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An offering statement pursuant to Regulation A relating to these securities has been filed with the Securities and Exchange Commission. Information contained in this Preliminary Offering Circular is subject to completion or amendment. These securities may not be sold nor may offers to buy be accepted before the offering statement filed with the Commission is qualified. This Preliminary Offering Circular shall not constitute an offer to sell or the solicitation of an offer to buy nor may there be any sales of these securities in any state in which such offer, solicitation or sale would be unlawful before registration or qualification under the laws of any such state. We may elect to satisfy our obligation to deliver a Final Offering Circular by sending you a notice within two business days after the completion of our sale to you that contains the URL where the Offering Circular was filed and may be obtained.

Preliminary Offering Circular

October 28, 2021

Universe Energy Partners, LP

Premier Place
5910 North Central Expressway Suite 370
Dallas, Texas 75206

(972) 885-6799

$50,000,000 Aggregate Maximum Offering Amount
2,000 Units of Limited and Additional General Partnership Interest

Universe Energy Partners, LP, (the “Partnership”), a Texas limited partnership, is offering a maximum of $50,000,000, in the aggregate, of Units of Limited and Additional General Partnership Interests (each, a “Unit,” and collectively, the “Units”) pursuant to this offering circular. The purchase price per Unit is $25,000, with a minimum purchase amount of $10,000 (0.40 Unit); however, we, in our sole discretion, reserve the right to accept smaller purchase amounts. We expect to commence the sale of the Units as of the date on which the offering circular is declared qualified by the United States Securities and Exchange Commission, (the “SEC”), and the Units will be offered for a period of one year thereafter, provided that, the managing general partner may extend the offering, in its sole discretion, for one or more periods not to exceed twelve months in total. Upon our acceptance of $500,000 in subscriptions (20 Units) that meet the requirements described herein, investors will be admitted as limited or additional general partners in the Partnership (the limited partners, together with the additional general partners, the “investor partners”). All investor partners will be obligated to enter into a limited partnership agreement in substantially the form described herein and provided as Exhibit (1)(b) to the Offering Circular.

The Partnership was formed to acquire interests in various oil and gas mineral rights, leases, producing wells, and drilling opportunities (the “Prospects,” and individually a “Prospect”), currently owned by our affiliate, Energy Production Corporation. The Prospects are expected to be located primarily in the Electra Arch Field in Wilbarger County, Texas; Big Lake Field, in Reagan County, Texas; and the Polar Bear Field in West Baton Rouge Parish, Louisiana. The Partnership may also acquire Prospects in other locations, which may be owned by unrelated third parties and/or our affiliates. Universe Energy, LLC (the “Managing General Partner”) will serve as its managing general partner of the Partnership. See the “Proposed Activities”.

The primary purpose of the Partnership will be to generate revenue from the production of oil and gas and to distribute cash to its partners. The investment objectives of the Partnership are to: (1) acquire interests in Prospects as described herein, (2) provide partners tax deductions for IDC, equipment costs, depletion and depreciation and (3) provide cash distributions to its partners derived from production of oil and gas. However, there can be no assurance that the Partnership’s investment objectives will be achieved.

Investment in this Partnership is speculative and involves a high degree of risk and should be made only by persons able to bear the risk of and to withstand the total loss of their investment. Before buying Units, you should consider carefully the risk factors beginning on page 5 of this offering circular, including:

· You may not be able to evaluate any of the Prospects or Prospect properties before making your investment decision · Oil and natural gas investments are highly risky · Additional general partners have unlimited liability for Partnership obligations · the Partnership returns may be affected by dry holes · The partnership agreement prohibits your participation in the Partnership’s business decisions · Cash distributions are not guaranteed · Prices of oil and natural gas are unstable · Your ability to resell your Units is limited due to the lack of a public market and restrictions contained in the partnership agreement · We and our affiliates may have conflicts of interest with you and the Partnership · We are not an investment company and are not required to register under the Investment Company Act of 1940; therefore, investors will not receive the protections of such act.

Generally, no sale may be made to you in the offering if the aggregate purchase price you pay is more than 10% of the greater of your annual income or net worth. Different rules apply to accredited investors and non-natural persons. Before making any representation that your investment does not exceed applicable thresholds, we encourage you to review Rule 251(d)(2)(i)(C) of Regulation A. For general information on investing, we encourage you to refer to www.investor.gov.

