity of the loans under the ANB Credit Agreement to September 24, 2024. We fully repaid all amounts owed under the ANB Credit Agreement on August 12, 2024 in connection with entering into the Fortress Credit Agreement.

Fortress Credit Agreement

The Company and PhoenixOp, as borrower, entered into the Fortress Credit Agreement with Fortress on August 12, 2024. The Fortress Credit Agreement provides for a $100.0 million term loan facility (the “Fortress Term Loan”), borrowed in full on August 12, 2024, and a $35.0 million delayed draw term loan facility, which was borrowed in full on October 11, 2024 (any loans thereunder, together with the Fortress Term Loan, the “Fortress Tranche A Loans”). On December 18, 2024, the Fortress Credit Agreement was amended to, among other things, provide for a new tranche of term loans (the “Fortress Tranche C Loan”) in an aggregate principal amount of $115.0 million that was borrowed in full on December 18, 2024. The Fortress Credit Agreement also includes an $8.5 million tranche of loans (the “Fortress Tranche B Loan” and, together with the Fortress Tranche A Loans and the Fortress Tranche C Loan, the “Fortress Loans”), which represents a contingent principal obligation that is only due and payable (together with accrued interest thereon) if subject to certain exceptions, either (a) the Company has not paid in full all outstanding principal and accrued interest on the Fortress Loans in cash by March 31, 2027 or (b) an Event of Default (as defined in the Fortress Credit Agreement) has occurred resulting from the failure to pay principal or interest when due under the terms and conditions of the Fortress Credit Agreement.

Obligations under the Fortress Credit Agreement are secured by substantially all of the assets of Phoenix Equity and its subsidiaries that have guaranteed the obligations of the obligors under the Fortress Credit Agreement, subject to certain exceptions (the Company, PhoenixOp, and such subsidiaries, collectively, the “Credit Parties”). Furthermore, pursuant to that certain Assignment of

Loans and Liens, dated as of August 12, 2024, among the Company, Phoenix Operating, ANB, Fortress, as administrative agent and as collateral agent, and the new lenders party thereto, ANB assigned, and Fortress assumed, all security interests granted by the Credit Parties in favor of ANB under the ANB Credit Agreement. The lenders under the Fortress Credit Agreement also purchased and assumed from ANB all of the outstanding extensions of credit made by ANB under the ANB Credit Agreement. As a result of the foregoing, the ANB Credit Agreement and all related documentation ceased to be of any force and effect.

The Fortress Term Loan and the Fortress Tranche B Loan were each subject to original issue discount (“OID”) of 10.59907834%, and each of the Fortress Tranche A Loans made under the delayed draw term loan facility and the Fortress Tranche C Loan were subject to 3.00% OID.

Borrowings under the Fortress Credit Agreement bear interest at a rate per annum equal to Term SOFR (as defined in the Fortress Credit Agreement) plus 0.10% plus 7.00%. Interest on the Fortress Tranche A Loans and Fortress Tranche C Loan is payable quarterly in arrears. The outstanding principal amount of the Fortress Loans (including, if applicable, the Fortress Tranche B Loan) must be repaid as follows: (i) on December 31, 2026, $125.0 million of the outstanding principal amount of the Fortress Loans less the aggregate amount of all voluntary prepayments and mandatory prepayments made as of December 31, 2026; and (ii) the remaining aggregate outstanding principal amount on December 18, 2027. In connection with any payment in full of the Fortress Loans (whether by voluntary prepayment, acceleration, or on the maturity date), PhoenixOp will pay a repayment premium in an amount sufficient to achieve a MOIC (as defined in the Fortress Credit Agreement) of 1.18.

The Fortress Credit Agreement contains various customary affirmative and negative covenants, as well as financial covenants. The Fortress Credit Agreement requires the Company to maintain (a) a maximum total secured leverage ratio (i) as of the last day of any fiscal quarter ending on or before December 31, 2025 of less than or equal to 2.00 to 1.00 (commencing with the fiscal quarter ending December 31, 2024), and (ii) as of the last day of any fiscal quarter ending on or after March 31, 2026 of less than or equal to 1.50 to 1.00, (b) a minimum current ratio as of the last day of each calendar month of (i) 0.90 to 1.00 from September 30, 2024 through October 31, 2024, (ii) 0.80 to 1.00 from November 30, 2024 through November 30, 2025, (iii) 0.90 to 1.00 from December 31, 2025 through December 31, 2026, and (iv) 1.00 to 1.00 for each calendar month ending thereafter, and (c) a minimum asset coverage ratio as of the last day of any fiscal quarter of at least 2.00 to 1.00. The Fortress Credit Agreement also places certain limits on the Company’s ability to incur additional indebtedness, including the issuance of unsecured notes or bonds and accounts receivable factoring arrangements. As of December 31, 2024, we believe we were in compliance with all of the financial covenants contained in the Fortress Credit Agreement.

The Fortress Credit Agreement contains customary events of default, including, but not limited to, nonpayment of the Fortress Tranche A Loans or Fortress Tranche C Loan and any other material indebtedness, material inaccuracies of representations and warranties, violations of covenants, certain bankruptcies and liquidations, certain material judgments, and certain events related to the security documents.

As described above, a portion of the proceeds from the Fortress Term Loan was used to pay all amounts owed under the ANB Credit Agreement. The Company and PhoenixOp will use the remaining proceeds of the Fortress Loans to finance the development of oil and gas properties in accordance with the approved plan of development as provided in the Fortress Credit Agreement.

Adamantium Debt

Adamantium was formed on June 21, 2023, as a wholly owned financing subsidiary of the Company for the purpose of undertaking financing efforts under Regulation D and subsequently loaning amounts to the Company and/or its subsidiaries, as needed. Adamantium offers high net worth individuals unsecured bonds pursuant to an offering under Rule 506(c) of Regulation D that commenced in September 2023 (the “Adamantium Bonds”), and does not expect to undertake financing efforts under Regulation A. Adamantium has in the past, and may in the future, issue debt securities in other offerings exempt from registration under the Securities Act under Section 4(a)(2) thereof or any other available exemption, including, for example, the Adamantium Secured Note.

On September 14, 2023, the Company, as borrower, entered into the Adamantium Loan Agreement with Adamantium, as lender. On October 30, 2023, the Company, Adamantium, and PhoenixOp entered into an amendment to the Adamantium Loan Agreement to add PhoenixOp as a borrower, and on November 1, 2024 entered into another amendment to increase the loan amount thereunder. The Adamantium Loan Agreement provides for up to $407.0 million in aggregate principal amount of borrowings in one or more advances, comprising $400.0 million from the proceeds of Adamantium Bonds and $7.0 million from the proceeds of the Adamantium Secured Note. Adamantium may, but is not guaranteed to, issue $400 million in aggregate principal amount of Adamantium Bonds to fund advances to the Company and PhoenixOp pursuant to the Adamantium Loan Agreement. The timing of any advance under the Adamantium Loan Agreement is contingent upon Adamantium’s receipt of proceeds from the sale of Adamantium Securities. Each advance will have a maturity and interest rate that matches the terms of the respective Adamantium Securities sold prior to such advance and to which such advance relates. We expect to use the proceeds of borrowings under the Adamantium Loan Agreement (i) to purchase mineral rights and non-operated working interests, as well as additional asset acquisitions, (ii) to finance potential drilling and exploration operations of one or more subsidiaries (including PhoenixOp), and (iii) for other working capital needs.

As of December 31, 2024, $128.1 million aggregate principal amount of Adamantium Bonds was outstanding, with maturity dates ranging from five to eleven years from the issue date and interest rates ranging from 13.0% to 16.0% per annum, and $7.0 million aggregate principal amount was outstanding under that certain Secured Subordinated Promissory Note, dated as of November 1, 2024, by and between Adamantium and the noteholder named therein (as the same may be amended and supplemented from time to time, the “Adamantium Secured Note” and, together with the Adamantium Bonds, the “Adamantium Securities”), which initially matures in November 2031, has an interest rate of 16.5% per annum, and is secured by Adamantium’s rights under the Adamantium Loan Agreement, and, in each case, the corollary amount of borrowings was outstanding under the Adamantium Loan Agreement. Between January 1, 2025 and February 28, 2025, we issued an additional $26.3 million of Adamantium Bonds (and borrowed a corresponding amount under the Adamantium Loan Agreement), with maturities ranging from December 2029 to February 2036 and interest rates between 13.0% and 16.0% per annum.

The Adamantium Securities contain customary events of default and may be redeemed at the option of Adamantium at any time without premium or penalty. The holders of Adamantium Bonds also have a right to request redemption of their bonds in certain circumstances at a discount to par, subject to a limit of 10% of the then-outstanding principal amount of Adamantium Bonds in any given calendar year. The holder of the Adamantium Secured Note has the right to request redemption of its note at par, subject to a limit of $5.0 million in aggregate principal amount of the Adamantium Secured Note in any 12-month period.

Amounts loaned under the Adamantium Loan Agreement are secured by mortgages on certain of our properties, which mortgages are junior to the security interest under the Fortress Credit Agreement and other existing and future senior secured indebtedness. The aggregate outstanding amount of all advances under the Adamantium Loan Agreement may not exceed 100% of the aggregate total discounted present value of the junior mortgages serving as collateral thereunder, after deducting any allocable amount securing any of our outstanding senior indebtedness (the “Adamantium Loan-to-Value Ratio”). The value of such collateral will be determined by one or more reserve studies performed by a third party retained by us on an annual basis. In the event the aggregate amount outstanding under the Adamantium Loan Agreement exceeds the Adamantium Loan-to-Value Ratio, we may cure such deficiency by either pledging additional collateral or repaying a portion of the borrowings under the Adamantium Loan Agreement until the Adamantium Loan-to-Value Ratio is achieved.

At the option of Adamantium, an advance may be made on either (i) a current basis, whereby the Company makes interest-only monthly payments in cash to Adamantium on the tenth day of each month or (ii) an accrual basis, whereby interest is compounded monthly and the Company will pay all accrued and unpaid interest at maturity of the respective advance. Interest will accrue a full pro rata portion of the annual rate of interest for each calendar month regardless of the number of days an advance is outstanding during such calendar month, on the same terms as the interest payable on the Adamantium Securities sold prior to such advance and to which such advance relates. On each respective maturity date for advances made on both a current and accrual basis, the outstanding principal amount, together with all accrued and unpaid interest thereon, will mature and be due and payable to Adamantium. To the extent the Adamantium Securities are accelerated or prepaid, in whole or in part, the Company will be obligated to pay or prepay, in whole or in part, all or any part of any outstanding indebtedness under the Adamantium Loan Agreement so as to satisfy the obligations and terms of the accelerated or prepaid Adamantium Securities. Adamantium will use any amounts repaid under the Adamantium Loan Agreement to repay the corresponding Adamantium Securities. The Adamantium Loan Agreement is not a revolving facility and the Company may not reborrow amounts repaid.

The Adamantium Loan Agreement can be amended or waived with the consent of the Company and Adamantium, including in order to change the amount, rate, payment terms, collateral package, and borrowers thereunder. The consent of holders of the Adamantium Securities, the Reg D Bonds, and/or Reg A Bonds is not required for any amendment or waiver of the Adamantium Loan Agreement, and any such amendment or waiver may be adverse to the interests of such holders. Because Adamantium is a wholly owned financing subsidiary of the Company with common management, there exists the potential for conflicts of interest with respect to decisions regarding the Adamantium Loan Agreement, including with respect to waivers and amendments thereto. Management is committed to fulfilling its fiduciary duties and operating in good faith.

Reg D Bonds

As of December 31, 2024, the Company had $497.8 million aggregate principal amount outstanding of unsecured bonds issued pursuant to Regulation D (the “Reg D Bonds”), consisting of:

(a) $13.5 million aggregate principal amount outstanding of Reg D Bonds that rank pari passu with the Reg A Bonds, are contractually subordinated to amounts under the Fortress Credit Agreement, and are contractually senior to obligations under the Subordinated Reg D Bonds, (the “Senior Reg D Bonds”) comprising:

(i) $0.9 million aggregate principal amount outstanding of unsecured bonds offered and sold pursuant to an offering under Rule 506(b) of Regulation D that commenced in July 2020 and terminated in September 2021, with initial maturity dates ranging from one to four years from the issue date and an interest rate of 5.0% per annum (the “2020 506(b) Bonds”);

(ii) $2.1 million aggregate principal amount outstanding of unsecured bonds offered and sold pursuant to an offering under Rule 506(c) of Regulation D that commenced in October 2020 and terminated in July 2022, with maturity dates ranging from one to four years from the issue date and interest rates ranging from 13.0% to 15.0% per annum (the “2020 506(c) Bonds”); and

(iii) $10.5 million aggregate principal amount outstanding of unsecured bonds offered and sold pursuant to an offering under Rule 506(c) of Regulation D that commenced in July 2022 and terminated in December 2022, with a maturity date of five years from the issue date and an interest rate of 11.0% per annum (the “July 2022 506(c) Bonds”);

(b) $484.3 million aggregate principal amount outstanding of Reg D Bonds that are contractually subordinated to obligations under the Fortress Credit Agreement, the Reg A Bonds, and the Senior Reg D Bonds, comprising:

(i) $69.0 million aggregate principal amount outstanding of Series AAA through Series D-1 unsecured bonds offered and sold pursuant to an offering under Rule 506(c) of Regulation D that commenced in December 2022 and terminated in August 2023, with maturity dates ranging from nine months to seven years from the issue date and interest rates ranging from 8.0% to 12.0% per annum (the “December 2022 506(c) Bonds”); and

(ii) $415.3 million aggregate principal amount outstanding of Series U through Series JJ-1 unsecured bonds offered and sold to date pursuant to an offering under Rule 506(c) of Regulation D that commenced in August 2023 with maturity dates ranging from one to eleven years from the issue date and interest rates ranging from 9.0% to 14.0% per annum (the “August 2023 506(c) Bonds”).

The Reg D Bonds contain customary events of default and may be redeemed at the option of the Company at any time without premium or penalty. Holders of Reg D Bonds (other than the 2020 506(b) Bonds and 2020 506(c) Bonds) have a right to request redemption of their bonds in certain circumstances at a discount to par, subject to a limit of 10% of the then-outstanding principal amount of the applicable series in any given calendar year.

Between January 1, 2025, and February 28, 2025, the Company issued an additional $91.3 million of August 2023 506(c) Bonds with maturities ranging from December 2025 to February 2036 and interest rates between 9.0% and 14.0% per annum.

Reg A Bonds

As of December 31, 2024, the Company had $104.9 million aggregate principal amount outstanding of Reg A Bonds, which are unsecured bonds offered and sold to date pursuant to an offering under Regulation A, which commenced in December 2021 and are being offered on a continuous basis, which Reg A Bonds rank pari passu with the Senior Reg D Bonds, and are contractually senior to obligations under the Subordinated Reg D Bonds.

The Reg A Bonds contain customary events of default and may be redeemed at the option of the Company at any time without premium or penalty. The Company will also be obligated to offer to holders of Reg A Bonds the right to have their bonds repurchased upon a change of control (as described in the indenture governing the Reg A Bonds). The holders of Reg A Bonds also have a right to request redemption of their bonds in certain circumstances at a discount to par, subject to a limit of 10% of the then-outstanding amount of the applicable series in any given calendar year.

Contractual Obligations and Commitments

A summary of our contractual obligations, commitments, and other liabilities as of December 31, 2024 is presented below:

(in thousands)	2025		2026-2027		2028-2029		Thereafter		Total
Debt obligations(1)	$	103,319	$	416,255	$	58,424	$	409,889	$	987,887
Interest payable(2)		80,488		135,451		87,063		667,443		970,445
Operating lease obligations(3)		1,293		2,657		2,480		3,047		9,477
Deferred closing arrangements(4)		7,189		3,324		—		—		10,513
Drilling rig obligations(5)		8,442		—		—		—		8,442
Total	$	200,731	$	557,687	$	147,967	$	1,080,379	$	1,986,764

(1) Debt obligations represent the principal amounts outstanding under our short-term debt and long-term debt (including the current portion) as of December 31, 2024 and are based on the stated maturity dates. The table above assumes no prepayments or early redemptions, and does not reflect additional debt incurred or repaid after December 31, 2024.

(2) Interest payable is estimated based on final maturity dates of debt securities outstanding at December 31, 2024 and does not reflect anticipated future refinancing, early redemptions, or new debt issuances after December 31, 2024. Floating rate interest obligations are estimated based on rates as of December 31, 2024.

(3) We lease office space in California, Colorado, Florida, Texas, and Wyoming, which have non-cancelable lease agreements expiring in various years through April 2034. The amounts in this table represent the minimum lease payments required over the term of the lease.

(4) For certain mineral interest acquisitions, we have agreed to pay the purchase price in installments together with interest, with interest rates ranging from 8.0% to 15.0% per annum. The amounts in this table represent the remaining payments due over bespoke terms ranging from 11 to 48 months.

(5) Drilling rig obligations represent amounts outstanding under the remaining term of drilling rig contracts entered into with third parties during the year ended December 31, 2024.

Critical Accounting Policies and Use of Estimates

This discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of financial statements in conformity with GAAP requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenue, and expenses, and disclosures of contingent assets and liabilities, including with respect to quantities of oil, natural gas, and NGL reserves that are the basis for the calculations of depreciation, depletion, and amortization and determinations of impairment of oil and natural gas properties. Our significant accounting policies are described in Note 2, “Significant Accounting Policies,” of the accompanying consolidated financial statements included elsewhere in this Annual Report.

Critical accounting policies are those that we consider to be the most important in portraying our financial condition and results of operations and also require the greatest amount of judgments by management, including requiring an accounting estimate to be made based on assumptions about matters that are highly uncertain at the time the estimate is made, if different estimates reasonably could have been used, or if changes in the estimate that are reasonably possible could materially impact the financial statements. We base our estimates on historical experience and on various other assumptions we believe to be reasonable according to the facts and circumstances at the time the estimates are made. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of financial statements. Judgments or uncertainties regarding the application of these policies may result in materially different amounts being reported under different conditions or using different assumptions. There can be no assurance that actual results will not differ from those estimates and assumptions.

Furthermore, reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas and there are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment along with estimated selling prices. As a result, reserve estimates may materially differ from the quantities of oil and natural gas that are ultimately recovered. We consider the following policies to be the most critical in understanding the judgments that are involved in preparing our consolidated financial statements.

Oil and Gas Properties

We invest in crude oil and natural gas properties, including mineral interests and working interests as a non-operator and operator. Exploration and production activities are accounted for in accordance with the successful-efforts method of accounting. Under this method, costs of acquiring proved mineral interests in crude oil and natural gas properties, development wells, related plant and equipment, and related asset retirement obligation assets are capitalized. Costs of proved but undeveloped wells are initially capitalized to wells-in-progress until the well becomes productive. Once the well is productive, accumulated capitalized costs are reclassified to proved and producing properties and accounted for following the successful efforts method of accounting. Costs are also capitalized for unevaluated wells that have found crude oil and natural gas reserves even if the reserves cannot be classified as proved when the drilling is completed, provided the unevaluated well has found a sufficient quality of reserves to justify its completion as an economically and operationally viable producing well. If proved reserves are not found, unevaluated well costs are expensed as dry holes. All other unevaluated wells and costs, and all general and administrative costs unrelated to acquisitions, are expensed as incurred.

Depletion of capitalized costs is recorded using the units-of-production method based on proved reserves. The depletion rate is determined by dividing the cumulative recovered barrels of oil equivalent by the estimated ultimate recovery by well and averaged among all wells within the pooled unit. This rate is multiplied by the original cost basis and reduced by depletion taken in prior periods. The cost basis remaining represents the percentage of the asset remaining to be recovered by the wells within the pooled unit.

Impairment of Long-lived Assets

We follow the provisions of FASB ASC 360, Property, Plant, and Equipment (“ASC 360”). ASC 360 requires that our long-lived assets be assessed for potential impairment of their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. Proved oil and natural gas properties are evaluated by geologic basin for potential impairment. In accordance with the successful efforts method of accounting, impairment on proved properties is recognized when the estimated undiscounted projected future net cash flows or evaluation value using expected future prices of a geologic basin are less than its carrying value. If impairment occurs, the carrying value of the impaired geologic basin is reduced to its estimated fair value.

Unproved oil and natural gas properties do not have producing properties and are valued on acquisition by management, with the assistance of an independent expert when necessary. As reserves are proved through the successful completion of exploratory wells, the cost is transferred to proved properties. The cost of the remaining unproved basis is periodically evaluated by management to assess whether the value of a property has diminished. To do this assessment, management considers (i) estimated potential reserves and future net revenues from an independent expert (ii) our history in exploring the area, (iii) our future drilling plans per our capital drilling program prepared by our reservoir engineers and operations management, and (iv) other factors associated with the area. Impairment is taken on the unproved property value if it is determined that the costs are not likely to be recoverable. The valuation is subjective and requires management to make estimates and assumptions that, with the passage of time, may prove to be materially different from actual results.

Revenue from Contracts with Customers

We recognize our revenues following ASC Topic 606, Revenue from Contracts with Customers. Our revenues are primarily derived from our interests in the sale of oil and natural gas production. Oil, natural gas, and NGL sales revenues are generally recognized when control of the product is transferred to the customer, the performance obligations under the terms of the contracts with customers are satisfied, and collectability is reasonably assured. In circumstances where we are the non-operator or mineral right owner, we do not consider ourselves to have control of the product, and revenues are recognized net of production taxes and post-production expenses. The performance obligations for our contracts with customers are satisfied as of a point in time through the delivery of oil and natural gas to our customers. Given the inherent time lag between when oil, natural gas, NGL production, and sales occur and when operators or purchasers often make disbursements to royalty interest owners and due to the large potential fluctuations of both oil production and sale price, a significant portion of our revenue may represent accrued revenue based on estimated net sales volumes and estimated selling prices.

For crude oil and natural gas produced by PhoenixOp, each delivery order is treated as a separate performance obligation. Revenue is recognized when the performance obligation is satisfied, which typically occurs at the point in time control of the product transfers to the customer. Revenue is measured as the amount we expect to receive in exchange for transferring commodities to the customer. Our commodity sales are typically based on prevailing market-based prices. When deliveries contain multiple products, an observable standalone selling price is generally used to measure revenue for each product. Revenues from product sales are presented separately from post-production expenses, including transportation costs, as we control the operated production prior to its transfer to customers.

Recent Accounting Pronouncements

In November 2024, the FASB issued Accounting Standards Update (“ASU”) 2024-03, Income Statement—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses, which requires companies to provide more detailed disclosures about the disaggregation of income statement expenses. The ASU aims to enhance the transparency and usefulness of financial statements by providing better insight into the components of expense line items, and becomes effective for fiscal years beginning after December 15, 2026 and interim periods within fiscal years beginning after December 15, 2027. We are currently evaluating the impact of the standard on our financial statements and disclosures.

Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates or from counterparty or customer credit risk, each as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. These disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our instruments that are sensitive to market risk were entered into for purposes other than speculative trading. Also, gains and losses on these instruments are generally offset by losses and gains on the offsetting expenses.

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to the oil, NGL, and natural gas production of our E&P operators, including PhoenixOp, which affects our revenue from PhoenixOp and the royalty payments we receive from our other E&P operators. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil, NGL, and natural gas has been volatile and unpredictable for several years, and this volatility is expected to continue in the future. The prices that our E&P operators receive for oil, NGL, and natural gas production depend on many factors outside of their and our control, such as the strength of the global economy and global supply and demand for the commodities they produce.

To reduce the impact of fluctuations in oil, NGL, and natural gas prices on our revenues, we periodically enter into commodity derivative contracts with respect to certain of our oil, NGL, and natural gas production through various transactions that limit the risks of fluctuations of future prices. Additionally, we are required to hedge a portion of anticipated oil production pursuant to certain covenants under the Fortress Credit Agreement. As a part of our derivative contracts, as of December 31, 2024, over the next three years, we had nearly 5.5 million Bbl hedged at a weighted average floor of $64.24 per Bbl, which would generate revenues of approximately $350 million over the same period, assuming a price of $0 per Bbl. We plan to continue our practice of entering into such transactions to reduce the impact of commodity price volatility on our cash flow from operations. Future transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars, whereby we receive the excess, if any, of the fixed floor over the floating rate or pay the excess, if any, of the floating rate over the fixed ceiling. These hedging activities are intended to limit our exposure to product price volatility and to maintain stable cash flows.

By using derivative instruments to economically limit exposure to changes in commodity prices, we expose ourselves to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk. See “—Counterparty and Customer Credit Risk” below.

The fair market value of our commodity derivative contracts was a net liability of $7.3 million as of December 31, 2024. Based upon our open commodity derivative positions at December 31, 2024, a hypothetical 10% increase in the NYMEX WTI price would increase our net derivative liability position by $45.8 million, while a 10% decrease in the NYMEX WTI price would decrease our net liability position by $45.8 million.

A $1.00 per Bbl change in our realized oil price would have resulted in a $4.2 million and a $1.4 million change in our oil revenues for the years ended December 31, 2024 and 2023, respectively. A $0.10 per Mcf change in our realized natural gas price would have resulted in a $0.1 million change and a $0.2 million change in our natural gas revenues for the years ended December 31, 2024 and 2023, respectively. A $1.00 per Bbl change in NGL prices would have resulted in a less than $0.1 million change and a $0.2 million change in our NGL revenues for the years ended December 31, 2024 and 2023, respectively. Revenues from oil sales contributed 93.2% and 89.5%,revenues from natural gas sales contributed 2.0% and 5.8%, and revenues from NGL sales contributed 3.9% and 4.7% of our consolidated revenues for the years ended December 31, 2024 and 2023, respectively.

Interest Rate Risk

Our primary exposure to interest rate risk results from outstanding borrowings under our credit facilities, which bear interest at a floating rate. The average annual interest rate incurred when such facility was outstanding on our borrowings under the Fortress Credit Agreement during the year ended December 31, 2024 was 11.83%. Assuming no change in the amount of borrowings under the Fortress Credit Agreement outstanding, a hypothetical 100 basis point increase or decrease in the average interest rate under these borrowings would increase or decrease our interest expense on those borrowings on an annual basis by approximately $2.5 million. See “—Liquidity and Capital Resources—Indebtedness—Fortress Credit Agreement.”

Counterparty and Customer Credit Risk

Our cash and cash equivalents are exposed to concentrations of credit risk. We manage and control this risk by investing these funds in major financial institutions. We often have balances in excess of the federally insured limits.

Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. We evaluate the credit standing of such counterparties as we deem appropriate. We have determined that our counterparties have an acceptable credit risk for the size of derivative position placed; therefore, we do not require collateral or other security from our counterparties. Additionally, we use master netting arrangements to minimize credit risk exposure.

Our principal exposures to credit risk are through receivables generated by the production activities of our operators. For the year ended December 31, 2024, one third-party E&P operator made up 21% our consolidated revenue, as compared to one third-party E&P operators that made up 11% of our consolidated revenue for the year ended December 31, 2023, and Similarly, as of December 31, 2024, we had concentrations in accounts receivable of 17%, 15%, and 13% with three third-party E&P operators, as compared to 26% and 14% with two third-party E&P operator as of December 31, 2023. Although we are exposed to a concentration of credit risk due to our reliance on our operators, we do not believe the loss of any single purchaser would materially impact our operating results as crude oil and natural gas are fungible products with well-established markets and numerous purchasers. If multiple purchasers were to cease making purchases at or around

the same time, we believe there would be challenges initially, but there would be ample markets to handle the disruption. Additionally, recent rulings in bankruptcy cases involving our third-party E&P operators have stipulated that royalty owners must still be paid for oil, gas, and NGL extracted from their mineral acreage during the bankruptcy process. In light of this, we do not expect the entry of one of our operators into bankruptcy proceedings would materially affect our operating results.

Furthermore, as PhoenixOp increases the extent of its operations and generates revenue from the sale of crude oil and natural gas delivered to purchasers, we expect that our concentration of revenue and accounts receivable among a limited number of third-party E&P operators will decrease and we will achieve greater control over the terms of the sales agreements entered into among PhoenixOp and the purchasers.

Item 3. Managers and Officers

Managers, Executive Officers, and Significant Employees

We are a member-managed limited liability company organized under the laws of the State of Delaware, and do not have a board of directors, board of managers, or similar construct (or any committees thereof). We are wholly owned and controlled by Phoenix Equity. LJC has the power to select or remove Phoenix Equity’s managers in its sole discretion pursuant to its limited liability company agreement. No other unitholders of Phoenix Equity are entitled to appoint managers or otherwise directly participate in Phoenix Equity’s management or operations. Pursuant to our organizational documents, any manager of Phoenix Equity will be deemed to be the manager of the Company for all purposes of the Delaware Limited Liability Company Act (the “DLLCA”). As of the date of this Annual Report, Adam Ferrari, our Chief Executive Officer, is the sole manager of Phoenix Equity. Therefore, none of Phoenix Equity’s managers would be considered “independent” under the rules of any national securities exchange or inter-dealer quotation system. As used in this section “we,” “our,” and “us” refer to Phoenix Equity and its subsidiaries.

The following table sets forth certain information about our manager, executive officers, and significant employees as of the date of this Annual Report:

Name	Age	Position	Since
Executive Officers
Adam Ferrari	42	Manager and Chief Executive Officer	November 2023
Curtis Allen	39	Chief Financial Officer	February 2020
Brandon Allen	43	Chief Operating Officer	December 2024
Lindsey Wilson	40	Chief Business Officer	December 2024
Sean Goodnight	50	Chief Acquisition Officer	June 2020
Justin Arn	44	Chief Land and Title Officer	April 2020
David Wheeler	50	Chief Legal Officer	October 2024
Significant Employees
Matthew Willer	48	Managing Director, Capital Markets	March 2021

Set forth below is a brief description of the business experience of our manager and each of our executive officers and significant employees. All of our officers serve at the discretion of LJC.

Adam Ferrari, Manager and Chief Executive Officer. Adam has been Manager and Chief and Executive Officer since November 2023. Adam served as our Vice President of Engineering from April 2023 until November 2023, during which time he was responsible for conducting engineering evaluations across all areas of interest and making purchase recommendations to our executive team. Prior to April 2023, Adam provided us with advisory services since our founding in 2019. Adam began his career with BP America as a completions engineer in 2005. During his tenure with BP America, Adam served in various drilling, completions, and production roles, both in the Gulf of Mexico and in the onshore U.S. business units. Following his experience at BP America, Adam transitioned to an equity analyst role within the Oil and Gas division at Macquarie Capital. After gaining experience on the financial services side of the oil and gas industry, Adam transitioned back to the operating side in a lead Petroleum Engineering role with then-start-up Halcón Resources Corporation (now Battalion Oil Corporation (NYSE: BATL) (“Halcón”)). While at Halcón, Adam supported various exploration and development programs in the broader Gulf Coast region and the Bakken shale asset in North Dakota. Following his tenure at Halcón, Adam pursued entrepreneurial opportunities on the mineral acquisitions side of the oil and gas industry that ultimately led him to us. Immediately prior to providing us advisory services, Adam was the Chief Executive Officer of The Petram Group, LLC (f/k/a Wolfhawk Energy Holdings, LLC doing business as d/b/a “Ferrari Energy”) (“The Petram Group”) from” December 2016 until March 2019. Prior to his employment at The Petram Group, Mr. Ferrari founded and operated Ferrari Energy, LLC, which was active in acquiring and disposing of mineral interests from 2014 to 2017. In early 2016, Wolfhawk Energy Holdings, LLC (later to be renamed The Petram Group, LLC) began operating under the brand name Ferrari Energy, even though there was no formal connection between Ferrari Energy, LLC and Wolfhawk Energy Holdings, LLC. Currently, Ferrari Energy, LLC has no employees, holds only one remaining mineral property, and is otherwise inactive. Adam graduated magna cum laude from the University of Illinois at Urbana-Champagne with a Bachelor of Science Degree in Chemical Engineering. Adam Ferrari is the spouse of Brynn Ferrari, our Chief Marketing Officer, and the son of Charlene and Daniel Ferrari, who control LJC.

Curtis Allen, Chief Financial Officer. Curtis has been our Chief Financial Officer since February 2020. Curtis is responsible for all accounting and finance functions and mineral underwriting, along with a multitude of day-to-day operational tasks. Curtis has over 15 years’ experience in financial services with an emphasis on investment analysis. Curtis has a range of accounting and financial experience, from a private tax practice to auditing billion-dollar defense contractors with the Department of Defense. Most recently prior to joining our company, Curtis spent over seven years managing investments for personal and corporate clients at LPL Financial. Curtis is a Certified Public Accountant, has held FINRA Series 7 and Series 66 licenses, and has passed the Chartered Financial Analyst Level I exam. Curtis graduated magna cum laude from the State University of New York at Oswego with both his Bachelor of Science and Master of Business Administration concentrated in Accounting.

Brandon Allen, Chief Operating Officer. Brandon has been our Chief Operating Officer since December 2024. Brandon previously served as PhoenixOp’s President from February 2024 and as its Vice President of Reservoir Engineering from March 2023 to February 2024. Brandon is responsible for overseeing all of the operations of the business, including maintaining the reserves for all Phoenix Energy ownership. Brandon has over 19 years of experience in the oil and gas business, spanning multiple basins throughout the United States. He has a range of oil and gas experience, offering expertise in reservoir engineering, SEC reserves estimation and reporting, financial reporting, operations planning, asset development and planning, and acquisition evaluation. Immediately prior to joining PhoenixOp, Brandon founded and served as the Senior Vice President of CarbonPath, Inc., a startup carbon credit business. Brandon received a Bachelor of Science degree in Chemical Engineering and a Bachelor of the Arts degree in Biochemistry from the University of Colorado at Boulder.

Lindsey Wilson, Chief Business Officer. Lindsey has been our Chief Business Officer since December 2024. Prior to that time, Lindsey served as our Chief Operating Officer since she helped to found our company in 2019. Lindsey is responsible for overseeing a wide range of business matters related to our operations and takes great pride in working with all of our departments on setting and achieving aggressive business goals. Lindsey brings to our company years of extensive practical experience leading diverse, multidisciplinary teams in the energy sector. Lindsey entered the oil and gas industry in 2011 working leasing projects in Texas, and this foundational experience was the springboard that ultimately allowed her to transition into more advanced management roles within the mineral and leasehold acquisition space. From 2017 until immediately prior to helping found our company, Lindsey was employed as the Operations Manager of The Petram Group. Lindsey graduated from the University of Texas at Arlington and holds a Bachelor of Business Administration with a concentration in Marketing.

Sean Goodnight, Chief Acquisitions Officer. Sean has been our Chief Acquisitions Officer since June 2020. Sean brings over 25 years of consultative sales experience to our company. Sean leads our acquisitions, securities and sales efforts and has implemented processes, developed tools, and introduced materials that have contributed to the continued success of our company. He has built a team of talented, sophisticated professionals who possess the expertise and skillset to maintain the high standards that have become the foundation of his department. Sean spent the early part of his career in the health care and insurance industries, and was introduced into the oil and gas industry in 2016 working with mineral acquisitions, where he quickly transitioned into management. Prior to joining our company, Mr. Goodnight was employed by The Petram Group as an acquisitions landman from 2016 to 2018.

Justin Arn, Chief Land and Title Officer. Justin has been our Chief Land and Title Officer since April 2020. Justin began his Land career researching mineral and royalty rights for multiple mineral acquisition companies focusing on the DJ Basin in Weld County, Colorado, and Laramie County, Wyoming. He has coordinated and managed title projects, large and small, in Wyoming, Colorado, North Dakota, Montana, and Texas, and performed and managed opportunity and due diligence title work for the purchase of thousands of royalty acres throughout the DJ, Bakken, and Permian basins. Immediately prior to joining our company, Justin was employed as a landman for The Petram Group from 2017 to 2020. Justin is an active member of the American Association of Professional Landmen and the Wyoming Association of Professional Landmen.

David Wheeler, Chief Legal Officer. David has been our Chief Legal Officer since October 2024 and is based out of our Irvine, California office. David is responsible for overseeing our day-to-day legal needs and providing advice and guidance to the management team on legal matters, including with respect to capital markets and securities laws and compliance, corporate structuring and governance, litigation management and contract negotiation and drafting. David comes to us with over 20 years of legal experience as a corporate lawyer, serving most recently for over four years as the Chief Legal Officer of a private equity sponsored company with global operations operating in a regulated industry. Prior to that, David spent almost 13 years at Latham & Watkins LLP in their corporate department, advising both public and private clients on a wide variety of corporate law matters, including mergers and acquisitions, corporate governance, capital markets transactions, public company representation, and other general corporate and transactional matters. David graduated from The University of Southern California Gould School of Law with a Juris Doctorate and from Brigham Young University with a Bachelor of Science Degree in Business Management. David is actively licensed to practice law in the State of California.

Matthew Willer, Managing Director, Capital Markets. Matthew has been serving as our Managing Director, Capital Markets, since March 2021. Matthew is responsible for investor relations and outreach and coordinating our investor presentations across our multiple debt offerings. Matthew is also the President and Director of M.D. Willer & Co., a boutique capital markets firm specializing in the needs of small-cap issuers, a position he has held since January 2002. Previously, Matthew co-founded Assure Holdings Corp., where he served as its President and Director from March 2016 to March 2018. Matthew received his Bachelor of Science in Finance and Management from the University of Southern California’s Marshall School of Business, with an emphasis on Finance and Management.

Compensation of Managers and Executive Officers

This compensation discussion and analysis discusses the material components and principles underlying the executive compensation program for our executive officers who are named in the Summary Compensation Table (as defined below). In 2024, our “named executive officers” and their positions were as follows:

• Adam Ferrari, Chief Executive Officer;

• Curtis Allen, Chief Financial Officer;

• Sean Goodnight, Chief Acquisitions Officer;

• Brandon Allen, Chief Operating Officer; and

• Lindsey Wilson, Chief Business Officer.

Where relevant, the discussion below also reflects certain contemplated changes to our compensation structure that occurred after our 2024 fiscal year. Actual compensation programs that we adopt following the completion of the Registered Offering may differ materially from the currently planned programs summarized in this discussion but, absent a requirement to update our offering materials, we will not update this discussion to reflect any changes to the currently planned programs.

Details of Our Compensation Program

Executive Compensation Philosophy and Objectives

Our compensation programs are designed to help achieve the goals of attracting, incentivizing, and retaining highly talented individuals who are committed to our company, while balancing the long-term interests of our members, investors, and customers. The principles and objectives of our compensation and benefits program for our named executive officers are to:

• attract, retain, and motivate individuals who are capable of advancing our financial goals and, ultimately, creating and maintaining our long-term equity value;

• reward executives in a manner aligned with our financial performance to drive pay for performance; and

• provide a total compensation opportunity that is competitive with our market and the industry within which we seek executive talent.

Other than Mr. Ferrari, each of our named executive officers is a member in Phoenix Equity and may become entitled to future distributions with respect to their membership interests under the Second Amended and Restated Limited Liability Company Agreement of Phoenix Equity, dated December 4, 2024 (as the same may be amended or supplemented from time to time, the “Phoenix Equity Operating Agreement”). Under the terms of the Phoenix Equity Operating Agreement, any payments of wages, consulting fees, commissions, or other cash compensation for services rendered and the out-of-pocket costs incurred by us for any health, welfare, retirement, fringe, or other similar benefits provided to our members, including our executive officers, are deemed to be a draw against and will reduce future distributions to the member with respect to such member’s membership interest in Phoenix Equity. Accordingly, base salary, variable revenue-based compensation, bonuses, and commission payment amounts are agreed upon from time to time by our named executive officers and our company and are subject to change, in each case, as determined by our chief executive officer in consultation with or, with respect to Mr. Ferrari, the approval of, LJC.

Compensation Governance and Best Practices

We are committed to having strong governance standards with respect to our compensation programs, procedures, and practices. Our key compensation practices include the following:

• Pay for performance. Other than with respect to Mr. Ferrari, any compensation paid to our named executive officers, either in terms of base salary, variable revenue-based compensation, bonuses, or commission payments, will ultimately reduce the future distributions payable to such named executive officer with respect to his or her membership interest in Phoenix Equity. This is intended to align their interests with investors. Mr. Ferrari’s variable revenue-based compensation is determined by LJC and directly tied to the performance of our company and its annual revenues in order to align Mr. Ferrari’s interests with our members and investors.

• No guaranteed annual salary increases. Other than with respect to Mr. Ferrari, our named executive officers’ salaries are based on individual evaluations and agreed to from time to time by our named executive officers and our chief executive officer with the input of certain other named executive officers and LJC. Mr. Ferrari’s compensation is determined by LJC and Mr. Ferrari as agreed upon from time to time based on the performance of our company.

• No pledging. We prohibit our members, including our named executive officers, from pledging any membership interests in Phoenix Equity, except with the prior consent of LJC or as otherwise permitted by the Phoenix Equity Operating Agreement.

Determination of Compensation and Role of Executive Officers in Determining Executive Compensation

Our chief executive officer consults with LJC and certain of our named executive officers to make compensation decisions with respect to our named executive officers.

Ultimately, our chief executive officer, together with LJC, made 2024 compensation decisions for each of our named executive officers (other than Mr. Ferrari) based on their collective experience and knowledge of the compensation practices in our industry and that of similar companies within our industry. As described above, because any compensation payable to our named executive officers (other than Mr. Ferrari) ultimately reduces each named executive officer’s future distributions payable with respect to his or her membership interest in Phoenix Equity, our named executive officers (other than Mr. Ferrari) agree to their annual compensation packages. Mr. Ferrari’s 2024 compensation was determined by LJC with input from certain of the named executive officers based on our company’s projected performance and an analysis of compensation practices within our industry.

We expect that going forward our chief executive officer, in consultation with LJC, will continue to make future compensation decisions with respect to our named executive officers other than himself. We expect that LJC will continue to make future compensation decisions with respect to Mr. Ferrari, as the chief executive officer. We do not currently have any plans to form a compensation committee or otherwise obtain third-party guidance regarding our compensation program.

Elements of Our Executive Compensation Program

We design the principal components of our executive compensation program to fulfill one or more of the principles and objectives described above. Compensation of any named executive officers consist of the following elements:

• base compensation, either in the form of guaranteed salary or variable revenue-based compensation;

• bonuses;

• commissions;

• equity compensation; and

• health and welfare benefits and certain perquisites and other benefits generally offered to all employees of our company.

Our compensation program is designed to be flexible and complementary and to collectively serve all of the executives’ compensation objectives described above. Therefore, we do not currently have, and we do not expect to have, formal policies relating to the allocation of total compensation among the various elements of our compensation program.

Each of our named executive officers, other than Mr. Ferrari, is a member in Phoenix Equity and may become entitled to future distributions with respect to their membership interests under the Phoenix Equity Operating Agreement. Under the terms of the Phoenix Equity Operating Agreement, any payments of wages, consulting fees, bonuses, commissions, or other cash compensation for services rendered and the out-of-pocket costs incurred by us for any health, welfare, retirement, fringe, or other similar benefits provided to our members, including our named executive officers, are deemed to be a draw against and will reduce future distributions to the named executive officer with respect to such named executive officer’s membership interest in Phoenix Equity. Accordingly, base compensation, variable revenue-based compensation, bonuses, and commission payment amounts are agreed upon from time to time by our named executive officers and our chief executive officer, in consultation with or, with respect to Mr. Ferrari, the approval of, LJC, and are subject to change. We continue to evaluate the mix of base compensation, bonuses, commissions, and equity-based compensation to appropriately align the interests of our named executive officers with those of our members and investors.

Base Compensation

Certain of our named executive officers receive a base salary determined by our chief executive officer in consultation with LJC and certain other executive officers. Base salary is a visible and stable fixed component of our compensation program. Base salaries for our named executive officers

were initially established at the time each executive was hired and may be adjusted from time to time as determined by our chief executive officer based on our company’s performance, market conditions, and individual performance and to be competitive within our market and industry.

Messrs. Ferrari and Curtis Allen and Ms. Wilson are entitled to receive a variable revenue-based compensation tied to revenue targets of the company set by LJC, in lieu of a base salary. The increase in the compensation for Messrs. Ferrari and Curtis Allen for 2024 was determined by LJC based on the company’s significant growth year over year and projected continued growth and overall performance and based on an analysis of the compensation of executive officers of similarly sized companies within our industry. During 2024, Messrs. Ferrari and Curtis Allen and Ms. Wilson

were entitled to 1.10%, 0.55%, and 0.14% of our company’s gross revenue, respectively. Payments were made twice monthly throughout 2024 and were trued-up on December 15, 2024, using annual gross revenue estimates prepared from the books and records of our company as of such date.

The following table sets forth the base salaries of our named executive officers for 2024:

Named Executive Officer	Fiscal 2024 Annual Base Compensation
Adam Ferrari	$	3,135,000	(1)
Curtis Allen	$	1,567,500	(1)
Sean Goodnight	$	455,000	(2)
Brandon Allen	$	300,000	(2)
Lindsey Wilson	$	399,000	(1)

(1) Represents equity draw based on a percentage of company revenue, as described above.

(2) Represents annual base salary.

Bonuses

Our chief executive officer, in consultation with LJC, determined that each of Messrs. Goodnight and Brandon Allen should be eligible to earn discretionary bonuses as part of each such named executive officer’s 2024 compensation package based on each such named executive officer’s individual performance and the performance of our company.

Mr. Goodnight’s bonus earned for 2024 was $205,000 and will be payable in March 2025. Mr. Goodnight received a discretionary additional bonus in the amount of $95,000 in December 2024. Mr. Brandon Allen’s bonus earned for 2024 was $225,000 and will be payable in March 2025.

While Ms. Wilson is not expressly entitled to a bonus as part of her 2024 compensation package, our chief executive officer may determine in his discretion to grant her a bonus based on her individual performance and the performance of our company. During 2024, Ms. Wilson received aggregate bonus payments in the amount of $32,000.