THE UNITED STATES SECURITIES AND EXCHANGE COMMISSION DOES NOT PASS UPON THE MERITS OF OR GIVE ITS APPROVAL TO ANY SECURITIES OFFERED OR THE TERMS OF THE OFFERING, NOR DOES IT PASS UPON THE ACCURACY OR COMPLETENESS OF ANY OFFERING CIRCULAR OR OTHER SOLICITATION MATERIALS. THESE SECURITIES ARE OFFERED PURSUANT TO AN EXEMPTION FROM REGISTRATION WITH THE COMMISSION; HOWEVER, THE COMMISSION HAS NOT MADE AN INDEPENDENT DETERMINATION THAT THE SECURITIES OFFERED ARE EXEMPT FROM REGISTRATION.

FORM 1-A DISCLOSURE FORMAT IS BEING FOLLOWED.

NOTICES TO INVESTORS

You should not construe the contents of this offering circular or any prior or subsequent communication from the Partnership, or us, our affiliates, or any person associated with this offering, as legal, financial, tax or investment advice. Instead, you should consult with your own personal legal counsel, business and/or tax adviser as to legal, tax, financial and related matters concerning an investment in the Units and its suitability for you and your particular circumstances.

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The purchase of the securities offered by this offering circular may be suitable for you only if you have substantial financial resources, do not anticipate that you will be required to liquidate any portion of your investment in the Units in the foreseeable future, understand or have been advised of the risk factors associated with this investment, are familiar with the nature and risks attendant to investments in oil and gas funds and have determined that the purchase of the securities is consistent with your projected income and investment objectives. You will be required to represent and warrant to us, in writing, in the subscription documents that the above facts and circumstances are true, you are purchasing the securities for investment only and not with a view toward resale and that you have individually, or together with your purchaser representative, the requisite knowledge, experience and skill in business and financial matters to be capable of evaluating the merits and risks of making an investment in the Partnership. See “Risk Factors” and “Terms of the Offering – Investor Suitability.”

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Along with our advisors and affiliates, we have prepared certain statements, estimates and projections that are included in or accompany this offering circular for the limited purpose of evaluating the Partnership’s proposed business plan, in which we may illustrate, under certain limited assumptions, the results of the Partnership’s projected operations. Although these projections may be presented with numerical specificity, they are based on assumptions that are subject to significant business, economic, political, regulatory and competitive uncertainties and contingencies, all of which are difficult to predict and many of which are beyond the control of the Managing General Partner, and its affiliates and advisors. These assumptions are based on future business decisions that are subject to change. Therefore, we cannot assure you that the projections or their underlying assumptions will be realized. As a result, actual results of operations can be materially different from those shown. UNDER NO CIRCUMSTANCES SHOULD THE INCLUSION OF THE PROJECTIONS BE REGARDED AS A REPRESENTATION, WARRANTY OR PREDICTION BY MANAGING GENERAL PARTNER OR ANY OTHER PERSON WITH RESPECT TO THE ACCURACY THEREOF OR THE ACCURACY OF THE UNDERLYING ASSUMPTIONS, OR THAT THE PARTNERSHIP WILL ACHIEVE OR IS LIKELY TO ACHIEVE ANY PARTICULAR RESULTS. THERE CAN BE NO ASSURANCE THAT THE PARTNERSHIP’S ACTUAL FUTURE RESULTS WILL NOT VARY MATERIALLY FROM THE PROJECTIONS. We caution you not to place undue reliance on projections. Our accountants have not compiled or examined these projections and, accordingly, they do not express an opinion or any other form of assurance on them. See “Forward-Looking Statements.”

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This offering circular does not constitute an offer or a solicitation to anyone in any state or other jurisdiction in which such an offer or solicitation is not authorized. Acceptance of your subscription for Units will be made only after we determine that a prospective investor satisfies the requirements for an exemption from federal and state registration requirements and the investor suitability standards set forth in “TERMS OF THE OFFERING – Investor Suitability.”