Commissions

During 2024, Mr. Goodnight was eligible to receive sales commissions based on a percentage of the adjusted purchase price of mineral interests and interests in oil and gas properties that he is directly responsible for our company acquiring in connection with our operations. Pursuant to the terms of the Commission Agreement by and between Mr. Goodnight and us, effective as of January 16, 2024 (the “Goodnight Commission Agreement”),

Mr. Goodnight was eligible to earn a commission of 3.5% for closed mineral deals and 3% for closed lease deals during 2024. No such commissions were earned during 2024.

Equity Compensation

We view equity-based compensation as a critical component of our total compensation program. Equity-based compensation creates an ownership culture among our employees that provides an incentive to contribute to the continued growth and development of our business and aligns interests of executives with those of our members and investors. We do not currently have any formal policy for determining the number of equity-based awards to grant to named executive officers, but all named executive officers, along with all employees of our company, are eligible for awards under our 2024 Long-Term Incentive Plan.

Each of Mr. Curtis Allen, Mr. Goodnight, and Ms. Wilson was previously granted equity compensation in the form of profits interests in our company, which were exchanged for profits interests in Phoenix Equity effective as of October 18, 2024. The profits interests were designed to align the interests of our named executive officers with the interests of other members of Phoenix Equity and its affiliates and represented interests in the future profits in Phoenix Equity. The profits interests were fully vested at grant, subject to certain repurchase rights in the event of the death or incapacity of the profits interest holder.

On December 4, 2024, except as otherwise described for Mr. Curtis Allen and Ms. Wilson, the profits interests in Phoenix Equity held by our named executive officers (along with all other profits interests in Phoenix Equity) were cancelled in exchange for restricted units in Phoenix Equity. With respect to each of Mr. Curtis Allen and Ms. Wilson, on December 4, 2024, 50% of the vested profits interests in Phoenix Equity held by each of Mr. Curtis Allen and Ms. Wilson was cancelled in exchange for restricted units in Phoenix Equity, and 50% of the vested profits interests held by such named executive officers was cancelled in exchange for vested units in Phoenix Equity (the “retained units”). In addition, at the same time, Mr. Brandon Allen was issued restricted units in Phoenix Equity.

The restricted units issued to each of our named executive officers are Class A Units and Class B Units in Phoenix Equity subject to restrictions on transferability as set forth in the Phoenix Equity Operating Agreement. In addition, as set forth in the applicable award agreement evidencing the issuance of the restricted units, the restricted units are subject to forfeiture in the event that such named executive officer ceases to be employed with Phoenix Equity and its subsidiaries prior to a change in control of Phoenix Equity. The restricted units are also subject to our repurchase rights under the Phoenix Equity Operating Agreement in the event of the named executive officer’s termination of employment for any reason other than upon a “Liquidity Event” (as defined in the Phoenix Equity Operating Agreement), except as set forth in an agreement between us and the named executive officer.

The retained units issued to Mr. Curtis Allen and Ms. Wilson in exchange for 50% of each such named executive officer’s vested profits interests in Phoenix Equity are fully vested Class A Units and Class B Units in Phoenix Equity that are not subject to forfeiture upon a termination of the named executive officer’s employment. In addition, as set forth in the applicable award agreement evidencing the issuance of the retained units, the retained units are not subject to repurchase by Phoenix Equity, and Phoenix Equity has also agreed that neither Mr. Curtis Allen nor Ms. Wilson will be subject to expulsion as a member of Phoenix Equity.

In connection with the conversion described above and the issuance of restricted units to certain other employees, our named executive officers were issued the following number of Class A Units and Class B Units:

Name	Restricted Class A Units		Vested Class A Units		Restricted Class B Units		Vested Class B Units
Adam Ferrari		—		—		—		—
Curtis Allen		262,505		262,505		96,245		96,245
Sean Goodnight		53,570		—		210,930		—
Brandon Allen		53,570		—		176,930		—
Lindsey Wilson		26,785		26,785		153,215		153,215

In addition to the Class A Units and Class B Units granted to Ms. Wilson, Ms. Wilson was also entitled to receive a cash payment equal to $1,185,300 in lieu of any additional Class A Units or Class B Units she would otherwise have been entitled to as part of the conversion of her profits interests in Phoenix Equity to units in Phoenix Equity. Ms. Wilson received $150,000 of this amount in December 2024 with the remaining portion expected to be paid in 2025.

Retirement Savings and Health and Welfare Benefits

We currently maintain a 401(k) retirement savings plan for our employees, including our named executive officers, who satisfy certain eligibility requirements. Our named executive officers are eligible to participate in the 401(k) plan on the same terms as apply to our other employees generally. The U.S. Internal Revenue Code of 1986, as amended, allows eligible participants to defer a portion of their compensation, within prescribed limits, through elective contributions to the 401(k) plan. During the year ended December 31, 2024, we made company contributions to the 401(k) plan equal to 100% of elective contributions made by participants in the 401(k) plan, up to 3% of a participant’s eligible compensation.

All of our full-time employees, including our named executive officers, are eligible to participate in our health and welfare plans, including medical, dental, and vision benefits.

Perquisites and Other Personal Benefits

Each of Mr. Ferrari, Mr. Curtis Allen, Mr. Goodnight, and Ms. Wilson received an automobile allowance from January 1, 2024 until March 31, 2024. We ceased to provide this automobile allowance to any of our named executive officers beginning in April 2024.

Other than the automobile allowance provided to certain of our named executive officers, we did not provide any perquisites or special personal benefits to our named executive officers during 2024, but our chief executive officer may from time to time approve them in the future when it is determined that such perquisites are necessary or advisable to fairly compensate or incentivize our employees.

Employment Arrangements

In November 2023, we entered into an employment letter agreement with Mr. Ferrari that provides that he will be paid approximately $29,167 per month and be eligible to receive company benefits. We entered into a revised employee agreement with Mr. Ferrari, effective January 1, 2024, that provides that he will receive variable compensation based on a percentage of our revenues, contingent upon our achievement of revenue targets set by LJC, and that he is eligible to participate in our employee benefit plans. See “—Elements of Our Executive Compensation Program—Base Compensation” above for more information regarding Mr. Ferrari’s variable compensation.

We entered into an employee agreement with each of Mr. Curtis Allen and Ms. Wilson, effective January 1, 2024, that provides that each such named executive officer will receive variable compensation based on a percentage of our revenues, contingent upon our achievement of revenue targets set by LJC, and that they are eligible to participate in our employee benefit plans. See “—Elements of Our Executive Compensation Program—Base Compensation” above for more information regarding Mr. Curtis Allen’s and Ms. Wilson’s variable compensation.

We entered into an offer letter with Mr. Goodnight in June 2020 in connection with his commencement of employment with our company. Mr. Goodnight’s offer letter provides that his compensation package will be composed entirely of commission payments. In January 2024 we entered into the Goodnight Commission Agreement outlining the terms of Mr. Goodnight’s commission payments, as described above under “—Elements of Our Executive Compensation Program—Commissions.”

We also entered into an offer letter with Mr. Brandon Allen in March 2023 in connection with his commencement of employment with our company. Mr. Brandon Allen’s offer letter sets forth the terms of his initial compensation package, including annual base salary, ability to receive additional discretionary bonuses based on our company’s performance, and eligibility to participate in our employee benefit plans.

Each of Messrs. Goodnight’s and Brandon Allen’s compensation arrangements have been adjusted from time to time as determined by our chief executive officer and agreed to by each such named executive officer, based on our company’s performance, market conditions, and individual performance and as needed to remain competitive within our market and industry. For 2024, the compensation arrangements for each of Messrs. Goodnight and Brandon Allen were not subject to a written agreement, but included base salaries as described above under “—Elements of Our Executive Compensation Program—Base Compensation” and discretionary bonuses as described above under “—Elements of Our Executive Compensation Program—Bonuses.”

Tax Considerations

As a general matter, our chief executive officer, in consultation with certain other executive officers and outside advisors, reviews and considers the various tax and accounting implications of compensation programs we utilize.

Compensation Policies

We do not currently maintain any formal compensation policies due to our governance structure and the nature in which compensation is mutually determined by our named executive officers and our chief executive officer in consultation with LJC.

Material Compensation Decisions Following December 31, 2024

We entered into an employee agreement with each of Mr. Ferrari, Mr. Curtis Allen, and Ms. Wilson, effective January 1, 2025, that provides that each such named executive officer will continue to receive variable compensation based on a percentage of our revenue, contingent upon our achievement of revenue targets set by LJC, and continue to be eligible to participate in our

employee benefit plans. No changes were made to the percentage of gross revenue to which each of Messrs. Ferrari and Curtis Allen is entitled in 2025 as compared to 2024, but the percentage of revenue to which Ms. Wilson is entitled in 2025 was reduced from 0.14% to 0.10% of our company’s revenue. Subject to the advance to Mr. Ferrari described below, payments will continue to be made twice a month throughout 2025 and will be trued up on December 15, 2025, using annual revenue estimates prepared from the books and records of our company as of such date.

The employment agreement with Mr. Ferrari provides that our company will advance Mr. Ferrari $3,000,000 of the total variable compensation prior to the end of January 2025 with the remaining portion of such variable compensation payable twice a month through December 31, 2025.

In addition, in January 2025, we entered an amendment to Mr. Brandon Allen’s offer letter eliminating his ability to receive annual bonuses beginning in 2025 and providing that, effective for our 2025 fiscal year and future years, any salary changes and discretionary bonuses would be payable in the sole discretion of LJC. Mr. Brandon Allen’s base salary for 2025 was increased to $575,000. Such amounts were determined by the chief executive officer in consultation with LJC and certain other of our executive officers and were agreed to by Mr. Brandon Allen.

In January 2025, we also increased Mr. Goodnight’s base salary to $460,000, as determined by the chief executive officer in consultation with LJC and certain other of our executive officers.

For our 2025 fiscal year, our company has increased the maximum company contributions to the 401(k) plan to an amount equal to up to 4% of the amount eligible participants invest in the 401(k) plan. All named executive officers remain eligible to participate on the same terms as all other employees of our company.

Executive Compensation

2024 Summary Compensation Table

The following table (the “Summary Compensation Table”) sets forth information concerning the compensation of our named executive officers for the year ended December 31, 2024:

Name and Principal Position	Year		Salary ($)(1)		Bonus ($)(2)		Stock Awards ($)(3)			All Other Compensation ($)(4)		Total ($)
Adam Ferrari		2024		3,135,000		—		—			19,571		3,154,571
Chief Executive Officer		2023		408,334		—		—			48,395		456,729
Curtis Allen		2024		1,567,500		—		—	(5)		12,611		1,580,111
Chief Financial Officer		2023		360,355		—					29,337		389,692
Sean Goodnight		2024		455,000		300,000		—	(5)		6,218		761,218
Chief Acquisitions Officer		2023		483,402		—		—			19,447		502,849
Brandon Allen Chief Operating Officer		2024		300,000		225,000		—			9,583		534,583
Lindsey Wilson Chief Business Officer		2024		399,000		32,000		—	(5)		16,189		447,189

(1) For 2024, the amount shown for Messrs. Ferrari and Curtis Allen and Ms. Wilson represents variable revenue-based compensation. Under the Phoenix Equity Operating Agreement, all such compensatory payments made to or for the benefit of the named executive officers that are also members of Phoenix Equity are deemed to be a draw against and will reduce future distributions to such executive with respect to the executive’s membership interest in Phoenix Equity.

(2) The amounts included for 2024 represent the amount of discretionary annual bonuses paid to each of Messrs. Goodnight and Brandon Allen and Ms. Wilson for services rendered during 2024. Under the Phoenix Equity Operating Agreement, all such bonuses are deemed to be a draw against and will reduce future distributions to each such named executive officer with respect to the named executive officer’s membership interest in Phoenix Equity.

(3) The amounts included for 2024 represent the grant date fair value of the restricted Class A Units and restricted Class B Units in Phoenix Equity issued to each of our named executive officers, other than Mr. Ferrari, which will remain unvested until the date of a change in control of Phoenix Equity. The occurrence of a change in control of Phoenix Equity was deemed improbable such that no compensatory value has been assigned to such units under ASC Topic 718. Assuming a change in control of Phoenix Equity was probable, the grant date fair value of all restricted Class A Units granted to Messrs. Curtis Allen, Goodnight, and Brandon Allen and Ms. Wilson is $14,632,029, $2,985,992, $2,985,992, and $1,492,996, respectively, and the grant date fair value of all restricted Class B Units granted to each of Messrs. Curtis Allen, Goodnight, and Brandon Allen and Ms. Wilson is $5,364,697, $11,757,238, $9,862,078, and $8,540,204, respectively. See “—Elements of Our Executive Compensation Program—Equity Compensation” and “—Grants of Plan-Based Awards in 2024” for more information.

(4) Amounts included for 2024 for each of Messrs. Ferrari and Goodnight and Ms. Wilson reflect the total cost to us of a company-provided automobile allowance for each such named executive officer. The amount included for 2024 for Mr. Curtis Allen reflects $12,611, the cost of a company-provided automobile allowance for such named executive officer, and company matching 401(k) plan contributions of $2,683. Amounts included for 2024 for Mr. Brandon Allen reflect company matching 401(k) plan contributions. We ceased to provide the named executive officers with a company-provided automobile allowance in April 2024.

(5) Mr. Curtis Allen, Mr. Goodnight, and Ms. Wilson was previously granted profits interests in our company, which were exchanged for profits interests in Phoenix Equity effective as of October 18, 2024. On December 4, 2024, 50% of the profits interests in Phoenix Equity held by each of Mr. Curtis Allen and Ms. Wilson and 100% of the profits interests in Phoenix Equity held by Mr. Goodnight were converted into restricted Class A Units and Class B Units in Phoenix Equity. See “—Elements of Our Executive Compensation Program—Equity Compensation” and “—Grants of Plan-Based Awards in 2024” for more information.

Grants of Plan-Based Awards in 2024

The following table provides supplemental information relating to grants of plan-based awards made during 2024 to help explain information provided above in our Summary Compensation Table. This table presents information regarding all grants of plan-based awards occurring during 2024.

Name	Grant Date		All Other Stock Awards: Number of Shares of Stock (#)			Grant Date Fair value of Stock Awards ($)(1)
Adam Ferrari		—		—		$	—
Curtis Allen		12/04/2024		262,505	(2)	$	—	(4)
		12/04/2024		96,245	(3)	$	—	(4)
Sean Goodnight		12/04/2024		53,570	(2)	$	—	(4)
		12/04/2024		210,930	(3)	$	—	(4)
Brandon Allen		12/04/2024		53,570	(2)	$	—
		12/04/2024		176,930	(3)	$	—
Lindsey Wilson		12/04/2024		26,785	(2)	$	—	(4)
		12/04/2024		153,215	(3)	$	—	(4)

(1) These amounts represent the grant date fair value of restricted Class A Units and restricted Class B Units in Phoenix Equity issued to the named executive officers that are subject to forfeiture until the date of a change in control of Phoenix Equity, based on the probable outcome of such performance condition. See note 3 to the Summary Compensation Table above for more information.

(2) Represents restricted Class A Units granted to each of our named executive officers other than Mr. Ferrari that are subject to forfeiture upon the named executive officer’s termination of employment for any reason prior to a change in control of Phoenix Equity. Such restricted Class A Units will remain unvested until the date of a change in control of Phoenix Equity.

(3) Represents restricted Class B Units granted to each of our named executive officers other than Mr. Ferrari that are subject to forfeiture upon the named executive officer’s termination of employment for any reason prior to a change in control of Phoenix Equity. Such restricted Class B Units will remain unvested until the date of a change in control of Phoenix Equity.

(4) Each of Mr. Curtis Allen, Mr. Goodnight, and Ms. Wilson was previously granted equity compensation in the form of profits interests in our company, which were exchanged for profits interests in Phoenix Equity effective as of October 18, 2024. On December 4, 2024, 50% of the profits interests in Phoenix Equity held by each of Mr. Curtis Allen and Ms. Wilson and 100% of the profits interests in Phoenix Equity held by Mr. Goodnight were converted into restricted Class A Units and Class B Units in Phoenix Equity. See “—Elements of Our Executive Compensation Program—Equity Compensation” and “— 2024 Summary Compensation Table” for more information.

Outstanding Equity Awards at 2024 Fiscal Year-End

The following table sets forth certain information about restricted units granted to our named executive officers outstanding as of December 31, 2024:

	Stock Awards
Name	Number of Shares or Units of Stock that Have Not Vested (#)			Market Value of Shares or Units of Stock that Have Not Vested ($)(1)
Adam Ferrari		—			—
Curtis Allen		262,505	(2)	$	14,632,029
		96,245	(3)	$	5,364,696
Sean Goodnight		53,570	(2)	$	2,985,992
		210,930	(3)	$	11,757,238
Brandon Allen		53,570	(2)	$	2,985,992
		176,930	(3)	$	9,862,078
Lindsey Wilson		26,785	(2)	$	1,492,996
		153,215	(3)	$	8,540,204

(1) Market value based on $55.74, the fair market value of the Class A Units and Class B Units of Phoenix Equity on December 31, 2024, based on an independent third-party valuation we received.

(2) Represents the number of restricted Class A Units held by each of our named executive officers (other than Mr. Ferrari) that are subject to forfeiture upon the named executive officer’s termination of employment for any reason prior to a change in control of Phoenix Equity. As discussed above under the heading “—Elements of Our Executive Compensation Program—Equity Compensation,” the profits interests previously held by each of our named executive officers (other than Mr. Ferrari) were exchanged for profits interests in Phoenix Equity effective as of October 18, 2024, and were subsequently converted into restricted units (and, for Mr. Curtis Allen and Ms. Wilson, retained units) in Phoenix Equity on December 4, 2024. Refer to “—Elements of Our Executive Compensation Program—Equity Compensation” above for additional information.

(3) Represents the number of restricted Class B units held by each of our named executive officers (other than Mr. Ferrari) that are subject to forfeiture upon the named executive officer’s termination of employment for any reason prior to a change in control of Phoenix Equity. As discussed above under the heading “—Elements of Our Executive Compensation Program—Equity Compensation,” the profits interests previously held by each of our named executive officers (other than Mr. Ferrari) were exchanged for profits interests in Phoenix Equity effective as of October 18, 2024, and were subsequently converted into restricted units (and, for Mr. Curtis Allen and Ms. Wilson, retained units) in Phoenix Equity on December 4, 2024. Refer to “—Elements of Our Executive Compensation Program—Equity Compensation” above for additional information.

Potential Payments Upon Termination or Change in Control

None of our named executive officers are entitled to cash severance or benefits upon his or her termination of employment for any reason, provided that our company may determine to pay cash severance or grant severance benefits upon a named executive officer’s termination of employment in the discretion of our chief executive officer and/or LJC. We do not have a written or formal severance plan or policy that applies to any employees of our company, including any of the named executive officers.

Upon a “Liquidity Event” (as defined in the Phoenix Equity Operating Agreement) the forfeiture and repurchase provisions applicable to the restricted Class A Units and restricted Class B Units held by any of our named executive officers will lapse.

For purposes of the restricted Class A Units and restricted Class B Units in Phoenix Equity, a “Liquidity Event” generally means the occurrence of one of the following:

• a sale or disposition, whether in one transaction or a series of transactions, of all or substantially all of the equity securities of Phoenix Equity (including by way of merger, consolidation, share exchange, or similar transaction); or

• a sale or disposition, whether in one transaction or a series of transactions, of all or substantially all of the assets of Phoenix Equity and its subsidiaries.

Assuming a Liquidity Event occurred as of December 31, 2024, the value received by each of our named executive officers in respect of their restricted Class A Units and restricted Class B Units would be:

Name	Value of Class A Units for which Forfeiture Restrictions Cease to Apply upon Liquidity Event (1)		Value of Class B Units for which Forfeiture Restrictions Cease to Apply upon Liquidity Event (1)
Adam Ferrari		—		—
Curtis Allen	$	14,632,029	$	5,364,696
Sean Goodnight	$	2,985,992	$	11,757,238
Brandon Allen	$	2,985,992	$	9,862,078
Lindsey Wilson	$	1,492,996	$	8,540,204

(1) Market value based on $55.74, the fair market value of the Class A Units and Class B Units of Phoenix Equity on December 31, 2024, based on an independent third-party valuation.

Manager Compensation

Our company is managed indirectly by Adam Ferrari, our Chief Executive Officer, who was employed by us during the year ended December 31, 2024, and did not receive any additional compensation from us for his service as a manager of Phoenix Equity or our company.

Item 4. Security Ownership of Management and Certain Security Holders

We are a wholly owned subsidiary of Phoenix Equity. LJC controls Phoenix Equity and, therefore, indirectly has control over our management. The table below sets forth, as of the date of this Annual Report, information regarding the beneficial ownership of Phoenix Equity’s outstanding membership interests by: (1) each person who is known to us to be the beneficial owner of 5% or more of Phoenix Equity’s outstanding membership interests; (2) each of our named executive officers and managers; and (3) all of our executive officers and managers as a group. The SEC has defined “beneficial ownership” of a security to mean the possession, directly or indirectly, of sole or shared voting power and/or investment power over such security, including options and warrants that are currently exercisable or exercisable within 60 days.

Unless otherwise indicated, we believe that all persons named in the table below have sole voting and investment power with respect to the voting securities beneficially owned by them. Unless otherwise noted, the business address of the persons listed in the table below is 18575 Jamboree Road, Suite 830 Irvine, California 92612.

Name of Beneficial Holder	Class A Units(1)		Class A Unit Percentage			Class B Units(2)		Class B Unit Percentage
5% Holders
Lion of Judah Capital, LLC(3)		1,100,000		55.0	%		4,186,100		59.8	%
Managers and Named Executive Officers Adam Ferrari(3)
Adam Ferrari(4)		—		—	%		—		—	%
Curtis Allen		525,010		26.3	%		192,490		2.7	%
Sean Goodnight		53,570		2.7	%		210,930		3.0	%
Brandon Allen		53,570		2.7	%		306,430		4.4	%
Lindsey Wilson		53,570		2.7	%		176,930		2.5	%
All executive officers and managers as a group (seven individuals)		739,290		40.0	%		1,222,210		17.5	%

(1) Class A Units are entitled to vote on any matter involving Phoenix Equity or its subsidiaries.

(2) Class B Units are not entitled to vote on any matter involving Phoenix Equity or its subsidiaries.

(3) Daniel Ferrari and Charlene Ferrari each own 50% of the voting membership interests in, and are the managers of, LJC. Their address is 1983 Water Chase Drive, New Lenox, Illinois 60451. Adam Ferrari, the son of Daniel and Charlene Ferrari, owns 100% of the economic interests in LJC, but has no voting or managerial interest in LJC and, therefore, is not a beneficial owner of our membership interests by virtue of his economic interest ownership in LJC.

(4) Pursuant to the terms of the Phoenix Energy LLCA, because Adam Ferrari is the manager of Phoenix Equity, he is deemed for all purposes of the DLLCA to be the manager of the Company.

Item 5. Interest of Management and Others in Certain Transactions

In addition to the compensation arrangements, including employment, termination of employment, and change in control and indemnification arrangements, discussed in Item 3 in the section titled “Managers and Officers—Compensation of Managers and Executive Officers,” the following is a description of each transaction since January 1, 2022 and each currently proposed transaction in which:

• we or any subsidiaries have been or will be a participant;

• the amount involved exceeded or exceeds $120,000; and

• any of our executive officers, or beneficial owners of more than 5% of our capital stock had or will have a direct or indirect material interest.

Second Amended and Restated Limited Liability Company Agreement of Phoenix Energy One, LLC

We are governed by that certain Second Amended and Restated Limited Liability Company Agreement, dated as of January 23, 2025 (as amended, amended and restated, or supplemented from time to time, the “Phoenix Energy LLCA”), between ourselves and our sole member, Phoenix Equity.

The Phoenix Energy LLCA provides that Phoenix Equity is the sole member of the Company, entitled to 100% of any distributions made by the Company. The management of the Company is exclusively vested in Phoenix Equity and, as such, Phoenix Equity directs our business and operations, including appointment and compensation of our officers. The Phoenix Energy LLCA further provides that the managers of Phoenix Equity shall be deemed to be “managers” of the Company for all purposes under the DLLCA. LJC controls Phoenix Equity and, therefore, indirectly has control over the Company’s management. Daniel Ferrari and Charlene Ferrari each own 50% of the voting membership interests in, and are the managers of, LJC. Adam Ferrari, our Chief Executive Officer, the manager of Phoenix Equity, and the son of Daniel and Charlene Ferrari, owns 100% of the economic interests in LJC, but has no voting or managerial interest in LJC. This summary is qualified in its entirety by the full text of the Phoenix Energy LLCA, which is included as an exhibit to this Annual Report.

Consulting Agreement

We and Adam Ferrari, our Chief Executive Officer, entered into a consulting agreement (the “Consulting Agreement”) in November 2021 pursuant to which Mr. Ferrari provided us with petroleum engineering consulting services. The Consulting Agreement terminated commencing with Mr. Ferrari’s employment as our Vice President of Engineering in April 2023. We paid Mr. Ferrari $323,000 in consulting fees in 2022 pursuant to the Consulting Agreement.

Investments in Company Debt

From time to time certain of our managers or executive officers and their respective family members may purchase and hold our debt securities.

The following table sets forth, for the period from January 1, 2022 to February 28, 2025, investments made by such persons in our debt securities where such investments exceeded $120,000:

Related Party(1)	Debt Security	Interest Rate	Principal Amount During Period(2)		Principal Amount Outstanding as of February 28, 2025		Principal Paid During Period(2)		Interest Paid During Period
Adam Ferrari	July 2022 506(c) Bonds	8.0% - 11.0%	$	455,000	$	—	$	455,000	$	16,433
Adam Ferrari	December 2022 506(c) Bonds	9.0% - 12.0%	$	1,143,000	$	481,000	$	662,000	$	171,094
Adam Ferrari	August 2023 506(c) Bonds	10.0% - 14.0%	$	3,347,000	$	1,784,000	$	1,563,000	$	320,228
Adam Ferrari	Reg A Bonds	9.0%	$	200,000	$	—	$	200,000	$	14,963
Curtis Allen	December 2022 506(c) Bonds	12.0%	$	386,000	$	—	$	386,000	$	28,668
Curtis Allen	August 2023 506(c) Bonds	13.0% - 14.0%	$	3,026,000	$	1,036,000	$	1,990,000	$	181,972
Curtis Allen	Reg A Bonds	9.0%	$	14,000	$	—	$	14,000	$	1,928
Lindsey Wilson	December 2022 506(c) Bonds	9.0%	$	50,000	$	—	$	50,000	$	4,690
Lindsey Wilson	August 2023 506(c) Bonds	13.0%	$	184,000	$	184,000	$	—	$	18,066
Justin Arn	December 2022 506(c) Bonds	10.0%	$	50,000	$	—	$	50,000	$	5,236
Justin Arn	August 2023 506(c) Bonds	13.0%	$	161,000	$	161,000	$	—	$	24,330
Justin Arn	Reg A Bonds	9.0%	$	2,000	$	—	$	2,000	$	540
David Wheeler	August 2023 506(c) Bonds	12.0%	$	179,000	$	179,000	$	—	$	5,424

(1) Includes any debt securities known by such person to be held by any child, stepchild, parent, step-parent, spouse, sibling, mother-in-law, father-in- law, son-in-law, daughter-in-law, brother-in-law, or sister-in-law of such person and any person (other than a tenant or employee) sharing the household of such person.

(2) Reflects the largest aggregate amount of principal of such debt securities outstanding and paid during the period from January 1, 2022 to    February 28, 2025.

Discretionary Payments

For the year ended December 31, 2024, we paid interest expense of less than $0.2 million to a financial institution on behalf of LJC related to a certain financing agreement between LJC and this financial institution. Such payments were discretionary in nature, and we are under no obligation to continue to make such payments on behalf of LJC. For the year ending December 31, 2025, we expect to make additional payments up to an amount equal to approximately $0.1 million.

Item 6. Other Information

None.

Item 7. Financial Statements

PHOENIX ENERGY ONE, LLC

AND SUBSIDIARIES

Consolidated Financial Statements

As of and for the years ended December 31, 2024, 2023, and 2022

INDEX TO FINANCIAL STATEMENTS

Audited Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm	F-3
Consolidated Balance Sheets	F-5
Consolidated Statements of Operations	F-6
Consolidated Statements of Members’ Equity (Deficit)	F-7
Consolidated Statements of Cash Flows	F-8
Notes to the Consolidated Financial Statements	F-9

F-2

18012 Sky Park Circle, Suite 100 Irvine, California 92614 tel 949-852-1600 fax 949-852-1606 www.rjicpas.com

Report of Independent Registered Public Accounting Firm

To the Members of Phoenix Energy One, LLC

Irvine, California

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Phoenix Energy One, LLC and Subsidiaries (the Company) as of December 31, 2024, 2023 and 2022, and the related consolidated statements of operations, changes in equity (deficit) and cash flows for the years then ended, and the related notes to the consolidated financial statements (collectively referred to as the “financial statements”). In our opinion, the 2024, 2023 and 2022 consolidated financial statements present fairly, in all material respects, the financial position of Phoenix Energy One, LLC and Subsidiaries as of December 31, 2024, 2023 and 2022, and the results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

Restatement of 2023 and 2022 Financial Statements

As discussed in Note 3 to the consolidated financial statements, the 2023 and 2022 financial statements have been restated to correct misstatements. The 2022 financial statements of Phoenix Energy One, LLC before the adjustments described in Note 3 were audited by another auditor whose report, dated May 1, 2023, expressed an unqualified opinion on those financial statements. We have audited the 2022 and 2023 financial statements, as restated, as of and for the years ended December 31, 2023 and 2022, including the adjustments described in Note 3 that were applied to restate the 2023 and 2022 financial statements. In our opinion, such adjustments are appropriate and have been properly applied.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Phoenix Energy One, LLC in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Phoenix Energy One, LLC is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

F-3

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the Audit Committee (those charged with governance) of the Board of Directors/Members and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing separate opinions on the critical audit matter or on the accounts and disclosures to which they relate.

Estimation and Valuation of Proven Reserves

The estimation and valuation of proven reserves is identified as a critical audit matter. The valuation of these reserves is highly subjective due to the complexities involved in estimating the reserves, and the significant judgment required in determining the valuation assumptions, such as future commodity prices, production rates, and capital expenditures. The estimation of volumes and future revenues of the Company’s proved reserves could have a significant impact on the measurement of depletion expense or impairment expense.

The following are the primary procedures we performed to address this critical audit matter. We performed the following audit procedures in relation to the evaluation of proved reserves:

1. We sampled additions and disposals of reserve assets during the year to test the accuracy and completeness of the recording processes.

2. We gained an understanding of the Company’s process for estimating reserve quantities and valuing the reserves.

3. We validated the mathematical accuracy, formulas, and inputs used in the depletion reserve calculations to ensure the reserve expense calculation was appropriate for the type of reserves reported.

4. We performed reasonability tests to confirm whether the proved reserve balances for oil and gas properties were within expected ranges, based on historical data.

5. We tested the completeness and accuracy of data for selected wells to verify that the Company’s system was pulling accurate and relevant well data.

6. We reviewed the third-party reserve engineer’s report to assess the reasonableness and appropriateness of the Company’s approach and methodology in calculating their reserve estimates.

7. We assessed the knowledge, skills and expertise of the third-party reserve engineer involved in testing the reasonableness and approach to the reserve estimates.

8. We obtained and evaluated the third-party legal opinion from a title attorney concerning the Company’s ownership percentages of sampled wells, to validate the accuracy of these percentages.

9. We compared the estimated pricing and pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year for the pricing differentials.

10. Assessed the reasonableness of forecasted capital expenditures by comparing drilling forecasts applied in the reserve report to recent drilling costs.

11. Obtained evidence supporting the amount of development of proved undeveloped properties reflected in the reserve report and compared with forecasted drilling plans and budgets.

We have served as the Company’s auditors since 2023.

Irvine, California

March 26, 2025

F-4

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Consolidated Balance Sheets

(in thousands)

	December 31,
	2024			2023 (As Restated)			2022 (As Restated)
ASSETS
Current assets
Cash and cash equivalents	$	120,814		$	5,428		$	4,607
Accounts receivable		28,218			32,822			4,013
Earnest payments		154			25,387			794
Other current assets		7,528			647			376
Total current assets		156,714			64,284			9,790
Oil and gas properties		1,006,221			478,339			165,390
Accumulated depletion and impairment		(140,376	)		(54,671	)		(20,635	)
Net oil and gas properties		865,845			423,668			144,755
Right-of-use assets, net		6,010			4,542			1,798
Other noncurrent assets		501			673			677
Total Assets	$	1,029,070		$	493,167		$	157,020
LIABILITIES AND MEMBER’S EQUITY (DEFICIT)
Current liabilities
Accounts payable	$	41,824		$	47,272		$	19,438
Short-term debt		—			25,819			6,818
Current portion of long-term debt		103,240			87,038			46,039
Current portion of deferred closings		7,189			10,196			5,696
Escrow account		16,356			6,491			701
Current operating lease liabilities		656			567			305
Accrued and other liabilities		57,346			6,388			2,236
Total current liabilities		226,611			183,771			81,233
Long-term debt, net of current portion		795,215			295,167			59,481
Accrued interest		26,079			6,369			291
Deferred closings		3,324			7,884			5,533
Operating lease liabilities		5,860			4,225			1,597
Asset retirement obligations		1,181			585			212
Other noncurrent liabilities		4,858			—			—
Total liabilities		1,063,128			498,001			148,347
Member’s equity (deficit)
Member’s equity		434			4,865			2,183
Retained earnings (accumulated deficit)		(34,492	)		(9,699	)		6,490
Total member’s equity (deficit)		(34,058	)		(4,834	)		8,673
Total Liabilities and Member’s Equity (Deficit)	$	1,029,070		$	493,167		$	157,020

The accompanying notes are an integral part of these consolidated financial statements.

F-5

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Consolidated Statements of Operations

(in thousands)

	Year Ended December 31,
	2024			2023 (As Restated)			2022 (As Restated)
REVENUES
Mineral and royalty revenues	$	152,999		$	118,088		$	54,554
Product sales		125,649			—			—
Water services		2,478			—			—
Other revenues		101			17			—
Total revenues		281,227			118,105			54,554
OPERATING EXPENSES
Cost of sales		63,947			19,733			9,573
Depreciation, depletion, amortization and accretion		85,977			34,228			12,144
Selling, general and administrative		29,167			14,314			5,563
Payroll and payroll-related expenses		27,934			12,733			6,023
Advertising and marketing		679			4,136			1,353
Loss on sale of assets		564			—			—
Impairment expense		564			974			—
Total operating expenses		208,832			86,118			34,656
Income from operations		72,395			31,987			19,898
OTHER INCOME (EXPENSE)
Interest income		705			66			—
Interest expense		(90,210	)		(47,882	)		(11,893	)
Loss on derivatives		(5,986	)		(32	)		(2,239	)
Loss on debt extinguishment		(1,697	)		(328	)		(92	)
Total other expenses		(97,188	)		(48,176	)		(14,224	)
NET INCOME (LOSS)	$	(24,793	)	$	(16,189	)	$	5,674

The accompanying notes are an integral part of these consolidated financial statements.

F-6

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Consolidated Statements of Changes in Equity (Deficit)

(in thousands)

	Member’s Equity			Retained Earnings (Accumulated Deficit)			Total Member’s Equity (Deficit)
Balance, December 31, 2021 (As Restated)	$	2,088		$	816		$	2,904
Contributions		200			—			200
Distributions		(105	)		—			(105	)
Net income (As Restated)		—			5,674			5,674
Balance, December 31, 2022 (As Restated)		2,183			6,490			8,673
Contributions		10,150			—			10,150
Distributions		(7,468	)		—			(7,468	)
Net loss (As Restated)		—			(16,189	)		(16,189	)
Balance, December 31, 2023 (As Restated)		4,865			(9,699	)		(4,834	)
Contributions		325			—			325
Distributions		(4,756	)		—			(4,756	)
Net loss		—			(24,793	)		(24,793	)
Balance, December 31, 2024	$	434		$	(34,492	)	$	(34,058	)

The accompanying notes are an integral part of these consolidated financial statements.

F-7

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(in thousands)

	Year Ended December 31,
	2024			2023 (As Restated)			2022 (As Restated)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(24,793	)	$	(16,189	)	$	5,674
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Depreciation, depletion, amortization, and accretion		85,977			34,228			12,144
Impairment expense		564			974			—
Amortization of right-of-use assets		643			422			104
Amortization of debt discount and debt issuance costs		16,621			13,753			940
Unrealized loss (gain) on derivatives		7,518			32			(46	)
Loss on sale of assets		564			—			—
Loss on debt extinguishment		1,697			328			92
Changes in operating assets and liabilities:
Accounts receivable		4,605			(28,809	)		(2,731	)
Earnest payments		(22,639	)		(24,593	)		(788	)
Accounts payable		(10,967	)		2,832			344
Accrued and other liabilities		13,020			4,058			1,870
Escrow account		9,865			5,790			701
Accrued interest		19,829			6,078			291
Other		(7,265	)		(730	)		47
Net cash (used in) provided by operating activities		95,239			(1,826	)		18,642
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties and leases		(443,820	)		(278,661	)		(91,263	)
Proceeds from sale of assets		6,200			—			—
Additions to equipment and other property		(83	)		—			(625	)
Net cash used in investing activities		(437,703	)		(278,661	)		(91,888	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuances of debt, net of discount		864,003			464,541			80,499
Payments of debt issuance costs		(63,723	)		(43,441	)		(5,351	)
Repayments of debt		(328,167	)		(139,494	)		2,687
Members’ contributions		325			10,150			200
Members’ distributions		(4,756	)		(7,468	)		(105	)
Payments of deferred closings		(9,832	)		(2,980	)		(437	)
Net cash provided by financing activities		457,850			281,308			77,493
Net change in cash and cash equivalents		115,386			821			4,247
Cash and cash equivalents at beginning of year		5,428			4,607			360
Cash and cash equivalents at end of year	$	120,814		$	5,428		$	4,607

The accompanying notes are an integral part of these consolidated financial statements.

F-8

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

Note 1 – Business

Phoenix Energy One, LLC (“Phoenix Energy”), formerly known as Phoenix Capital Group Holdings, LLC (“Phoenix Capital”), is a Delaware limited liability company focused on oil and gas operations primarily in the Williston Basin, North Dakota/Montana, the Uinta Basin, Utah, the Permian Basin, Texas, the Denver-Julesburg Basin, Colorado/Wyoming and the Powder River Basin, Wyoming. The Company was formed in April 2019 and changed its name to Phoenix Energy in January 2025. As used in these consolidated financial statements, unless the context otherwise requires, references to the “Company,” “we,” “us,” and “our” refer to Phoenix Energy and its consolidated subsidiaries.

The Company’s strategy involves the acquisition of royalty assets, acquisition of non-operated working interests and direct drilling operations of operated working interests conducted through its wholly-owned subsidiaries, Phoenix Operating, LLC (“PhoenixOp”) and Firebird Services LLC (“Firebird”). PhoenixOp is a Delaware limited liability company formed in January 2022 to drill, complete and operate wells in the United States. Firebird is a Delaware limited liability company formed in October 2023 to perform saltwater disposal services on wells operated by PhoenixOp.

Phoenix Energy has also formed several financing entities, including Phoenix Capital Group Holdings I, LLC (“PCGH I”) in November 2022 and Adamantium Capital LLC (“Adamantium”) in June 2023, to undertake financing efforts and raise debt capital through unregistered and registered debt offerings to retail investors.

The Company operates as a limited liability company for which Lion of Judah Capital, LLC (“Lion of Judah”) was the majority profit-share owner and exclusive equity contributor until October 2024. In October 2024, as part of a reorganization of the Company, all the then-existing interests of the Company’s profit-share partners, including Lion of Judah who had previously held a 60.18% interest in Phoenix Energy, were exchanged for interests in Phoenix Equity Holdings, LLC (“Phoenix Equity”), a Delaware limited liability company and the sole member of Phoenix Energy following the transaction. Lion of Judah remains the majority equity owner and controlling member of Phoenix Equity.

Note 2 – Significant Accounting Policies

Basis of preparation and principles of consolidation

The accompanying consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). The consolidated financial statements include the accounts of Phoenix Energy and its wholly-owned subsidiaries. All intercompany accounts and transactions with and between Phoenix Energy and its wholly-owned subsidiaries have been eliminated in consolidation. Certain prior period amounts have been reclassified to conform to current period presentation.

Liquidity risk and management’s plans

Liquidity risk is the risk that the Company’s cash flows from operations will not be sufficient for the Company to continue operating and discharge its liabilities in the normal course of operations. The Company is exposed to liquidity risk as its continued operation is dependent upon its ability to continue to obtain financing, either in the form of debt or equity, or by achieving profitable operations in order to satisfy its liabilities as they come due.

As of December 31, 2024, the Company had negative working capital of approximately $69.9 million and a member’s deficit of approximately $34.1 million. The Company expects to repay its financial liabilities in the normal course of operations and to fund future operational and capital requirements through operating cash flows and through issuances of additional debt. As of March 26, 2025, after the balance sheet date, the Company had raised an additional $141.5  million of notes through its investor program (see Note 8 – Debt and Note 18 – Subsequent Events). Management believes its capital raises through its bond offerings will continue at or above this current pace.

F-9

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

The Company may need to conduct asset sales, which is not a planned course of action, and/or issuances of debt and/or equity if liquidity risk increases in any given period. The Company believes it has sufficient funds to meet foreseeable obligations by actively monitoring its credit facilities through use of the loans, asset sales, cost reductions and coordinating payment and revenue cycles.

The Company is required to evaluate whether or not its current financial condition, including its sources of liquidity at the date that the consolidated financial statements are issued, will enable the Company to meet its obligations as they come due within one year of the date of the issuance of these consolidated financial statements and to make a determination as to whether or not it is probable, under the application of this accounting guidance, that the Company will be able to continue as a going concern. In applying applicable accounting guidance, we considered the Company’s current financial condition and liquidity sources, including current funds available, forecasted future cash flows, the Company’s obligations due over the next twelve months as well as the Company’s recurring business operating expenses, and believe to have sufficient financial resources to operate beyond the next twelve months following the date these consolidated financial statements are issued.

Use of estimates

The preparation of the consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the applicable reporting period of such statements. Accordingly, actual results could differ materially from these estimates.

The accompanying consolidated financial statements are based on a number of significant estimates including quantities of oil, natural gas and natural gas liquids (“NGL”) reserves that are the basis for the calculations of depreciation, depletion, amortization, and determinations of impairment of oil and natural gas properties. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas and there are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment along with estimated selling prices. As a result, reserve estimates may materially differ from the quantities of oil and natural gas that are ultimately recovered.

Segment information

The Company’s Chief Executive Officer, who is our Chief Operating Decision Maker (the “CODM”), previously reviewed the Company’s operating results on a consolidated basis and managed our operations as a single operating segment: Phoenix Capital. The objective of Phoenix Capital was to acquire mineral interests and non-operated working interests in oil and gas properties and once acquired, to share in the proceeds of the natural resources extracted and sold by the operator. The Company’s financing activities and capital raise programs were also conducted under the Phoenix Capital segment.

In 2023, the Company began operating as two segments: Phoenix Capital and a new segment, PhoenixOp, which was formed to drill, extract and operate producing wells. The Company’s performance was evaluated based on the operating profit of the respective segments.

During the first quarter of 2024, the Company’s activities associated with its debt securities offerings met the criteria specified in Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 280 Segments to be classified as an operating segment, resulting in a change to the composition of the Company’s reportable segments. The segment previously described as “Phoenix Capital” was split into two components: Mineral and Non-operating and Securities, and the segment previously described as “PhoenixOp” was renamed to the Operating segment. The Company began reporting these three segments during the first quarter of 2024 to align with the manner in which the CODM manages the business and allocates resources within the Company. The Company acquires mineral interests and non-operated working interests in oil and gas properties under the Mineral and Non-operating segment; drills, extracts and operates wells under the Operating segment; and conducts activities associated with its debt securities offerings under the Securities segment. All of the Company’s operations are conducted in the United States.

F-10

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

Segment financial information as of and for the years ended December 31, 2023 and 2022 have been recast to reflect this change (See Note 17 – Segments).

Cash and cash equivalents

The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. The Company maintains its cash and cash equivalents at financial institutions. The balances may exceed the Federal Deposit Insurance Corporation (“FDIC”) insurance coverage and, as a result, there may be a concentration of credit risk related to amounts on deposit in excess of FDIC insurance coverage.

Asset retirement obligations

The fair value of a liability for an asset’s retirement obligations is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made, and the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. Over time, the liability is accreted for the change in its present value and the capitalized cost is depreciated over the useful life of the related asset. Asset retirement obligations (“ARO”) are periodically adjusted to reflect changes in the estimated present value of the obligation resulting from revisions to the estimated timing or amount of the expected future cash flows. Upon settlement of the obligation, the Company eliminates the liability and, based on the actual cost to retire, may incur a gain or loss.

Escrow account

Proceeds from investors who intend to purchase the Company’s bonds but have not yet closed the transaction are classified as escrow account on the consolidated balance sheets. Amounts are reclassified to debt upon the execution of the subscription agreement and, where applicable, the satisfactory verification of the bondholder’s accreditation.

Accounts receivable

Accounts receivable consists of uncollateralized mineral and royalty income due from third party operators for oil and gas sales to purchasers and receipts from the Company’s mineral and non-operated working interest ownership. It also consists of receivables from crude oil, natural gas and NGL purchasers and joint interest owners on properties operated by PhoenixOp.

In circumstances where the receivables relate to the Company’s mineral and non-operated working interests, purchasers remit payment for production to the operator and the operator, in turn, remits payment to Phoenix Energy for the agreed-to royalties. Receivables are estimated in circumstances where the Company has not received actual information, either due to timing delays or due to the unavailability of data at the time when revenues are recognized. Volume estimates for wells with available historical actual data are based on (i) the historical actual data for months where the data is available or (ii) engineering estimates for months where the historical actual data is not available. Pricing estimates are based upon actual prices realized in an area by adjusting the market price for the average basis differential from market on a basin-by-basin basis.

For receivables from joint interest owners on properties operated by PhoenixOp, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, receivables due to PhoenixOp are collected within two months.