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We will provide, prior to the consummation of the transactions contemplated by this offering circular, the opportunity to ask questions of, and receive answers from, us or any person acting on our behalf concerning the terms and conditions of this offering, and will make available any additional information, to the extent we possess such information or can acquire it without unreasonable effort or expense, necessary to verify the accuracy of the information described in this offering circular. All documents referenced in or attached to this offering circular and all of our non-proprietary or non-confidential books and records will be available for inspection by you or your representative at our offices. See “ACCESS TO INFORMATION.”

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Certain of the statements and information contained in this offering circular are summaries and are qualified in their entirety by the documents included as exhibits to and/or described in this offering circular. Consequently, you must carefully read the documents included and/or described in this offering circular before making a decision to invest.

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The execution of a subscription agreement by you constitutes your unconditional obligation to purchase the Units. You will not have the right to withdraw your subscription, except as state law may require. We reserve the right to reject any subscription for any reason, and the sale of any Units will not be deemed to have occurred until we have accepted an investor’s subscription and fully executed a counterpart of the subscription agreement. If for any reason, we do not accept your offer to purchase Units, we will promptly return your subscription without interest.

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The securities offered by this offering circular have not been registered under the Securities Act with the Commission or under the securities laws of any state with the relevant regulatory or administrative agency, in reliance upon one or more exemptions from the registration requirements of such act and laws. Any representation to the contrary is unlawful. The securities offered by this offering circular may not be resold or otherwise transferred unless such transfer is registered pursuant to the Securities Act and any applicable state securities laws or unless, in the opinion of our counsel, such registration is not required. Accordingly, you must continue to bear the economic risk of an investment in the securities for an indefinite period of time.

TABLE OF CONTENTS

THIS OFFERING CIRCULAR CONTAINS ALL OF THE REPRESENTATIONS BY THE COMPANY CONCERNING THIS OFFERING, AND NO PERSON SHALL MAKE DIFFERENT OR BROADER STATEMENTS THAN THOSE CONTAINED HEREIN. INVESTORS ARE CAUTIONED NOT TO RELY UPON ANY INFORMATION NOT EXPRESSLY SET FORTH IN THIS OFFERING CIRCULAR.

Summary

This summary highlights some information contained in this Offering Circular. It is not complete and may not contain all of the information that is important to you. To understand this offering fully, you should carefully read the entire Offering Circular as well as the exhibits. For a discussion of matters that should be considered in evaluating an investment in the Units, see “RISK FACTORS.” References to “we,” “our,” “us” and similar terms refer to Universe Energy, LLC.

About the Partnership

The Partnership was recently formed to acquire interests in various oil and gas mineral rights, leases, producing wells, and drilling opportunities (the “Prospects,” and individually a “Prospect”), currently owned by our affiliate, Energy Production Corporation. The Prospects are expected to be located primarily in the Electra Arch Field in Wilbarger County, Texas; Big Lake Field, in Reagan County, Texas; and the Polar Bear Field in West Baton Rouge Parish, Louisiana. The Partnership may also acquire Prospects in other locations, which may be owned by unrelated third parties and/or our affiliates. Universe Energy, LLC (the “Managing General Partner”) will serve as the managing general partner of the Partnership. See the “Proposed Activities” section of this offering circular.

The Partnership Prospects currently identified and discussed in the offering circular are three specified large oil and gas fields which are producing from conventional reservoir rock situated on large anticline structures. These Prospects were discovered and/or extended beginning in 1974 with a 38-year partnership between E.R. Carpenter Chemical Company and Energy Production Corporation. These Prospects are conventional reservoir rock and do not require non-conventional (shale and limited permeability rock) expensive extraction methods like fracking. The identified Prospects’ finding and development costs range from $4-15 per barrel of oil and $0.50-$1.00 per MCF/natural gas from the conventional rock. The expensive extraction methods required by non-conventional reservoir rock, primarily hydraulic fracking, have been deemed by many to be harmful to the environment. These Prospects are expected to require only each reservoir’s natural pressure to extract the oil and gas. Historically, conventional oil and gas rock has generally been deemed superior to non-conventional rock in ultimate recovery of “original oil and gas in place” and finding and development costs, with the additional benefit of less environmental harm expected than the extraction methods of non-conventional extraction methods such as fracking, thus resulting in an anticipated reduced carbon footprint for the Partnership’s operations.

The Partnership intends to primarily utilize wind and solar generated electricity by contracting with Reliant Energy to furnish the electric power needed for drilling and producing oil and gas wells with the goal of reducing the carbon impact of the Partnership’s operations. Although the Partnership intends to focus on the above green energy technologies, it is not prohibited from, and may still engage in, drilling and production activities that do not employ green energy technologies.

We intend for our affiliate, EPCO, to serve as the operator of most, if not all, of the wells to be drilled in Prospects acquired by the Partnership. We will evaluate all prospective acquisitions on the basis of their oil and gas producing potential and the estimated acquisition, drilling and completion costs of all Prospect wells. In addition, the Prospects may be selected based on well drilling proposals from non-affiliated operators. Prospects subject to one or more operating agreements with non-affiliated operators engaged to conduct and direct operations for the Prospects and the Partnership may enter into one or more operating agreements with one or more of our affiliates and non-affiliated operators for the same purpose. The operators will be responsible for overseeing all drilling, testing and completion operations for Prospects covered by the operating agreement. For wells that have been completed and put into production, the operator will be responsible for selling the oil and natural gas production from that Prospect. The operator may also nominate future wells to be drilled on a Prospect property where applicable.

As soon as practical following the break of escrow for this offering, the Partnership plans to acquire Prospects as described in the “PROPOSED ACTIVITIES“ section of this offering circular, and on such other terms as may be determined by us in our sole discretion. Until the amount of funds available for the Partnership’s proposed activities is determined and all potential Prospects are identified, the precise number of Prospects cannot be determined and the drilling and acquisition budget cannot be formulated.

Universe Energy, LLC, a newly formed entity, is the initial managing general partner of the Partnership. Although the Managing General Partner has a limited operating history, Joe Vaughan the sole member and one of the managers of the Managing General Partner, and his son, David Vaughan, who also serves as a manager of the Managing General Partner have spent the majority of their careers in the oil and gas industry. See “Management.” Prior performance is not indicative of future returns and you should not assume that the Partnership will experience returns similar to those experienced by investors in any other partnership.

Investment Objectives

This section summarizes the investment objectives of the Partnership. For reasons we discuss in this offering circular, including those set forth under the section entitled “RISK FACTORS,” we cannot guarantee that the Partnership will meet its objectives, and as a result, you may not realize some or all of the benefits discussed below. Investment in the Partnership is speculative and involves a high degree of risk. You should only invest if you can afford the loss of your entire investment.

While we cannot guarantee that the Partnership will achieve the following investment objectives, the Partnership is intended to produce the following benefits for its partners:

•       Cash distributions from the sale of oil and natural gas. If the Partnership’s revenues exceed its expenses, you will receive periodic distributions of the Partnership’s cash profits. We expect that cash distributions to the partners will begin approximately six months after the Partnership acquires the Prospects and be made monthly thereafter. The amount of distributions will depend primarily on the Partnership’s net cash receipts from oil and gas operations, and will be affected, among other things, by the price of oil and natural gas and the level of production of the Partnership’s properties. During the period in which this offering is open, the Partnership will estimate cost depletion for each of the Partnership’s producing properties and withhold such amount from monthly distributions. This withheld cost depletion may be re-invested in the activities of the Partnership or, after completion of this offering, distributed to the partners.

•       Tax deductions for intangible drilling costs, equipment costs, depletion and depreciation. As a partner in the Partnership, you may be entitled to deductions for intangible drilling costs (“IDC”), which would reduce your taxable income from the Partnership’s operations during the year in which the Partnership well is drilled or potentially earlier when the IDC is paid. See “Tax Considerations – Classification of Relationship with Other Working Interest Holders; IDC” and “Prior Activities.” In addition, you may be entitled to tax deductions for depletion and depreciation, which will also reduce your taxable income from the Partnership’s operations. See “TAX Considerations – Classification of Relationship with Other Working Interest Holders; Depletion” and “Tax Considerations – Depreciation.” For a number of years, there have been proposals before Congress that would change some of the U.S. federal income tax rules applicable to drilling for and producing oil and natural gas. Some of these proposals would, if enacted into law, place additional limits on or eliminate the current deductions for IDC and percentage depletion. See “Tax Considerations – Possible Changes in Federal Tax Laws.”