The Company routinely reviews outstanding balances, assesses the financial strength of its customers, and if applicable, would record a reserve for credit losses for amounts not expected to be fully recovered. There was no credit loss reserve as of December 31, 2024, 2023, and 2022.

F-11

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

Credit risk

Financial instruments that potentially subject the Company to concentrations of credit risk consist of cash and cash equivalents, accounts receivable, revenues and derivative instruments. Revenues are concentrated among operators and purchasers engaged in the energy industry within the United States. By using derivative instruments to economically limit exposure to changes in commodity prices, the Company exposes itself to credit risk and market risk. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties have been determined to have an acceptable credit risk for the size of derivative position placed; therefore, the Company does not require collateral from its counterparties. Management periodically assesses the financial condition of these entities and institutions and considers any possible credit risk to be minimal.

Joint interest

The majority of the Company’s oil and gas exploration, development, and production activities are conducted jointly with other entities and, accordingly, the consolidated financial statements reflect only the Company’s proportionate interest in such activities.

Earnest payments

Earnest payments are deposits paid to oil and gas property owners upon the execution of a purchase and sale agreement or a lease agreement for the acquisition of their interests. These deposits are generally refundable and reclassified to oil and gas properties on the consolidated balance sheets upon successful completion of title review and closing of the transaction, or expensed in the event the transaction is not consummated. Earnest payments expensed for the year ended December 31, 2024 was less than $0.1 million and no earnest payments were expensed for the years ended December 31, 2023 and 2022.

Oil and gas properties

The Company invests in crude oil and natural gas properties, including mineral interests and working interests as a non-operator and operator. Exploration and production activities are accounted for in accordance with the successful-efforts method of accounting. Under this method, costs of acquiring proved mineral interests in crude oil and natural gas properties, development wells, related plant and equipment, and related ARO assets are capitalized. Costs of proved but undeveloped wells are initially capitalized to wells-in-progress until the well becomes productive. Once the well is productive, accumulated capitalized costs are reclassified as proved and producing properties and accounted for following the successful efforts method of accounting. Costs are also capitalized for unevaluated wells that have found crude oil and natural gas reserves even if the reserves cannot be classified as proved when the drilling is completed, provided the unevaluated well has found a sufficient quality of reserves to justify its completion as an economically and operationally viable producing well. If proved reserves are not found, unevaluated well costs are expensed as dry holes. All other unevaluated wells and costs, and all general and administrative costs unrelated to acquisitions are expensed as incurred.

Depletion of capitalized costs is recorded using the units-of-production method based on proved reserves. The depletion rate is determined by dividing the cumulative recovered barrels of oil equivalent by the estimated ultimate recovery by well and averaged amongst all wells within the pooled unit. This rate is multiplied by the original cost basis and reduced by depletion taken in prior periods. The cost basis remaining represents the percentage of the asset remaining to be recovered by the wells within the pooled unit.

Capitalized interest

The Company capitalizes interest on expenditures made in connection with exploration and development projects that are not yet subject to depletion. The amount capitalized is determined by multiplying the weighted-average cost of borrowings by the average amount of eligible accumulated capital expenditures and is limited to actual interest costs incurred during the period. Interest is capitalized only for the period that activities are in process to bring the projects to their intended use. The Company capitalized interest costs of $11.8 million and $2.1 million

F-12

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

for the years ended December 31, 2024 and December 31, 2023, respectively. No interest cost was capitalized for the year ended December 31, 2022. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depletion.

Equipment and other property

Equipment and other property are stated at cost. Depreciation is calculated using the straight-line method over the estimated useful lives (ranging from 3 to 7 years) of the respective assets. The costs of normal maintenance and repairs are charged to expense as incurred. Material expenditures that increase the life of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. The cost of equipment and other property sold or otherwise disposed of, and the related accumulated depreciation, are removed from the consolidated balance sheet and any gain or loss is reflected in current earnings. These amounts are included in other noncurrent assets on the consolidated balance sheets.

Impairment of long-lived assets

The Company follows the provisions of FASB ASC 360, Property, Plant, and Equipment (“ASC 360”). ASC 360 requires that long-lived assets be assessed for potential impairment of their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. Proved oil and natural gas properties are evaluated by geologic basin for potential impairment. In accordance with the successful efforts method of accounting, impairment on proved properties is recognized when the estimated undiscounted projected future net cash flows, or evaluation value using expected future prices of a geologic basin are less than its carrying value. If impairment occurs, the carrying value of the impaired geologic basin is reduced to its estimated fair value.

Unproved oil and natural gas properties do not have producing properties and are valued on acquisition by management, with the assistance of an independent expert when necessary. As reserves are proved through the successful completion of exploratory wells, the cost is transferred to proved properties. The cost of the remaining unproved basis is periodically evaluated by management to assess whether the value of a property has diminished. To do this assessment, management considers, (i) estimated potential reserves and future net revenues from an independent expert, (ii) its history in exploring the area, (iii) its future drilling plans per its capital drilling program prepared by its reservoir engineers and operations management, and (iv) other factors associated with the area. Impairment is taken on the unproved property value if it is determined that the costs are not likely to be recoverable. The valuation of unproved oil and gas properties is subjective and requires management to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual results.

Revenue from contracts with customers

The Company recognizes its revenues following ASC Topic 606, Revenue from Contracts with Customers, (“ASC 606”). The Company’s revenues are primarily derived from its interests in the sale of oil and natural gas production. Oil, natural gas, and NGL sales revenues are generally recognized when control of the product is transferred to the customer, the performance obligations under the terms of the contracts with customers are satisfied and collectability is reasonably assured. In circumstances where the Company is the non-operator or mineral right owner, the Company does not consider itself to have control of the product, and revenues are recognized net of post-production expenses. The performance obligations for the Company’s contracts with customers are satisfied as of a point in time through the delivery of oil and natural gas to its customers. Given the inherent time lag between when oil, natural gas, NGL production and sales occur, and when operators or purchasers often make disbursements to royalty interest owners and due to the large potential fluctuations of both production and sale price, a significant portion of the Company’s revenue may represent accrued revenue based on estimated net sales volumes and estimated selling prices of the commodities.

For crude oil and natural gas produced by PhoenixOp, each delivery order is treated as a separate performance obligation. Revenue is recognized when the performance obligation is satisfied, which typically occurs at the point in time control of the product transfers to the customer. Revenue is measured as the amount the Company expects to receive in exchange for transferring commodities to the customer. The Company’s commodity

F-13

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

sales are typically based on prevailing market-based prices. When deliveries contain multiple products, an observable standalone selling price is generally used to measure revenue for each product. Revenues from product sales are presented separately from post-production expenses, including transportation costs, as the Company controls the operated production prior to its transfer to customers.

The Company, through Firebird, provides water disposal services to PhoenixOp and third parties with respect to oil and gas production from wells in which it is the operator. Pricing for such services represents a fixed rate fee based on the quantity of water volume processed. Intercompany charges associated with PhoenixOp’s net interests are eliminated upon consolidation. The proportionate share of fees allocable to third party working interest owners are recognized as revenues over the course of time, as services are performed. Revenues from water services are recognized only when it is probable the Company will collect the consideration it is entitled to in exchange for the services transferred to the customer.

Allocation of transaction price to remaining performance obligations

As the Company has determined that each unit of product generally represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. The Company has utilized the practical expedient in ASC 606, which permits the Company to allocate variable consideration to one or more but not all performance obligations in the contract if the terms of the variable payment related specifically to the Company’s efforts to satisfy that performance obligation and allocating the variable amount to the performance obligation is consistent with the allocation objective under ASC 606. Additionally, the Company will not disclose variable consideration subject to this practical expedient.

Equity-based compensation

The Company accounts for equity-based compensation using the fair value method. The grant-date fair value attributable to the equity awards is calculated based on a combination of an income approach based on the present value of estimated future cash flows, and a market approach based on market data of comparable businesses. Equity awards are granted by Phoenix Equity, the Company’s parent, and are measured at fair value on the date of grant. The Company records equity-based compensation expense and a capital contribution from Phoenix Equity if the requisite service period is deemed to have been rendered and the performance-based condition, if applicable, is probable to be satisfied. Forfeitures are recognized as they occur. For further discussion, see Note 11 – Equity-Based Compensation.

Fair value measurements

The Company follows ASC 820, Fair Value Measurements and Disclosures (“ASC 820”). This standard defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. ASC 820 does not require any new fair value measurements but applies to assets and liabilities that are required to be recorded at fair value under other accounting standards. ASC 820 characterizes inputs used in determining fair value according to a hierarchy that prioritizes those inputs based upon the degree to which they are observable.

F-14

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

The three levels of the fair value measurement hierarchy are as follows:

Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.

Level 2: Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

Level 3: Measured based on prices or valuation models that required inputs that are both significant to the fair value measurement and less observable for objective sources (i.e., supported by little or no market activity).

The carrying values of the Company’s current financial instruments, which include cash and cash equivalents, accounts receivable, accounts payable and accrued and other liabilities, approximated their fair values at December 31, 2024, 2023 and 2022 because of the short-term nature of these instruments. The estimated fair values of the Company’s debt and operating lease liabilities approximated their carrying values using Level 2 fair value inputs as of December 31, 2024, 2023 and 2022. For a discussion of fair value measurements on the Company’s derivatives and asset retirement obligations, refer to Note 6 – Derivatives and Note 7 – Asset Retirement Obligations.

Deferred debt issuance costs

Deferred debt issuance costs represent fees and other direct incremental costs incurred in connection with the Company’s borrowings and offerings of the Company’s debt securities. Upon issuance of the debt, the associated debt issuance costs are reclassified as a discount on the outstanding debt and amortized into interest expense, net of capitalized interest, over the term of the debt using the effective interest method.

Income taxes

The Company is a limited liability company and has elected to be treated as a partnership for income tax purposes. The pro rata share of taxable income or loss is ultimately included in the individual income tax returns of the members of Phoenix Equity, the Company’s parent. Consequently, no provision for incomes taxes is made in the accompanying consolidated financial statements.

The Company remains subject to examination of its U.S. federal partnership tax returns for the tax years ended 2021 through 2024 and its state partnership tax returns for the tax years ended 2020 through 2024. Penalties and interest are classified as selling, general and administrative expense on the consolidated statements of operations.

Recently adopted accounting standards

In November 2023, the FASB issued Accounting Standards Update (“ASU”) 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures (“ASU 2023-07”). ASU 2023-07 requires companies to disclose significant segment expenses, and becomes effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. The Company adopted ASU 2023-07 for the year ended December  31, 2024, and included additional disclosures as required in Note 17 – Segments. There was no impact on our financial position and/or results of operations.

In March 2024, the FASB issued ASU 2024-01, Compensation—Stock Compensation (Topic 718): Scope Application of Profits Interest and Similar Awards (“ASU 2024-01”). ASU 2024-01 provides guidance on how to apply the scope guidance to determine whether profits interests and similar awards should be accounted for as share-based payments arrangements, and becomes effective for fiscal years beginning after December 15, 2024, and interim periods within those annual periods. The Company early adopted ASU 2024-01 effective December  31, 2024 and the adoption did not have a material impact on the Company’s consolidated financial statements. See Note 11 – Equity-Based Compensation for additional information.

F-15

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

Recent accounting standards not yet adopted

In November 2024, the FASB issued ASU 2024-03, Income Statement—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses (“ASU 2024-03”). ASU 2024-03 requires companies to provide more detailed disclosures about the disaggregation of income statement expenses. The ASU aims to enhance the transparency and usefulness of financial statements by providing better insight into the components of expense line items, and becomes effective for fiscal years beginning after December 15, 2026, and interim periods within fiscal years beginning after December 15, 2027. The Company is currently evaluating the impact of the standard on our financial statements and disclosures.

Accounting pronouncements not listed above were assessed and determined to not have a material impact to the Company’s consolidated financial statements.

Note 3 – Restatement of Prior Year Financial Statements

In December 2023, the Company engaged its current independent registered public accounting firm, Ramirez Jimenez International CPAs, to audit the consolidated financial statements as of and for the year ended December 31, 2022 (the “2022 consolidated financial statements”) in accordance with the standards of the Public Company Accounting Oversight Board (the “PCAOB”). Previously, the 2022 consolidated financial statements were audited by the Company’s former auditor, Cherry Bekaert LLP, in accordance with generally accepted auditing standards in the United States (“GAAS”) (the “2022 GAAS Financials”), as permitted for financial statements to be included in an offering circular for a Tier 2 offering pursuant to Regulation A under the U.S. Securities Act of 1933, as amended. Although Form 1-K permits an issuer to include in such form financial statements audited in accordance with GAAS, the Company was permitted, and elected, under Regulation A to file the 2022 consolidated financial statements audited in accordance with the PCAOB standards (the “2022 PCAOB Financials”). In connection with this audit, the Company and the current auditor determined that there were errors in the 2022 GAAS Financials, primarily due to the calculation of depletion expense resulting from information becoming available subsequent to the issuance of the 2022 GAAS Financials, that are being corrected in the comparative periods of these consolidated financial statements as of and for the year ended December 31, 2024.

Subsequently, the Company restated its 2022 and 2023 consolidated financial statements to correct the accounting treatment for debt issuance costs incurred in connection with the Company’s unregistered bond offerings and capitalized interest. Debt issuance costs were previously expensed immediately and interest costs were not capitalized. The Company corrected these errors in the comparative periods of these consolidated financial statements as of and for the year ended December 31, 2024, such that debt issuance costs associated with the Company’s unregistered bond offerings are deferred and amortized over the weighted average debt term using the effective interest method. Further, interest incurred on expenditures made in connection with the Company’s exploration and development projects not currently subject to depletion are capitalized and subsequently depleted in the same manner as the underlying assets.

The effects of the changes on the Company’s consolidated financial statements as of and for the years ended December 31, 2023 and 2022 are summarized below.

Description of Misstatements

The Company identified the following misstatements in the 2022 GAAS Financials:

Oil and gas properties and asset retirement obligations. The Company identified an error in the calculation of the Company’s estimated retirement costs, which understated the Company’s oil and gas properties (asset additions) and asset retirement obligation liability of $0.1 million and $0.2 million, respectively, as of December 31, 2022.

F-16

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

Accumulated depletion and impairment. The Company identified an error in the timing of the recognition of depletion expense, which overstated accumulated depletion and impairment by $2.2 million as of December 31, 2022. See discussion of depreciation, depletion, amortization, and accretion below.

Right-of-use assets and operating lease liabilities. The Company adjusted its right-of-use assets to reflect the adoption of ASC 842 Leases (“ASC 842”) for public companies. The right-of-use assets amount was previously based on the Company’s adoption of ASC 842 for non-public companies. The adjustment reduced the right-of-use asset by $0.4 million with a corresponding reduction to current operating lease liabilities and operating lease liabilities of $0.1 million and $0.3 million, respectively.

Accounts payable. The Company identified errors related to the recognition of certain invoices in the proper accounting period, which understated accounts payable by $0.9 million as of December 31, 2022.

Escrow account. The Company identified an error related to the misclassification of the escrow account liability, which was previously classified as a component of long-term debt as of December 31, 2022. See discussion of long-term debt, net of current portion below.

Accrued and other liabilities. The Company identified an error in the calculation of accrued interest, which overstated accrued and other liabilities by $0.9 million as of December 31, 2022, partially offset by a $0.2 million understatement relating to year-end performance bonuses which were not previously accrued.

Long-term debt, net of current portion. See discussion of escrow account above. The remaining difference relates to the classification of bond discount accretion, which was previously classified as a component of accrued interest and accretion in the 2022 GAAS Financials. The Company corrected the classification of unamortized debt discount to be in the same line item as the debt liability.

Members’ equity. The correction of the Company’s misstatements on the consolidated statement of operations for the year ended December 31, 2022 resulted in an increase to members’ equity. See discussion below.

Revenues. The Company identified an error relating to the classification of royalty owner deductions of $3.0 million as an operating expense for the year ended December 31, 2022. The reclassification from operating expense to contra-revenue is a result of the Company’s conclusion that it is acting as the agent under its contracts with customers, and therefore must recognize revenue on a net basis in accordance with ASC 606, Revenue from Contracts with Customers.

Depreciation, depletion, amortization, and accretion: The Company identified an error in the calculation of the depletion expense, which previously excluded NGL reserves. The addition of NGL reserves decreased the depletion rate from 12.4% to 10.4%, which decreased the Company’s depletion expense by $2.2 million.

Payroll and payroll-related expense. The Company had previously not accrued year-end performance bonuses, which resulted in understated payroll and payroll-related expense of $0.2 million for the year ended December 31, 2022. In addition, the Company reclassified $3.8 million of guaranteed payments previously classified as selling, general, and administrative expense to payroll and payroll-related expense on the consolidated statement of operations.

In addition to the items noted herein, the Company identified immaterial errors in periods prior to the year ended December 31, 2022, the impact of which is reflected as an adjustment to beginning member’s equity of less than $0.1 million. The remainder of the notes to the Company’s consolidated financial statements have been updated and restated, as applicable, to reflect the impacts of the restatement described above.

Subsequently, the Company identified the following misstatements in the 2022 and 2023 consolidated financial statements during the first quarter of 2025:

Debt issuance costs. The Company had previously immediately expensed debt issuance costs related to its unregistered bond offerings rather than amortizing them over the weighted-average term of the bonds, which

F-17

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

resulted in overstated advertising and marketing expense, selling, general and administrative expense, and payroll and payroll-related expense, and understated interest expense and loss on debt extinguishment on the consolidated statements of operations for the years ended December 31, 2023 and 2022. Long-term debt, net of current portion was overstated by $34.4 million and $4.3 million on the consolidated balance sheets as of December 31, 2023 and 2022, respectively.

Capitalized interest. The Company had previously expensed all interest costs, rather than capitalizing interest incurred on expenditures made in connection with the Company’s exploration and development projects as permitted under ASC 835-20, Capitalized Interest. This resulted in overstated interest expense on the consolidated statement of operations for the year ended December 31, 2023, and a corresponding understatement of oil and gas properties on the consolidated balance sheet as of December 31, 2023. There was no impact to the 2022 consolidated financial statements for capitalized interest.

The following tables present a reconciliation from the figures as previously reported to the restated amounts for the Company’s consolidated balance sheets, statements of operations, statements of cash flows, and statements of changes in equity as of and for the years ended December 31, 2023 and 2022.

Corrected Consolidated Balance Sheets

	December 31, 2023
(in thousands)	As Previously Reported			Debt Issuance Costs, Capitalized Interest and Other Corrections			As Restated
Oil and gas properties	$	476,264		$	2,075		$	478,339
Net oil and gas properties		421,593			2,075			423,668
Total assets		491,092			2,075			493,167
Long-term debt, net of current portion		329,519			(34,352	)		295,167
Total liabilities		532,353			(34,352	)		498,001
Member’s equity (deficit)		(41,261	)		36,427			(4,834	)
Total liabilities and member’s equity (deficit)		491,092			2,075			493,167

F-18

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

	December 31, 2022
(in thousands)	As Previously Reported			Misstatement Corrections to 2022 GAAS Financials			Debt Issuance Costs, Capitalized Interest and Other Corrections			As Restated
Oil and gas properties	$	165,252		$	138		$	—		$	165,390
Accumulated depletion and impairment		(22,839	)		2,204			—			(20,635	)
Net oil and gas properties		142,413			2,342			—			144,755
Right-of-use assets		2,152			(354	)		—			1,798
Total assets		155,013			2,007			—			157,020
Accounts payable		18,583			855			—			19,438
Escrow account		—			701			—			701
Current operating lease liabilities		413			(108	)		—			305
Accrued and other liabilities		2,908			(672	)		—			2,236
Total current liabilities		80,457			776			—			81,233
Long-term debt, net of current portion		64,501			(684	)		(4,336	)		59,481
Accrued interest		306			(15	)		—			291
Operating lease liabilities		1,853			(256	)		—			1,597
Asset retirement obligations		62			150			—			212
Total liabilities		152,712			(29	)		(4,336	)		148,347
Member’s equity		2,301			2,036			4,336			8,673
Total liabilities and member’s equity (deficit)		155,013			2,007			—			157,020

Corrected Consolidated Statements of Operations

	Year ended December 31, 2023
(in thousands)	As Previously Reported			Debt Issuance Costs, Capitalized Interest and Other Corrections			As Restated
Advertising and marketing	$	36,696		$	(32,560	)	$	4,136
Selling, general and administrative		19,112			(4,798	)		14,314
Payroll and payroll-related		18,817			(6,084	)		12,733
Total operating expenses		129,560			(43,442	)		86,118
Income (loss) from operations		(11,455	)		43,442			31,987
Interest expense		(36,859	)		(11,023	)		(47,882	)
Loss on debt extinguishment		—			(328	)		(328	)
Total other expenses		(36,825	)		(11,351	)		(48,176	)
Net income (loss)		(48,280	)		32,091			(16,189	)

F-19

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

	Year ended December 31, 2022
(in thousands)	As Previously Reported			Misstatement Corrections to 2022 GAAS Financials			Debt Issuance Costs, Capitalized Interest and Other Corrections			As Restated
Mineral and royalty revenues	$	57,563		$	(3,009	)	$	—		$	54,554
Total revenues		57,563			(3,009	)		—			54,554
Cost of sales		12,582			(3,009	)		—			9,573
Depreciation, depletion, amortization, and accretion		14,337			(2,193	)		—			12,144
Advertising and marketing		5,350			—			(3,997	)		1,353
Selling, general, and administrative		9,356			(3,793	)		—			5,563
Payroll and payroll-related expenses		3,412			3,965			(1,354	)		6,023
Total operating expenses		45,037			(5,030	)		(5,351	)		34,656
Income from operations		12,526			2,021			5,351			19,898
Interest expense		(10,990	)		20			(923	)		(11,893	)
Loss on debt extinguishment		—			—			(92	)		(92	)
Total other expenses		(13,229	)		20			(1,015	)		(14,224	)
Net income (loss)		(703	)		2,041			4,336			5,674

Corrected Consolidated Statements of Changes in Equity

(in thousands)	As Previously Reported			Misstatement Corrections to 2022 GAAS Financials			Debt Issuance Costs, Capitalized Interest and Other Corrections		As Restated
Balance at December 31, 2021 (As Restated)	$	2,908		$	(4	)	$	—	$	2,904
Contributions		200			—			—		200
Distributions		(105	)		—			—		(105	)
Net loss (As Restated)		(703	)		2,041			4,336		5,674
Balance at December 31, 2022 (As Restated)	$	2,300		$	2,037		$	4,336	$	8,673
Balance at December 31, 2022 (As Restated)		4,337			—			4,336		8,673
Contributions		10,150			—			—		10,150
Distributions		(7,468	)		—			—		(7,468	)
Net income (As Restated)		(48,280	)		—			32,091		(16,189	)
Balance at December 31, 2023 (As Restated)	$	(41,261	)	$	—		$	36,427	$	(4,834	)

F-20

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

Corrected Consolidated Statements of Cash Flows

	Year ended December 31, 2023
(in thousands)	As Previously Reported			Debt Issuance Costs, Capitalized Interest and Other Corrections			As Restated
Net loss	$	(48,280	)	$	32,091		$	(16,189	)
Adjustments to reconcile net loss to net cash used in operating activities:
Amortization of debt discount and debt issuance costs		656			13,097			13,753
Loss on debt extinguishment		—			328			328
Net cash (used in) provided by operating activities		(47,342	)		45,516			(1,826	)
Additions to oil and gas properties and leases		(286,417	)		7,756			(278,661	)
Payments of debt issuance costs		—			(43,441	)		(43,441	)
Payments of deferred closings		6,851			(9,831	)		(2,980	)
Net cash provided by financing activities		334,580			(53,272	)		281,308

	Year ended December 31, 2022
(in thousands)	As Previously Reported			Misstatement Corrections to 2022 GAAS Financials			Debt Issuance Costs, Capitalized Interest and Other Corrections			As Restated
Net income (loss)	$	(703	)	$	2,041		$	4,336		$	5,674
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depreciation, depletion, amortization, and accretion		14,337			(2,193	)		—			12,144
Amortization of right-of-use assets		114			(10	)		—			104
Amortization of debt discount and debt issuance costs		1,004			(987	)		923			940
Unrealized loss (gain) on derivatives		—			(46	)		—			(46	)
Loss on debt extinguishment		—			—			92			92
Changes in operating assets and liabilities:
Earnest payments		—			(788	)		—			(788	)
Accounts payable		321			23			—			344
Accrued and other liabilities		1,006			864			—			1,870
Escrow account		—			701			—			701
Accrued interest		868			(577	)		—			291
Other		(658	)		705			—			47
Net cash provided by operating activities		13,559			(268	)		5,351			18,642
Additions to oil and gas properties and leases		(100,224	)		17			8,944			(91,263	)
Net cash used in investing activities		(100,849	)		17			8,944			(91,888	)
Proceeds from issuances of debt, net of discount		85,136			(4,388	)		(249	)		80,499
Payments of debt issuance costs		—			—			(5,351	)		(5,351	)
Repayments of debt		(1,000	)		3,687			—			2,687
Payments of deferred closings		7,653			605			(8,695	)		(437	)
Net cash flows provided by financing activities		91,884			(96	)		(14,295	)		77,493

F-21

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

Note 4 – Oil and Gas Properties

Oil and gas properties, net consist of the following:

	December 31,
(in thousands)	2024			2023			2022
Proved oil and natural gas properties(a)	$	687,366		$	371,625		$	123,527
Unproved oil and natural gas properties		318,855			106,714			41,863
Total oil and gas properties		1,006,221			478,339			165,390
Less: Accumulated depletion and impairment		(140,376	)		(54,671	)		(20,635	)
Oil and gas properties, net	$	865,845		$	423,668		$	144,755

(a) Represents proved and undeveloped (i.e., wells in progress) and proved and producing properties.

The Company considers a property proved when geological and engineering data can demonstrate with reasonable certainty that estimated quantities of oil, natural gas, and NGLs can be recoverable from known reservoirs in future periods under the economic and operating conditions (i.e., prices and costs) that exist at the time the estimates are made.

A property is unproved when there are currently no producing wells pooling the property. For the majority of the value of the unproven properties in 2024, the Company has analyzed the wells within a 10-mile radius of the property to conclude the property is economically viable for oil extraction and has the potential to be drilled and become proved reserves.

Depletion on oil and gas properties was $84.8 million, $34.0 million, and $12.0 million for the years ended December 31, 2024, 2023, and 2022, respectively.

Depreciation expense on the Company’s equipment and other property was $0.1 million for the years ended December 31, 2024, 2023, and 2022, respectively.

Impairment

When the Company performs its annual impairment test or circumstances indicate that the proved oil and gas properties may be impaired, the Company compares expected undiscounted future cash flows to the assets’ carrying value grouped by geologic basin. If the undiscounted future cash flows, based on the Company’s estimate of significant Level 3 inputs, including futures prices, anticipated production from proved reserves and other relevant data, are lower than the assets’ carrying value, the carrying value is reduced to fair value. Impairment expense also includes write-offs associated with title defects and lease expirations of the Company’s oil and gas properties, which totaled $0.6 million for the year ended December 31, 2024. In 2023, the Company’s proved natural gas properties with a carrying value of approximately $2.0 million were written down to their fair value of approximately $1.0 million due to a decline in the Henry Hubs future price. Impairment expense of approximately $1.0 million was recognized for the year ended December 31, 2023.

Note 5 – Revenue

Revenue from contracts with customers is presented as mineral and royalty revenues and product sales on the consolidated statements of operations. The Company is paid mineral and royalty revenue monthly by the various operators and working interest owners within the pooled units that the Company owns, and PhoenixOp is paid revenue monthly for the commodities it extracts and delivers to purchasers. Mineral and royalty revenues within the mineral and non-operating segment are presented net of post-production costs charged by the operator, whereas product sales revenue within the operating segment are presented separately from post-production costs, including transportation costs, on the consolidated statements of operations. Other costs, including severance taxes and lease operating expenses are presented as cost of sales on the consolidated statements of operations for both the mineral and non-operating and operating segments.

F-22

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

In 2024, the Company began generating revenues from performing saltwater disposal services on wells in which it is the operator. Revenues are driven primarily by the volumes of produced water and flowback water the Company injects into its saltwater disposal facilities and the fees the Company charges for these services. Fees are charged on a per-barrel basis and are recognized as revenues in accordance with ASC 606.

Other revenue is comprised of redemption fees that are charged to investors, generally upon the early redemption of their investments. For the securities segment, other revenue also includes intersegment interest revenue earned from the mineral and non-operating and operating segments that is eliminated in the consolidated statements of operations.

The following table presents the Company’s revenue from contracts with customers and other revenue for the years ended December 31, 2024, 2023, and 2022 by segment:

	Year Ended December 31, 2024
(in thousands)	Mineral and Non-Operating		Operating		Securities		Eliminations			Total
Revenue from customers	$	152,999	$	128,127	$	—	$	—		$	281,126
Other revenue		—		—		101		—			101
Intersegment revenue		136		—		102,030		(102,166	)		—
Total	$	153,135	$	128,127	$	102,131	$	(102,166	)	$	281,227

	Year Ended December 31, 2023
(in thousands)	Mineral and Non-Operating		Operating		Securities		Eliminations			Total
Revenue from customers	$	116,863	$	1,225	$	—	$	—		$	118,088
Other revenue		—		—		17		—			17
Intersegment revenue		39		—		40,492		(40,531	)		—
Total	$	116,902	$	1,225	$	40,509	$	(40,531	)	$	118,105

	Year Ended December 31, 2022
(in thousands)	Mineral and Non-Operating		Operating		Securities		Eliminations			Total
Revenue from customers	$	54,554	$	—	$	—	$	—		$	54,554
Intersegment revenue		—		—		4,991		(4,991	)		—
Total	$	54,554	$	—	$	4,991	$	(4,991	)	$	54,554

The following tables present the Company’s revenue from contracts with customers disaggregated by product type for the periods presented:

	Year Ended December 31, 2024
(in thousands)	Mineral and Non-Operating		Operating		Securities		Eliminations		Total
Crude oil	$	138,640	$	123,340	$	—	$	—	$	261,980
Natural gas sales		5,424		315		—		—		5,739
NGL		8,935		1,994		—		—		10,929
Water services		—		2,478		—		—		2,478
Total	$	152,999	$	128,127	$	—	$	—	$	281,126

F-23

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

	Year Ended December 31, 2023
(in thousands)	Mineral and Non-Operating		Operating		Securities		Eliminations		Total
Crude oil	$	104,631	$	1,140	$	—	$	—	$	105,771
Natural gas sales		6,776		14		—		—		6,790
NGL		5,456		71		—		—		5,527
Total	$	116,863	$	1,225	$	—	$	—	$	118,088

	Year Ended December 31, 2022
(in thousands)	Mineral and Non-operating		Operating		Securities		Eliminations		Total
Crude oil	$	47,493	$	—	$	—	$	—	$	47,493
Natural gas sales		7,061		—		—		—		7,061
Total	$	54,554	$	—	$	—	$	—	$	54,554

The following table summarizes major customers that make up 10% or more of accounts receivable as of December 31, 2024, 2023, and 2022:

	December 31,
	2024			2023			2022
Customer A		17	%		—	%		34	%
Customer B		15	%		—	%		—	%
Customer C		13	%		—	%		—	%
Customer D		—	%		26	%		—	%
Customer E		—	%		14	%		—	%
Customer F		—	%		—	%		10	%

The following table summarizes major customers that make up 10% or more of revenue for the years ended December 31, 2024, 2023, and 2022:

	Year Ended December 31,
	2024			2023			2022
Customer A		21	%		—	%		—	%
Customer B		—	%		11	%		14	%
Customer C		—	%		—	%		16	%
Customer D		—	%		—	%		16	%
Customer E		—	%		—	%		15	%

Note 6 – Derivatives

The Company periodically enters into commodity derivative contracts to manage its exposure to crude oil price risk. Additionally, the Company is required to hedge a portion of anticipated crude oil production for future periods pursuant to its debt covenants under the Fortress Credit Agreement, as further described in Note 8 – Debt. The Company does not enter into derivative contracts for speculative trading purposes.

When the Company utilizes crude oil commodity derivative contracts, it expects to enter into put/call collars, fixed swaps or put options to hedge a portion of its anticipated future production. A collar contract establishes a floor and ceiling price on contracted volumes and provides payment to the Company if the index price falls below the floor or requires payment by the Company if the index price rises above the ceiling. A fixed swap contract sets a fixed price and provides payment to the Company if the index price is below the fixed price or requires payment by the Company if the index price is above the fixed price. A put arrangement gives the Company the right to sell the underlying crude oil commodity at a strike price and provides payment to the Company if the

F-24

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

index price falls below the strike price. No payment or receipt occurs if the index price is higher than the strike price. As of December 31, 2024, the Company’s derivatives were comprised of crude oil commodity derivative contacts indexed to the U.S. New York Mercantile Exchange West Texas Intermediate (“WTI”). The Company has not designated its derivative contracts for hedge accounting and, as a result, records the net change in the mark-to-market valuation of the derivative contracts and all payments and receipts on settled derivative contracts in its consolidated statements of operations. All derivative contracts are recorded at fair market value and included in the consolidated balance sheets as assets or liabilities. Derivative assets and liabilities are presented net on the consolidated balance sheets when a legally enforceable master netting arrangement exists with the counterparty.

As of December 31, 2024, the Company’s open crude oil derivative contracts consisted of the following:

	Settlement Period
(volumes in Bbl and prices in $/Bbl)	2025		2026		2027
Two-Way Collars
Notional Volumes		624,900		367,700		259,000
Weighted Average Ceiling Price	$	76.02	$	71.69	$	69.86
Weighted Average Floor Price	$	59.35	$	56.01	$	57.42
Swaps
Notional Volumes		2,174,200		1,260,000		894,000
Weighted Average Contract Price	$	68.86	$	64.62	$	63.07

The following table summarizes the gains and losses on derivative instruments included on the consolidated statements of operations and the net cash payments thereto for the periods presented. Cash flows associated with these non-hedge designated derivatives are reported within operating activities on the consolidated statements of cash flows.

	Year Ended December 31,
(in thousands)	2024			2023			2022
Loss on derivative instruments	$	(5,986	)	$	(32	)	$	(2,239	)
Net cash receipts (payments) on derivatives		1,532			100			(1,328	)

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.

Certain assets and liabilities are reported at fair value on a recurring basis, including the Company’s derivative instruments. The fair values of the Company’s derivative contracts are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third party, the contracted notional volumes, and time to maturity. These valuations are Level 2 inputs.

F-25

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

The following table provides (i) fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis, (ii) the gross amounts of recognized derivative assets and liabilities, (iii) the amounts offset under master netting arrangements with counterparties, and (iv) the resulting net amounts presented in the Company’s consolidated balance sheets as of December 31, 2024, 2023 and 2022. The net amounts are classified as current or noncurrent based on their anticipated settlement dates. Current derivative assets are presented as other current assets and current derivative liabilities are presented as a component of accrued and other liabilities on the consolidated balance sheets.

	December 31, 2024
(in thousands)	Balance Sheet Location	Level 1		Level 2			Level 3		Total Gross Fair Value			Gross Amounts Offset in Balance Sheet			Net Fair Value Presented in Balance Sheet
Assets
Commodity derivatives	Other current assets	$	—	$	2,138		$	—	$	2,138		$	(2,037	)	$	101
Commodity derivatives	Other noncurrent assets		—		3,000			—		3,000			(3,000	)		—
		$	—	$	5,138		$	—	$	5,138		$	(5,037	)	$	101
Liabilities
Commodity derivatives	Accrued and other liabilities	$	—	$	(4,574	)	$	—	$	(4,574	)	$	2,037		$	(2,537	)
Commodity derivatives	Other noncurrent liabilities		—		(7,858	)		—		(7,858	)		3,000			(4,858	)
		$	—	$	(12,432	)	$	—	$	(12,432	)	$	5,037		$	(7,395	)

	December 31, 2023
(in thousands)	Balance Sheet Location	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
Assets
Commodity derivatives	Other current assets	$	—	$	71	$	—	$	71	$	—	$	71
		$	—	$	71	$	—	$	71	$	—	$	71
Liabilities
Commodity derivatives	Accrued and other liabilities	$	—	$	—	$	—	$	—	$	—	$	—
		$	—	$	—	$	—	$	—	$	—	$	—

	December 31, 2022
(in thousands)	Balance Sheet Location	Level 1		Level 2			Level 3		Total Gross Fair Value			Gross Amounts Offset in Balance Sheet			Net Fair Value Presented in Balance Sheet
Assets
Commodity derivatives	Other current assets	$	—	$	18		$	—	$	18		$	(18	)	$	—
		$	—	$	18		$	—	$	18		$	(18	)	$	—
Liabilities
Commodity derivatives	Accrued and other liabilities	$	—	$	(20	)	$	—	$	(20	)	$	18		$	(2	)
		$	—	$	(20	)	$	—	$	(20	)	$	18		$	(2	)

Note 7 – Asset Retirement Obligations

The Company’s asset retirement obligations relate to the future plugging and abandonment of wells and related facilities. As of December 31, 2024, 2023 and 2022, the net present value of the total ARO was estimated to

F-26

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

be $1.3 million, $0.6 million and $0.2 million, respectively, with the undiscounted value being $12.9 million, $7.7 million and $2.7 million, respectively. Total ARO shown in the table below consists of amounts for future plugging and abandonment liabilities on wellbores in which the Company has a working interest or are operated by the Company, adjusted for inflation at a rate of 2.56%, 2.50% and 2.55% per annum as of December 31, 2024, 2023 and 2022, respectively. These values are discounted to present value using a rate of 10.0% per annum for the years ended December 31, 2024, 2023 and 2022.

The following table summarizes the changes in the ARO for the periods presented:

	Year Ended December 31,
(in thousands)	2024			2023		2022
Asset retirement obligations at beginning of period	$	697		$	212	$	40
Additions		1,430			430		155
Derecognition		(975	)		—		—
Accretion		180			55		17
Revisions in estimated cash flows		15			—		—
Asset retirement obligations at end of period(a)	$	1,347		$	697	$	212

(a) Current ARO is classified as a component of accrued and other liabilities and noncurrent ARO is classified as asset retirement obligations on the consolidated balance sheets. As of December 31, 2024 and 2023, current ARO was approximately $0.2 million and $0.1 million, respectively, and noncurrent ARO was approximately $1.2 million and $0.6 million, respectively.

ARO is measured using primarily Level 3 inputs. The significant unobservable inputs to this fair value measurement include estimates of plugging costs, remediation costs, inflation rate, and well life. The inputs are calculated based on historical data as well as current estimated costs.

Note 8 – Debt

Short-Term Debt

Amarillo National Bank Credit Agreement

In July 2023, the Company entered into a one-year credit agreement with Amarillo National Bank (“ANB”) for a $30.0 million revolving line of credit (the “ANB Credit Agreement”). The Company fully repaid the ANB Credit Agreement in August 2024 with proceeds received from the Fortress Term Loan, as further described below. The ANB Credit Agreement bore interest at the Wall Street Journal’s prime rate plus 3.0% per annum, with a floor of 9.0% per annum. Interest expense of $2.1 million and $1.5 million was attributable to the ANB Credit Agreement for the years ended December 31, 2024 and 2023, respectively. There was no outstanding balance under the ANB Credit Agreement as of December 31, 2024. As of December 31, 2023, the outstanding balance of the ANB Credit Agreement was $19.1 million.

Merchant Cash Advances

In December 2024, Phoenix Energy fully repaid its outstanding balances under the merchant cash advance agreements it had entered into with several financial institutions. The Company sold its future receivables for cash advances under these agreements, which were short-term and required the Company to repay the advances on a weekly or bi-weekly basis. Repayment amounts incorporated factor rates, which indicate the percentage of the loan amount that is to be repaid, ranging from 1.17 to 1.23 for merchant cash advances outstanding of $6.7 million as of December 31, 2023, and 1.15 to 1.33 for merchant cash advances outstanding of $6.8 million as of December 31, 2022. Interest expense attributable to the merchant cash advances was $3.0 million, $2.5 million, and $2.9 million for the years ended December 31, 2024, 2023 and 2022, respectively.

F-27

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

Long-Term Debt

The following table summarizes the Company’s long-term debt for the periods presented:

	Maturity Date						December 31,
(in thousands)	Earliest Date		Latest Date		Interest Rate(a)		2024			2023			2022
Unsecured debt - Regulation D		1/10/2025		12/10/2035		5.0% to 15.0%	$	497,823		$	313,681		$	46,979
Unsecured debt - Regulation A		1/10/2025		8/10/2027		9.0%		104,884			85,250			35,868
Adamantium Securities		1/10/2029		12/10/2035		13.0% to 16.5%		135,180			22,824			—
Fortress Term Loan		—		12/18/2027		Term SOFR + 7.10%		250,000			—			—
Cortland Line of Credit		—		—		—%		—			—			23,000
Cortland Term Loan		—		—		—%		—			—			3,833
Other								—			289			369
Total outstanding debt								987,887			422,044			110,049
Less: Unamortized debt discount and issuance costs(b)								(89,432	)		(39,839	)		(4,529	)
Less: Current portion of long-term debt								(103,240	)		(87,038	)		(46,039	)
Total long-term debt, net of current portion							$	795,215		$	295,167		$	59,481

(a) Represents the contractual interest rate as of December 31, 2024.

(b) Amortized into interest expense using the effective interest method. Write-offs of debt issuance costs associated with the redemption of bonds issued under the Company’s unregistered debt offerings are classified as loss on debt extinguishment in the consolidated statements of operations.

The following table summarizes the aggregate contractual annual maturities for the Company’s long-term debt outstanding as of December 31, 2024, excluding unamortized debt discount and issuance costs:

(in thousands)
Year Ending December 31,	Amount
2025	$	103,319
2026		203,279
2027		212,976
2028		14,724
2029		43,700
Thereafter		409,889
Total	$	987,887

Unsecured Debt

Phoenix Energy has several bond offerings issued under Regulation A and Rule 506(c) of Regulation D of federal securities law. Under the federal securities laws, any offer or sale of a security must be registered with the Securities Exchange Commission (“SEC”) or qualify for an exemption. Regulation A and Regulation D provide certain exemptions from the registration requirements, which allow companies to offer and sell their securities without having to register the offering with the SEC. The Company first commenced its bond offerings pursuant to Regulation D in July 2020, and subsequently Regulation A in December 2021, and have since issued a cumulative combined total of $948.5 million of debt to investors from inception through December 31, 2024. The bonds have terms ranging from one to eleven years. In instances where interest is compounded, interest is accrued monthly. Interest expense attributable to these bonds totaled $60.7 million, $29.5 million, and $4.1 million for the years ended December 31, 2024, 2023, and 2022 respectively.

In March 2024, the Company filed an amendment to the Form 1-A that was originally qualified by the SEC in December 2021 (as amended) to update the maximum offering available for sale of the Company’s 9.0% unsecured bonds. This amendment offered up to $31.7 million of the Company’s bonds, which, under Regulation A, represented the maximum that could be offered out of the $75.0 million limit on securities the Company was authorized to issue over a rolling twelve-month period. The Company issued $31.6 million of Regulation A bonds during the year ended December 31, 2024, of which $1.8 million was subsequently early redeemed.

F-28

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

Adamantium Securities

In September 2023, the Company, through its wholly-owned subsidiary, Adamantium, commenced an offering of bonds exempt from registration pursuant to Rule 506(c) of Regulation D (the “Adamantium Bonds”). The Adamantium Bonds offer high net worth individuals a debt instrument that is unsecured but structurally senior to other bonds sold by the Company under Regulation A and Regulation D. The Adamantium Bonds have maturity terms that range from five to eleven years and bear interest ranging from 13.0% to 16.5% per annum. In November 2024, Adamantium issued a $7.0 million seven-year promissory note to an investor bearing interest at 16.5% per annum (the “Adamantium Secured Note,” and together with the Adamantium Bonds, “the Adamantium Securities”). The Adamantium Securities contain customary events of default and may be redeemed at the option of Adamantium at any time without premium or penalty. The holders of Adamantium Bonds also have a right to request redemption of their bonds in certain circumstances at a discount to par, subject to a limit of 10% of the then-outstanding principal amount of Adamantium Bonds in any given calendar year. The holder of the Adamantium Secured Note has the right to request redemption of its note at par, subject to a limit of $5.0 million in aggregate principal amount of the Adamantium Secured Note in any 12-month period.

Cortland Credit Line of Credit and Term Loan

In October 2021, the Company obtained a $23.0 million revolving line of credit with Cortland Credit Lending Corporation (“Cortland”) due in October 2023 (the “Cortland Line of Credit”). The Cortland Line of Credit accrued interest at a variable rate per annum equal to the greater of (a) 10.50% or (b) the TD Bank US Prime Rate plus 7.25% and was payable monthly. Subsequently, in October 2022, the Company issued a $5.0 million five-year term loan with Cortland bearing the same interest rate as the Cortland Line of Credit, plus an additional fixed fee of $83,333 per month.

In April 2023, the Company agreed to a “term out” of its existing obligations with Cortland and converted the line of credit and term loan into a $26.8 million term loan maturing in January 2024 (the “Cortland Term Loan”). The Company was required to repay the Cortland Term Loan in ten equal payments of $2.7 million per month, plus interest. There were no changes to the interest rate terms resulting from the term out conversion. In July 2023, the Company fully repaid the Cortland Term Loan with the proceeds of the ANB Credit Agreement (as defined above). Interest expense attributable to Cortland of $2.1 million and $3.3 million was recognized for the years ended December 31, 2023 and 2022, respectively. Prior to the repayment, our obligations under the credit agreements with Cortland were collateralized by the Company’s oil and gas properties.

Fortress Credit Agreement

In August 2024, the Company entered into a secured credit agreement (the “Fortress Credit Agreement”) with Fortress Credit Corp. (“Fortress”) for a $100.0 million term loan facility (the “Fortress Term Loan”), borrowed in full upon closing, and a $35.0 million delayed draw term loan facility (the “DDTL Facility”) that was subsequently drawn in October 2024. In December 2024, the Company entered into an amendment with Fortress which provided for a new tranche of term loans in an aggregate principal amount of $115.0 million (the “Fortress Tranche C Loan” and, together with the Fortress Term Loan and the DDTL Facility, the “Fortress Loans”) that was borrowed in full immediately upon closing. The proceeds from the Fortress Loans were used, in part, to pay all amounts owed under the ANB Credit Agreement. The remaining proceeds are being used for the development of the Company’s oil and gas properties in accordance with the approved plan of development provided in the Fortress Credit Agreement. Debt issuance costs of $4.3 million, together with the $7.5 million debt discount associated with the Fortress Loans, are amortized to interest expense over the term of the loan.

The Fortress Loans bear interest at a rate per annum equal to Term Secured Overnight Financing Rate (“SOFR”) plus a margin of 7.1%, which is due and payable at the last day of each fiscal quarter. As of December 31, 2024, the all-in interest rate was 11.7%. The amendment the Company entered into December 2024 extended the

F-29

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

maturity date from August 2027 to December 2027 and revised the repayment schedule such that at least $125.0 million of the outstanding principal is to be repaid by December 2026, with the remainder due upon maturity. Additionally, in connection with any payment in full of the Fortress Loans, the Company is required to pay a repayment premium in an amount that achieves a multiple on invested capital of 1.18, as defined in the Fortress Credit Agreement.

The Fortress Credit Agreement also includes an $8.5 million tranche of loans (the “Tranche B Loan”), which represents a contingent principal obligation that is only due and payable (together with accrued interest thereon) upon certain conditions occurring, including payment defaults under the Fortress Credit Agreement or a bankruptcy filing by the Company. No value was attributed to this embedded feature as this feature was determined to be triggered by events with only a remote probability of occurrence.

Loans under the Fortress Credit Agreement are secured by substantially all of the assets of Phoenix Energy, PhoenixOp and certain of the Company’s other wholly-owned subsidiaries. The Fortress Credit Agreement also contains various customary affirmative and negative covenants, including financial covenants that require the Company to maintain (a) a maximum total secured leverage ratio as of the last day of any fiscal quarter ending on or before December 31, 2025 of less than or equal to 2.00 to 1.00 (commencing with the fiscal quarter ending December 31, 2024) and (i) as of the last day of any fiscal quarter ending on or after March 31, 2026 of less than or equal to 1.50 to 1.00, (b) a minimum current ratio as of the last day of each calendar month of (i) 0.90 to 1.00 from September 30, 2024 through October 31, 2024, (ii) 0.80 to 1.00 from November 30, 2024 through November 30, 2025, (iii) 0.90 to 1.00 from December 31, 2025 through December 31, 2026 and (iv) 1.00 to 1.00 for each calendar month ending thereafter and (c) a minimum asset coverage ratio as of the last day of any fiscal quarter of at least 2.00 to 1.00. Additionally, the Fortress Credit Agreement requires the Company to enter into and maintain through September 30, 2025, hedges covering at least 75% of the initially anticipated monthly production of crude oil from the Company’s proved developed reserves for a 36-month period. See Note 6 – Derivatives. As of December 31, 2024, we were in compliance with all covenants contained in the Fortress Credit Agreement.

Interest Expense on Debt

The following table presents the total interest expense incurred on the Company’s debt:

	Year Ended December 31,
(in thousands)	2024			2023			2022
Stated interest	$	85,409		$	36,204		$	10,953
Amortization of debt discount and debt issuance costs		16,621			13,753			940
Other interest and fees		—			—			—
Total interest cost		102,030			49,957			11,893
Capitalized interest		(11,820	)		(2,075	)		—
Total interest expense,	$	90,210		$	47,882		$	11,893

F-30

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

Note 9 – Accrued and Other Liabilities

The following table summarizes the Company’s accrued and other liabilities for the periods presented:

	December 31,
(in thousands)	2024		2023		2022
Accrued capital expenditures and lease operating expenses	$	37,150	$	1,373	$	959
Revenue payables		4,441		383		—
Accrued personnel costs		4,316		803		161
Advances from joint interest partners		4,105		1,785		—
Current derivative liabilities		2,537		—		2
Accrued interest		1,746		1,873		108
Unredeemed matured bonds		1,338		—		—
Asset retirement obligations		165		112		—
Other		1,549		59		1,006
Total	$	57,346	$	6,388	$	2,236

Accrued capital expenditures and lease operating expenses are primarily associated with drilling, completion and operating activities on wells operated by PhoenixOp. As of December 31, 2024, PhoenixOp had placed 32 wells into production and had an additional 39 wells in various stages of development.

In circumstances where the Company serves as the operator, the Company receives production proceeds from the purchaser and distributes the amounts to other royalty owners based on their respective ownership interests. Production proceeds that the Company has not yet distributed to these owners are reflected as revenue payables and classified as a component of accrued and other liabilities in the consolidated balance sheets. The Company recognizes revenue for only its net revenue interest in oil and natural gas properties.

Note 10 – Deferred Closings

Deferred closings represent agreements entered into by the Company with mineral interest owners that provide for the acquisition price to be paid in installments. Deferred closing arrangements have terms ranging from 11 to 48 months and interest rates ranging from 8.0% to 15.0% per annum. Interest is accrued on a quarterly basis.

The following table summarizes the aggregate annual contractual settlements for the Company’s deferred closing arrangements as of December 31, 2024:

(in thousands)
Year Ending December 31,	Amount
2025	$	7,189
2026		3,260
2027		64
2028		—
2029		—
Thereafter		—
Total	$	10,513

Note 11 – Equity-Based Compensation

In December 2024, the Company adopted the 2024 Long-Term Incentive Plan (the “2024 Incentive Plan”). Under the 2024 Incentive Plan, Phoenix Equity, the Company’s parent, may grant awards to service providers of the Company, which may be paid in units, cash, or other property, as determined by each individual award agreement. Unit awards may be granted with performance conditions and service conditions, depending on the individual award, and may be subject to vesting or other terms. Performance conditions are contingent on the specified

F-31

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

condition being met, whereby service conditions depend solely on the employee rendering service to the Company for the requisite service period as defined within each individual award agreement. The 2024 Incentive Plan provides for the issuance of Class A Units, Class B Units and Phantom Units of Phoenix Equity’s interests to service providers of the Company, including employees and independent contractors. Each of the Class A, B and Phantom Units are entitled to distributions to the extent such distributions are declared by Phoenix Equity. No distributions have been declared or paid to date. As of December 31, 2024, 0.9 million of Class A Units and 2.8 million of Class B Units were authorized and issued to employees, and 1.0 million Phantom Units were authorized but not yet issued.

The 2024 Incentive Plan superseded and replaced all prior incentive plans, and resulted in the cancellation and termination of any previously outstanding awards, wherein 2.4 million previously granted unit awards to 10 grantees were canceled and regranted. Regranted unit awards included updated terms and conditions, including updated performance and service vesting conditions. However, with respect to 289,290 Class A units and 249,460 Class B units, no new vesting conditions were added, and upon the cancellation and regrant, the Company recognized no additional equity-based compensation expense for these vested unit awards for the year ended December 31, 2024.

A summary of the activity under the 2024 Incentive Plan as of December 31, 2024, and changes during the year then ended, is presented below.

	Number of Units		Weighted Average Per Share Grant Date Fair Value
Nonvested at December 31, 2023		—	$	—
Granted - Class A Units		610,710		55.74
Granted - Class B Units		2,564,440		55.74
Vested		—		—
Forfeited		—		—
Nonvested at December 31, 2024		3,175,150

During the year ended December 31, 2024, Phoenix Equity granted 0.6 million Class A unit awared and 2.6 million Class B unit awards contingent on the achievement of a performance condition (the “performance unit awards”), all of which will only vest upon the Company undergoing a liquidity event (e.g., change in control). No compensation cost will be recognized for the performance unit awards until a liquidity event occurs. The Company has elected to account for forfeitures as they occur.

As of December 31, 2024, there was $177.0 million of total unrecognized compensation cost related to nonvested performance unit awards granted under the 2024 Incentive Plan, measured based on the fair value of the awards; that cost is expected to be recognized at the time a liquidity event occurs.

The fair value of each unit granted under the 2024 Incentive Plan was valued on the date of grant under an independent third-party valuation, which included a combination of an income approach, based on the present value of estimated future cash flows, and a market approach based on market data of comparable businesses. The weighted-average assumptions used in the valuation of performance unit awards granted for the year ended December 31, 2024, are presented in the table below:

	2024
Dividend yield(a)		—	%
Risk-free interest rate(b)		4.38	%
Expected volatility(c)		57.50	%
Expected term (in years)(d)		5.00
Discount for lack of marketability(e)		30.00	%

(a) The Company has no history or expectation of paying cash dividends on its awards.

(b) The risk-free interest rate is based on the U.S. Treasury yield for a term consistent with the expected life of the awards in effect at the time of grant.

(c) Volatility was estimated based on the different interests being appraised, leveraging historical volatility for comparable publicly traded organizations within its industry. The Company lacks company-specific historical and implied volatility information. Therefore, it estimates its expected stock volatility based on the historical volatility of a publicly traded set of peer companies within the industry with characteristics similar to the Company.

(d) The expected term represents the estimated period, in years, until a liquidity event occurs.

(e) Discount for lack of marketability was determined using the Restricted Stock Studies, Chaffee Put Option, Finnerty’s Put Option, and Qualitative Mandelbaum Factor approaches.

F-32

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

Note 12 – Related Parties

Debt Offerings

Certain of the Company’s executives and their family members participate in the Company’s unregistered debt offerings. During the years ended December 31, 2024, 2023, and 2022, these officers and their family members purchased, in aggregate, 4,458, 2,847 and 924 of the combined Regulation A+ and Regulation D bonds, respectively, for a total purchase price of $4.4 million, $2.8 million and $0.9 million. Interest expense attributable to these securities was $0.5 million, $0.2 million, and less than $1.0 million for the years ended December 31, 2024, 2023, and 2022, respectively. As of December 31, 2024, 2023, and 2022, there were 2,860, 2,055, and 759 of bonds outstanding with carrying values of $2.9 million, $2.0 million, and $0.8 million, respectively.

Lion of Judah

The Company paid interest expense of less than $0.2 million to a financial institution on behalf of Lion of Judah related to a certain financing agreement between Lion of Judah and the financial institution for the year ended December 31, 2024. No such payments were made in the prior periods. Interest payments made by the Company on behalf of Lion of Judah are discretionary in nature.

Note 13 – Leases

The Company leases its office facilities under noncancelable multi-year operating lease agreements. The Company determines whether a contract contains a lease at inception by determining if the contract conveys the right to control the use of identified office space for a period of time in exchange for consideration. The Company’s lease agreements contain lease and non-lease components, which are generally accounted for separately with amounts allocated to the lease and non-lease components based on relative stand-alone prices.

Right of use (“ROU”) assets and lease liabilities are recognized at the commencement date based on the present value of the future minimum lease payments over the lease term. Renewal and termination clauses that are factored into the determination of the lease term if it is reasonably certain that these options would be exercised by the Company. Lease assets are amortized over the lease term unless there is a transfer of title or purchase option reasonably certain of exercise, in which case the asset life is used. The Company’s lease agreements include variable payments. Variable lease payments not dependent on an index or rate primarily consist of common area maintenance charges and are not included in the calculation of the ROU asset and lease liability and are expensed as incurred. In order to determine the present value of lease payments, the Company uses the implicit rate when it is readily determinable or the Company’s incremental borrowing rate based on the Company’s existing line of credit facilities.

The Company’s lease agreements do not contain any material residual value guarantees or material restrictive covenants. As of December 31, 2024, the Company does not have leases where it is involved with the construction or design of an underlying asset, has no material obligation for leases signed but not yet commenced and does not have any material sublease activities.

F-33

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

The following table summarizes the Company’s future minimum lease payments as of December 31, 2024:

(in thousands)
Year Ending December 31,	Amount
2025	$	1,293
2026		1,328
2027		1,329
2028		1,262
2029		1,218
Thereafter		3,047
Total lease payments		9,477
Less: interest		(2,961	)
Present value of lease liabilities	$	6,516

The following table shows the line item classification of our right-of-use assets and lease liabilities on the Company’s consolidated balance sheets:

		December 31,
(in thousands)	Line item	2024			2023			2022
Right-of-use assets – operating	Right of use assets, net	$	6,010		$	4,542		$	1,798
Total right-of-use assets		$	6,010		$	4,542		$	1,798
Current operating lease liabilities	Current operating lease liabilities	$	656		$	567		$	305
Noncurrent operating lease liabilities	Operating lease liabilities		5,860			4,225			1,597
Total lease liabilities		$	6,516		$	4,792		$	1,902
Weighted average remaining lease term (in years)			7.16			6.29			5.43
Weighted average discount rate			10.29	%		9.16	%		9.16	%

	Year Ended December 31,
(in thousands)	2024		2023		2022
Operating leases(a)	$	1,393	$	1,168	$	211
Short-term leases(a)		—		138		232
Variable lease payments(a)		83		20		2
Net operating lease cost	$	1,476	$	1,326	$	445

(a) Expenses are classified within selling, general and administrative expense on the consolidated statements of operations.

Note 14 – Defined Contribution Plan

The Company has a 401(k) defined contribution plan which permits participating employees to defer up to a maximum of 100% of their compensation, subject to limitations established by the Internal Revenue Service. In January 2024, the Company began providing matching contributions of up to 3.0% of the employees’ compensation which vest ratably over a three-year period. The Company recognized compensation cost of $0.2 million related to its contributions to the plan for the year ended December 31, 2024.

F-34

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

Note 15 – Commitments and Contingencies

For a summary of the Company’s lease obligations, see Note 13 – Leases.

Litigation

From time to time, the Company may become involved in other legal proceedings or be subject to claims arising in the ordinary course of business. Although the results of ordinary course litigation and claims cannot be predicted with certainty, the Company currently believes that the final outcome of these ordinary course matters will not have a material adverse effect on its business, financial condition, results of operations or cash flows. Regardless of the outcome, litigation can have an adverse impact because of defense and settlement costs, diversion of management resources and other factors.

Drilling Rig Contracts

The Company has entered into drilling rig contracts to procure drilling services for wells operated by PhoenixOp. The contracts are short-term and provide a daily operating rate as consideration for services performed by the third-party provider. As of December 31, 2024, the Company was subject to $8.4 million of commitments under these contracts.

Crude Oil Delivery Commitments

The Company, through PhoenixOp, is subject to an arrangement pursuant to which it has committed to provide a total of 3.65 million barrels of crude oil, with a yearly minimum of 730,000 barrels of crude oil, from January 2024 to December 2028. The Company is subject to a shortfall fee in the event it fails to meet this commitment. No shortfalls have occurred to date. As a part of this arrangement, PhoenixOp has dedicated to the counterparty certain rights to all oil extracted from its wells in certain properties in North Dakota. The Company delivered 2.3 million barrels of crude oil during the year ended December 31, 2024, and the remaining aggregate commitment under the contract as of December 31, 2024 is approximately 1.4 million barrels of crude oil.

Note 16 – Supplemental Information to Consolidated Statements of Cash Flows

The following table summarizes supplemental information to the consolidated statements of cash flows for the periods presented:

	Year Ended December 31,
(in thousands)	2024		2023		2022
Supplemental disclosure of cash flow information:
Cash interest paid, net of capitalized interest	$	42,700	$	23,802	$	9,723
Cash paid for operating leases		927		569		188
Supplemental disclosure of non-cash transactions:
Capital expenditures in accounts payable and accrued and other liabilities	$	29,895	$	25,002	$	15,746
Modification of right-of-use asset and lease liability		1,608		—		—
Right-of-use asset obtained in exchange for lease liability		503		3,166		1,902

Note 17 – Segments

Segment operating profit is used as a performance metric by the CODM in determining how to allocate resources and assess performance as this measure provides insight into the segments’ operations and overall success of a segment for a given period. Segment operating profit is calculated as total segment revenue less operating costs attributable to the segment, which includes allocated corporate costs that are overhead in nature and not directly associated with the segments, such as certain general and administrative expenses, executive or shared-function payroll costs and certain limited marketing activities. Corporate costs are allocated to the segments based on usage

F-35

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

and headcount, as appropriate. Segment operating profit excludes other income and expense, such as interest expense, interest income, gain (loss) on derivatives, loss on debt extinguishment, even though these amounts are allocated to the segments and provided to the CODM. Transactions between segments are accounted for on an accrual basis and are eliminated upon consolidation. Interest expense is allocated to the segments based on the carrying value of the oil and gas properties owned by the respective segment at the balance sheet date, and interest income and gain (loss) on derivatives are allocated using the same basis as corporate costs.

The following table summarizes segment operating profit (loss) and reconciliation to net income (loss) for the periods presented:

	Year Ended December 31,
(in thousands)	2024			2023			2022
Segment operating profit
Mineral and Non-operating	$	43,499		$	49,018		$	23,248
Operating		44,145			(5,500	)		—
Securities		86,781			28,961			1,641
Eliminations		(102,030	)		(40,492	)		(4,991	)
Total segment operating profit		72,395			31,987			19,898
Interest income		705			66			—
Interest expense		(90,210	)		(47,882	)		(11,893	)
Loss on derivatives		(5,986	)		(32	)		(2,239	)
Loss on debt extinguishment		(1,697	)		(328	)		(92	)
Net income (loss)	$	(24,793	)	$	(16,189	)	$	5,674

F-36

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

The following tables present financial information by segment as of and for the years ended December 31, 2024, 2023, and 2022.

	Year Ended December 31,
(in thousands)	2024			2023			2022
Significant expenses
Mineral and Non-Operating
Cost of sales	$	30,236		$	19,265		$	9,573
Depreciation, depletion, amortization and accretion		50,607			34,193			12,144
Selling, general and administrative		14,463			6,813			3,712
Payroll and payroll-related		13,303			6,399			5,296
Other segment items(a)		—			—			—
Operating
Cost of sales	$	33,847		$	507		$	—
Depreciation, depletion, amortization and accretion		35,370			35			—
Selling, general and administrative		6,215			2,786			—
Payroll and payroll-related		8,550			3,157			—
Securities
Advertising and marketing	$	679		$	3,656		$	772
Selling, general and administrative		8,489			4,715			1,851
Payroll and payroll-related		6,081			3,178			726
Interest expense
Mineral and non-operating	$	63,782		$	40,688		$	11,893
Operating		26,428			7,194			—
Securities		102,030			40,492			4,991
Eliminations		(102,030	)		(40,492	)		(4,991	)
Total interest expense	$	90,210		$	47,882		$	11,893
Capital expenditures
Mineral and non-operating	$	352,358		$	231,285		$	91,888
Operating		252,074			47,376			—
Eliminations		(166,729	)		—			—
Total capital expenditures	$	437,703		$	278,661		$	91,888

(a) Other segment items include advertising and marketing expense, loss on sale of assets, and impairment expense.

	December 31,
(in thousands)	2024			2023			2022
Assets
Mineral and Non-operating	$	898,300		$	469,185		$	157,020
Operating		332,721			68,821			—
Securities		6,918			29,448			—
Eliminations		(208,869	)		(74,287	)		—
Total assets	$	1,029,070		$	493,167		$	157,020

F-37

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

The following table summarizes the Company’s oil and natural properties by proved and unproved properties, location and by segment (before accumulated depletion):

	December 31, 2024
(in thousands)	Mineral and Non-Operating		Operating		Securities		Eliminations		Consolidated Total
Oil and natural gas properties, proved
Williston Basin	$	184,740	$	351,864	$	—	$	—	$	536,604
Powder River Basin		47,780		—		—		—		47,780
Denver-Julesburg		45,193		—		—		—		45,193
Permian Basin		20,050		—		—		—		20,050
Marcellus		1,306		—		—		—		1,306
Uinta Basin		34,731		—		—		—		34,731
Other		1,702		—		—		—		1,702
Total proved properties	$	335,502	$	351,864	$	—	$	—	$	687,366
Oil and natural gas properties, unproved
Williston Basin	$	209,437	$	7,300	$	—	$	—	$	216,737
Powder River Basin		29,853		—		—		—		29,853
Denver-Julesburg		35,619		—		—		—		35,619
Permian Basin		6,752		—		—		—		6,752
Uinta Basin		28,045		—		—		—		28,045
Other		1,849		—		—		—		1,849
Total unproved properties	$	311,555	$	7,300	$	—	$	—	$	318,855

	December 31, 2023
(in thousands)	Mineral and Non-Operating		Operating		Securities		Eliminations		Consolidated Total
Oil and natural gas properties, proved
Williston Basin	$	189,651	$	60,372	$	—	$	—	$	250,023
Powder River Basin		38,536		—		—		—		38,536
Denver-Julesburg		46,781		—		—		—		46,781
Permian Basin		25,375		—		—		—		25,375
Uinta Basin		7,959		—		—		—		7,959
Other		2,951		—		—		—		2,951
Total proved properties	$	311,253	$	60,372	$	—	$	—	$	371,625
Oil and natural gas properties, unproved
Williston Basin	$	40,599	$	5,120	$	—	$	—	$	45,719
Powder River Basin		28,922		—		—		—		28,922
Denver-Julesburg		22,231		—		—		—		22,231
Permian Basin		1,001		—		—		—		1,001
Uinta Basin		8,379		—		—		—		8,379
Other		462		—		—		—		462
Total unproved properties	$	101,594	$	5,120	$	—	$	—	$	106,714

F-38

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

	December 31, 2022
(in thousands)	Mineral and Non-Operating		Operating		Securities		Eliminations		Consolidated Total
Oil and natural gas properties, proved
Williston Basin	$	70,794	$	—	$	—	$	—	$	70,794
Powder River Basin		27,569		—		—		—		27,569
Denver-Julesburg		15,536		—		—		—		15,536
Permian Basin		9,618		—		—		—		9,618
Other		10		—		—		—		10
Total proved properties	$	123,527	$	—	$	—	$	—	$	123,527
Oil and natural gas properties, unproved
Williston Basin	$	14,269	$	—	$	—	$	—	$	14,269
Powder River Basin		1,336		—		—		—		1,336
Denver-Julesburg		14,755		—		—		—		14,755
Permian Basin		8,911		—		—		—		8,911
Other		2,592		—		—		—		2,592
Total unproved properties	$	41,863	$	—	$	—	$	—	$	41,863

Note 18 – Subsequent Events

Management has evaluated subsequent events through March 26, 2025, in connection with the preparation of these consolidated financial statements, which is the date the consolidated financial statements were available to be issued. The Company has determined that there were no material such events that warrant disclosure or recognition in the consolidated financial statements, except for the following:

In January 2025, Phoenix Capital Group Holdings, LLC changed its name to Phoenix Energy One, LLC.

The Company is continuing to raise debt capital under its exempt debt offerings. Since the balance sheet date and through March 26, 2025, the Company issued approximately $107.6 million and $33.9 million of its Regulation D and Adamantium bonds, respectively, under the same terms and conditions as the existing securities.

Note 19 – Supplemental Information on Oil and Natural Gas Operations (unaudited)

Geographic Area of Operations

All of the Company’s proved reserves are located within the continental United States, with the majority concentrated in North Dakota, Montana, Utah, Texas, Colorado and Wyoming.

Costs Incurred in Oil and Natural Gas Property Acquisitions and Development Activities

Costs incurred in oil and natural gas property acquisition and development, whether capitalized or expensed, are presented below:

	Year Ended December 31,
(in thousands)	2024		2023		2022
Acquisition Costs of Properties
Proved	$	202,725	$	100,282	$	35,998
Unproved		311,555		83,432		43,359
Development Costs		418,493		70,933		37,691
Total	$	932,773	$	254,647	$	117,048

F-39

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

Property acquisition costs include costs incurred to purchase, lease or otherwise acquire a property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, and to provide facilities to extract, treat and gather natural gas.

Oil and Natural Gas Capitalized Costs

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization including impairments, are presented below:

	December 31,
(in thousands)	2024			2023			2022
Proved oil and natural gas properties	$	687,366		$	371,625		$	123,527
Unproved oil and natural gas properties		318,855			106,714			41,863
Total oil and gas properties		1,006,221			478,339			165,390
Less: Accumulated depletion and impairment		(140,376	)		(54,671	)		(20,635	)
Oil and gas properties, net	$	865,845		$	423,668		$	144,755

Oil and Natural Gas Reserve Information

The following table sets forth estimated net quantities of the Company’s proved developed oil and natural gas reserves. Estimated reserves for the periods presented are based on the unweighted average of first-day-of-the-month commodity prices over the period January through December for the year in accordance with definitions and guidelines set forth by the SEC and the FASB. For estimates of oil reserves, the average WTI spot oil prices used were $76.32, $78.21, and $94.14 per barrel as of December 31, 2024, 2023 and 2022, respectively. These average prices are adjusted for quality, transportation fees, and market differentials. For estimates of natural gas reserves, the average Henry Hub prices used were $2.130, $2.637, and $6.357 per MMBtu as of December 31, 2024, 2023 and 2022, respectively. These average prices are adjusted for energy content, transportation fees, and market differentials.

Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent the Company’s net revenue interest in its properties. Although the Company believes these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, production costs and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

F-40

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

Proved Developed and Undeveloped Reserves:	Oil (Bbls)			Natural Gas (Mcf)			Natural Gas Liquids (Bbls)			Total (BOE)(a)
As of December 31, 2021		2,105,157			3,972,925			—			2,767,311
Production		(523,416	)		(1,058,506	)		—			(699,834	)
Divestitures		—			—			—			—
Purchases of reserves in place		1,165,585			2,331,222			—			1,554,122
Extensions and discoveries		58,367			101,435			—			75,273
Revisions of previous estimates		886,029			2,277,136			—			1,265,552
As of December 31, 2022		3,691,722			7,624,212			—			4,962,424
Production		(1,446,928	)		(2,152,939	)		(201,454	)		(2,007,205	)
Divestitures		—			—			—			—
Purchases of reserves in place		1,078,682			1,077,933			168,207			1,426,545
Extensions and discoveries		28,697,688			25,945,687			7,407,103			40,429,072
Revisions of previous estimates		28,871			(678,800	)		789,652			705,390
As of December 31, 2023		32,050,035			31,816,093			8,163,508			45,516,225
Production		(3,830,461	)		(2,979,341	)		(415,363	)		(4,742,381	)
Divestitures		(66,654	)		(9,186	)		(3,702	)		(71,887	)
Purchases of reserves in place		580,118			1,922,022			147,354			1,047,809
Extensions and discoveries		20,123,921			13,465,004			2,108,197			24,476,286
Revisions of previous estimates		965,595			(5,903,628	)		(2,398,383	)		(2,416,726	)
As of December 31, 2024		49,822,554			38,310,963			7,601,611			63,809,326
Proved Developed Reserves
December 31, 2022		3,691,722			7,624,212			—			4,962,424
December 31, 2023		7,124,194			12,250,285			1,514,761			10,680,669
December 31, 2024		18,624,758			20,819,874			2,848,355			24,943,092
Proved Undeveloped Reserves(b)
December 31, 2022		—			—			—			—
December 31, 2023		24,925,841			19,565,808			6,648,747			34,835,556
December 31, 2024		31,197,795			17,491,089			4,753,257			38,866,233

(a) Estimated proved reserves are presented on an oil-equivalent basis using a conversion of six Mcf per barrel of “oil equivalent.” This conversion is based on energy equivalence and not price or value equivalence. If a price equivalent conversion based on the twelve-month average prices for the year ended December 31, 2024 was used, the conversion factor would be approximately 35.8 Mcf per Bbl of oil.

(b) In early 2023, PhoenixOp was established with the intention that certain leaseholds held by Phoenix Energy would be developed by PhoenixOp. PhoenixOp executed a contract for a drilling rig with Patterson-UTI Drilling Company in June 2023, which allowed for previously unbooked reserves to be estimated and booked as proved undeveloped in accordance with SEC guidelines for reserves categorization and estimation and in adherence to the five-year rule as set forth by the SEC.

At December 31, 2024, total estimated proved reserves were approximately 63,809,326 Boe, a 18,293,101 Boe net increase from the previous year end’s estimate of 45,516,225 Boe. Proved developed reserves of 24,943,092 Boe increased approximately 14,262,423 Boe from December 31, 2023 as a result of proved developed reserves acquisitions of 1,047,809 Boe, extensions of 3,268,997 Boe, and total positive revisions of previous estimates of 14,759,886 Boe, offset by divestitures of 71,887 Boe and production from proved developed reserves of 4,742,381 Boe. The total positive revisions of previous estimates comprised: (i) positive price revisions of 1,263 Boe; (ii) positive transfer of 14,871,911 Boe from proved undeveloped to proved developed reserves; (iii) negative well performance revisions of (481,161) Boe; (iv) positive revisions of 715,795 Boe due to interest changes; and (v) negative revisions of (347,922) Boe due to changes in lifting cost. Proved undeveloped reserves of 38,866,233 Boe increased approximately 4,030,677 Boe from December 31, 2023 as a result of proved undeveloped reserves extensions of 21,207,289 and total negative revisions of previous estimates of 17,176,612 Boe. The total negative revisions of previous estimates comprised: (i) positive price revisions of 48,935 Boe,; (ii) negative transfer of (14,871,911) Boe from proved undeveloped to proved developed reserves; and (iii) negative well performance revisions of (2,353,636) Boe due to asset development reconfiguration and type curve adjustments. During the year

F-41

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

ended December 31, 2024, approximately $450.0 million in capital expenditures went toward the acquisition and development of proved developed reserves, which includes drilling, completion, and other facility costs associated with acquiring and developing wells. All proved undeveloped reserves disclosed as of December 31, 2024 are scheduled to be converted to proved developed status within five years of initial disclosure.

At December 31, 2023, total estimated proved reserves were approximately 45,516,225 Boe, a 40,553,802 Boe net increase from the previous year end’s estimate of 4,962,424 Boe. Proved developed reserves of 10,680,669 Boe increased approximately 5,718,245 Boe from December 31, 2022 as a result of proved developed reserves acquisitions of 1,426,545 Boe, extensions of 5,682,894 Boe, and total positive revisions of previous estimates of 616,010 Boe, offset by production from proved reserves of 2,007,205 Boe. The total positive revisions of previous estimates comprised: (i) negative price revisions of (13,622) Boe, (ii) transfer of (89,378) Boe from proved developed to proved undeveloped due to previous misclassifications of reserve, (iii) positive well performance revisions of 515,938 Boe, and (iv) positive revisions of 203,072 Boe due to changes in lifting cost. Proved undeveloped reserves of 34,835,556 Boe increased approximately 34,835,556 Boe from December 31, 2022 as a result of revisions due to previous misclassification of 89,378 Boe of reserves as proved developed reserves and due to the addition of 34,746,179 Boe of operated proved undeveloped reserves stemming from the signing of a drilling rig contract in June 2023. During the year ended December 31, 2023, approximately $171.2 million in capital expenditures went toward the acquisition and development of proved developed reserves, which includes drilling, completion, and other facility costs associated with acquiring and developing wells. At December 31, 2022, there were no proved undeveloped reserves and therefore all capital expenditures for the year ended December 31, 2023 were related to the development of non-proved reserves or the acquisition of proved developed reserves.

At December 31, 2022, total estimated proved reserves were approximately 4,962,424 Boe, a 2,195,112 Boe net increase from the estimate of 2,767,312 Boe at December 31, 2021. Proved developed reserves of 4,962,424 Boe represented an increase of approximately 2,195,112 Boe from December 31, 2021 as a result of proved developed reserves acquisitions of 1,554,122 Boe, extensions of 75,272 Boe, and total positive revisions of previous estimates of 1,265,552 Boe, offset by production of 699,834 Boe. The total positive revisions of previous estimates comprised: (i) positive price revisions of 524,667 Boe and (ii) positive well performance revisions of 740,885 Boe. During the year ended December 31, 2022, approximately $117.1 million in capital expenditures went toward the acquisition and development of proved reserves, which includes drilling, completion, and other facility costs associated with acquiring and developing wells.

Standardized Measure of Discounted Future Net Cash Flows

Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the 12-month unweighted average of first-day-of-the-month commodity prices for the periods presented. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials. Future cash inflows are computed by applying applicable prices relating to the Company’s proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions.

	Year Ended December 31,
(in thousands)	2024			2023			2022
Future cash inflows	$	3,626,615		$	2,427,554		$	381,493
Future development costs		(779,533	)		(619,680	)		—
Future production costs		(998,851	)		(681,730	)		(74,897	)
Future net cash flows		1,848,231			1,126,144			306,596
Less 10% annual discount to reflect timing of cash flows		(779,539	)		(578,863	)		(116,711	)
Standard measure of discounted future net cash flows	$	1,068,692		$	547,281		$	189,885

F-42

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Consolidated Financial Statements

Changes in the Standardized Measure for Discounted Cash Flows

(in thousands)	2024			2023			2022
Beginning of the year	$	547,281		$	189,885		$	96,636
Net change in sales and transfer prices and in production (lifting) costs related to future production		13,353			(49,785	)		—
Changes in the estimated future development costs		—			—			—
Sales and transfers of oil and gas produced during the period		(289,138	)		(118,105	)		(57,563	)
Net change due to extensions, discoveries, and improved recovery		261,832			416,822			3,134
Net change due to purchases and sales of minerals in place		26,301			36,562			57,622
Net change due to revisions in quantity estimates		189,962			2,519			83,101
Previously estimated development costs incurred during the period		106,214			—			—
Accretion of discount		212,886			69,383			6,955
End of the year	$	1,068,692		$	547,281		$	189,885

The data presented in this note should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a significant amount of estimations and assumptions. The required projection of production and related expenditures overtime requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from historical prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.

F-43

Item 8. Exhibits

Exhibit Number	Exhibit Description+
(2)(a)*	Certificate of Formation of Phoenix Capital Group Holdings, LLC (incorporated by reference to Exhibit (2)(a) to the Company’s Offering Statement on Form 1-A (File No. 024-11723), filed with the SEC on November 19, 2021)
(2)(b)*	Certificate of Amendment to the Certificate of Formation of Phoenix Energy One, LLC, dated as of January  23, 2025 (incorporated by reference to Exhibit 99.1 to the Company’s Form 1-U, filed with the SEC on January 27, 2025)
(2)(c)*	Second Amended and Restated Limited Liability Company Agreement of Phoenix Energy One, LLC, dated as of January  23, 2025 (incorporated by reference to Exhibit 99.2 to the Company’s Form 1-U, filed with the SEC on January 27, 2025)
(3)(a)*	Form of Indenture between Phoenix Capital Group Holdings, LLC and UMB Bank, N.A., as trustee, dated as of January  12, 2022 (incorporated by reference as Exhibit (3)(a) to the Company’s Form 1-U, filed with the SEC on January 12, 2022)
(3)(b)*	Form of Bond, as of May 25, 2023 (incorporated by reference to Exhibit (3)(b) to Post Qualification Amendment No.  2 to the Company’s Offering Statement on Form 1-A (File No. 024-11723), filed with the SEC on May 26, 2023)
(3)(c)*	Supplemental Indenture between Phoenix Capital Group Holdings, LLC and UMB Bank, N.A., as trustee, dated as of February 1, 2022 (incorporated by reference as Exhibit (3)(a) to the Company’s Form 1-U, filed with the SEC on February 8, 2022)
(3)(d)*	Second Supplemental Indenture between Phoenix Capital Group Holdings, LLC and UMB Bank, N.A., as trustee, dated as of July 18, 2022 (incorporated by reference as Exhibit (3)(a) to the Company’s Form 1-U, filed with the SEC on July 21, 2022)
(3)(e)*	Third Supplemental Indenture between Phoenix Capital Group Holdings, LLC and UMB Bank, N.A., as trustee, dated as of May 25, 2023 (incorporated by reference to Exhibit (3)(e) to Post Qualification Amendment No. 2 to the Company’s Offering Statement on Form 1-A (File No. 024-11723), filed with the SEC on May 26, 2023)
(3)(f)	Form of Adamantium Bond.
(3)(g)	Form of 2020 506(b) Bond and 2020 506(c) Bond.
(3)(h)	Form of July 2022 506(c) Bond.
(3)(i)	Form of December 2022 506(c) Bond (Series AAA through Series D-1).
(3)(j)	Indenture, by and between Phoenix Capital Group Holdings, LLC and UMB Bank, N.A., as trustee, dated as of August 25, 2023, governing the August 2023 506(c) Bonds.
(3)(k)	Form of August 2023 506(c) Bond (Series U through Series Z-1).
(3)(l)	First Supplemental Indenture, by and between Phoenix Capital Group Holdings, LLC and UMB Bank, N.A., as trustee, dated as of August 20, 2024.
(3)(m)	Form of August 2023 506(c) Bond (Series AA through Series JJ-1) (included in Exhibit (3)(l)).
(3)(n)	Second Supplemental Indenture, by and between Phoenix Capital Group Holdings, LLC and UMB Bank, N.A., as trustee, dated as of October 17, 2024.
(4)*	Subscription Agreement (incorporated by reference to Exhibit (4) to the Company’s Offering Statement on Form 1-A (File No. 024-11723), filed with the SEC on November 19, 2021).
(6)(a)*	Security Agreement, by and between Phoenix Capital Group Holdings, LLC and Amarillo National Bank, LLC, dated as of July  24, 2023 (incorporated by reference to Exhibit (6)(d) to Post Qualification Amendment No.  4 to the Company’s Offering Statement on Form 1-A (File No. 024-11723), filed with the SEC on August 8, 2023).
(6)(b)*	Commercial Credit Agreement by and between Phoenix Capital Group Holdings, LLC and Amarillo National Bank, LLC, dated as of July 24, 2023 (incorporated by reference to Exhibit (6)(e) to Post Qualification Amendment No. 4 to the Company’s Offering Statement on Form 1-A (File No. 024-11723), filed with the SEC on August 8, 2023).
(6)(c)*	Promissory Note, by and between Phoenix Capital Group Holdings, LLC and Amarillo National Bank, LLC, dated as of July  24, 2023 (incorporated by reference to Exhibit (6)(e) to Post Qualification Amendment No.  4 to the Company’s Offering Statement on Form 1-A (File No. 024-11723), filed with the SEC on August 8, 2023).
(6)(d)*	Form of Line of Credit Loan Agreement dated as of June 1, 2023 by and between Phoenix Capital Group Holdings, LLC and Phoenix Capital Group Holdings I LLC (incorporated by reference to Exhibit (6)(g) to Post Qualification Amendment No. 4 to the Company’s Offering Statement on Form 1-A (File No. 024-11723), filed with the SEC on August 8, 2023).
(6)(e)†++	Second Amended and Restated Limited Liability Company Agreement of Phoenix Equity Holdings, LLC, dated as of December 4, 2024.
(6)(f)†	Unit Award Agreement, by and between Phoenix Equity Holdings, LLC and Curtis Allen, dated as of December 4, 2024.
(6)(g)†	Unit Award Agreement, by and between Phoenix Equity Holdings, LLC and Sean Goodnight, dated as of December 4, 2024.
(6)(h)†	Commission Agreement, by and between by and between Phoenix Capital Group Holdings, LLC and Sean Goodnight, dated as of June 12, 2020.

Exhibit Number	Exhibit Description
(6)(i)†	Employee Agreement, by and between Phoenix Equity Holdings, LLC and Adam Ferrari, effective as of January 1, 2025.
(6)(j)†	Employee Agreement, by and between Phoenix Equity Holdings, LLC and Curtis Allen, effective as of January 1, 2025.
(6)(k)†	Employee Agreement, by and between Phoenix Equity Holdings, LLC and Lindsey Wilson, effective as of January 1, 2025.
(6)(l)†	Employee Offer Letter, by and between Phoenix Operating LLC and Brandon Allen, dated as of March 2, 2023.
(6)(m)†++	Employee Offer Letter, by and between Phoenix Capital Group Holdings, LLC and Sean Goodnight, dated as of June 12, 2020.
(6)(n)†	2024 Long-Term Incentive Plan of Phoenix Equity Holdings, LLC.
(6)(o)†	Form of Unit Award Agreement of Phoenix Equity Holdings, LLC.
(6)(p)†	Form of Phantom Unit Award Agreement of Phoenix Equity Holdings, LLC.
(6)(q)†	Performance Bonus Amendment, by and among Phoenix Operating LLC, Phoenix Capital Group Holdings, LLC, and Brandon Allen, dated as of January 22, 2025.
(6)(r)*	Loan Agreement between Adamantium Capital, LLC and Phoenix Capital Group Holdings, LLC, dated September  14, 2023 (incorporated by reference to Exhibit (6)(j) to Post Qualification Amendment No.  9 to the Company’s Offering Statement on Form 1-A (File No. 024-11723), filed with the SEC on November 13, 2023).
(6)(s)*	Amended and Restated Broker-Dealer Agreement between Phoenix Capital Group Holdings I, LLC, Phoenix Capital Group Holdings, LLC, and Dalmore Group, LLC, dated June 5, 2023 (incorporated by reference to Exhibit (6)(k) to Post Qualification Amendment No. 5 to the Company’s Offering Statement on Form 1-A, filed with the SEC on September 6, 2023).
(6)(t)*	Broker-Dealer Agreement between Adamantium Capital, LLC, Phoenix Capital Group Holdings, LLC, and Dalmore Group, LLC, dated September  11, 2023 (incorporated by reference to Exhibit (6)(l) to Post Qualification Amendment No. 7 to the Company’s Offering Statement on Form 1-A (File No. 024-11723), filed with the SEC on November 13, 2023).
(6)(u)*	Loan Agreement Amendment and Note Modification Agreement, by and between Phoenix Capital Group Holdings, LLC, Phoenix Operating, LLC, and Adamantium Capital, LLC, dated October 30, 2023 (incorporated by reference to Exhibit (6)(m) to Post Qualification Amendment No. 7 to the Company’s Offering Statement on Form 1-A (File No. 024-11723), filed with the SEC on November 13, 2023).
(6)(v)*	First Amendment to Commercial Credit Agreement, by and among Phoenix Capital Group Holdings, LLC, Phoenix Operating, LLC, and Amarillo National Bank, dated as of July 24, 2024.(incorporated by reference to Exhibit 99.1 to the Company’s Form 1-U, filed with the SEC on July 26, 2024).
(6)(w)*	Modification of Promissory Note, by and among Phoenix Capital Group Holdings, LLC, Phoenix Operating, LLC, and Amarillo National Bank, dated as of July 24, 2024 (incorporated by reference to Exhibit 99.2 to the Company’s Form 1-U, filed with the SEC on July 26, 2024).
(6)(x)*	Second Amendment to Loan Agreement, by and among Phoenix Capital Group Holdings, LLC, Phoenix Operating LLC, and Adamantium (incorporated by reference to Exhibit 99.1 to the Company’s Form 1-U, filed with the SEC on December 18, 2024).

Exhibit Number	Exhibit Description
(6)(y)	Third Amendment to Loan Agreement, by and among Phoenix Capital Group Holdings, LLC, Phoenix Operating LLC, and Adamantium Capital LLC, dated as of January 3, 2025.
(6)(z)	Fourth Amendment to Loan Agreement, by and among Phoenix Energy One, LLC, Phoenix Operating LLC, and Adamantium Capital LLC, dated as of January 24, 2025.
(6)(aa)*++	Amended and Restated Senior Credit Agreement, by and among Phoenix Capital Group Holdings, LLC, Phoenix Operating LLC, each of the lenders from time to time party thereto, and Fortress Credit Corp., dated as of August 12, 2024 (incorporated by reference to Exhibit 99.1 to the Company’s Form 1-U, filed with the SEC on August 16, 2024)
(6)(bb)*	Assignment of Loans and Liens, by and among Phoenix Capital Group Holdings, LLC, Phoenix Operating LLC, Amarillo National Bank, and Fortress Credit Corp., as administrative agent, collateral agent, and lender, dated as of August 12, 2024 (incorporated by reference to Exhibit 99.2 to the Company’s Form 1-U, filed with the SEC on August 16, 2024).
(6)(cc)*	Limited Waiver and Amendment No.  1 to Amended and Restated Senior Credit Agreement, by and among Phoenix Capital Group Holdings, LLC, Phoenix Operating LLC, each of the lenders from time to time party thereto, and Fortress Credit Corp., dated as of October 25, 2024.
(6)(dd)*	Amendment No.  2 to Amended and Restated Senior Credit Agreement, by and among Phoenix Capital Group Holdings, LLC, Phoenix Operating LLC, each of the lenders from time to time party thereto, and Fortress Credit Corp., dated as of November 1, 2024.
(6)(ee)*++	Amendment No.  3 to Amended and Restated Senior Credit Agreement, by and among Phoenix Capital Group Holdings, LLC, Phoenix Operating LLC, each of the lenders from time to time party thereto, and Fortress Credit Corp., dated as of December  18, 2024 (incorporated by reference to Exhibit 99.1 to the Company’s Form 1-U, filed with the SEC on December 20, 2024)
(9)(a)*	Letter from Cherry Bekaert LLP (incorporated by reference to Exhibit 99.2 to the Company’s Current Report on Form 1-U, filed with the SEC on December 5, 2023)
(11)(a)	Consent of Ramirez Jimenez International CPAs.

* Previously filed.

+ Capitalized terms have the meanings assigned to them in the prospectus contained in this Registration Statement.

++ Certain annexes, schedules, and exhibits to this Exhibit have been omitted. The Company hereby agrees to furnish a supplemental copy of any omitted annex, schedule, or exhibit to the U.S. Securities and Exchange Commission upon request.

† Management contract or compensatory plan or arrangement.

SIGNATURES

Pursuant to the requirements of Regulation A, the Company has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized.

Phoenix Energy One, LLC, a Delaware limited liability company
By:	/s/ Curtis Allen
Name:	Curtis Allen
Title:	Chief Financial Officer
Date:	April 1, 2025

By:	/s/ Adam Ferrari
Name:	Adam Ferrari
Its:	Chief Executive Officer (Principal Executive Officer)
Date:	April 1, 2025
By:	/s/ Curtis Allen
Name:	Curtis Allen
Its:	Chief Financial Officer (Principal Financial and Accounting Officer)
Date:	April 1, 2025