Terms of the Offering

RISK FACTORS

Investment in the Partnership involves a high degree of risk and is suitable only for investors of substantial financial means who have no need for liquidity in their investments. You should consider carefully the following factors, in addition to the other information in this offering circular, prior to making your investment decision.

Particular Risks of the Partnership

We have a limited operating history.

The Partnership and the Managing General Partner are both recently formed entities and have limited operating histories. Accordingly, the Partnership’s prospects for success and future financial results are difficult to assess. Affiliates of our principals, Joe Vaughan and David Vaughan, including Energy Production Corporation and its predecessor, have managed other oil and gas developments projects for more than forty years. (See “Management”).

Not all properties to be acquired with the proceeds of this offering are currently identified.

The Partnership intends to acquire Prospects in Texas and Louisiana, specifically in the Polar Bear Field, Big Lake Field, and Electra Arch Field, and depending on the amount of gross proceeds raised in the offering, may acquire Prospects in other fields located in Texas or Louisiana. However, this is a “blind pool” offering to the extent that the investor partners will not have an opportunity to evaluate the specific properties that are selected for investment by the Partnership and must completely rely on the ability of our management to select Prospects, obtain financing, if needed, and ultimately sell the acquired properties.

The Partnership’s ability to diversify risks depends upon the number of Units issued, the development costs of each well, the size of the Partnership’s interest in each well and the availability of suitable Prospects.

If the Partnership only subscribes a limited number of Units, the risk to the partners is increased. At the minimum subscription level, the Partnership will be required to participate in fewer Prospects and/or in smaller ownership interests. As more Units are subscribed to and the Partnership size increases, the Partnership has the ability to diversify its asset holdings by purchasing additional Prospects and participating in the drilling and completion of a greater number of oil and gas wells. In addition, as the Partnership size increases, the Partnership may have the ability to acquire larger ownership interests in oil and gas properties. The numbers of oil and gas wells developed by the Partnership will depend upon the capital raised by the Partnership, the size of the Partnership’s interest in each well/Prospect, the value of the Partnership’s interests in producing wells that may be acquired, and the development costs of each well to be drilled.

There is no guarantee of a return of your investment or any specific rate of return on your investment in the Partnership.

You may not recover all or any of your investment in the Partnership, or if you do recover your investment in the Partnership, you may not receive a rate of return on your investment that is competitive with other types of investments. You will be able to recover your investment only through the Partnership’s distributions of the sales proceeds from the production and sale of oil and natural gas from productive wells. The quantity of oil and natural gas in a well, which is referred to as its reserves, decreases over time as the oil and natural gas is produced until the well is no longer economical to operate. The Partnership’s distributions may not be enough for you to recover all your investment in the Partnership or to receive a rate of return on your investment that is competitive with other types of investment if you do recover your investment in the Partnership.

The minimum offering amount is insufficient to conduct planned operations.

A minimum offering amount of $500,000 must be obtained before capital of the Partnership will be utilized by the Partnership for any purpose. After this threshold is met, the funds may be used for the Partnership’s operations. This amount may be insufficient to acquire Prospects and there can be no assurance that we will be able to sell additional Units to meet the capitalization requirements of the Partnership. If the Partnership is unable to meet its capitalization requirements, the Partnership may be required to acquire a smaller percentage interest in Prospects, acquire fewer Prospects or seek third-party financing (the availability of which cannot be assured) to pay for planned operations or otherwise modify its planned operations.

The Partnership may not have enough cash to make distributions to its partners.

The Partnership’s oil and gas operations may not generate sufficient revenues to the Partnership to enable the Partnership to make cash distributions to its partners. The ability to make cash distributions will depend on the Partnership’s future operating performance. See “PARTICIPATION IN DISTRIBUTIONS, PROFITS AND LOSSES – Cash Distribution Policy.” We will review the accounts of the Partnership at least monthly to determine the cash available for distribution. Distributions will depend primarily on the Partnership’s cash flow from operations, which will be affected, among other things, by the following:

Partnership income will be taxable to the limited and additional general partners in the year earned, even if cash is not distributed. “PARTICIPATION IN DISTRIBUTIONS, PROFITS AND LOSSES – Cash Distribution Policy” and “COMPENSATION TO THE MANAGING GENERAL PARTNER.”

Decisions about operations of certain properties may be made by third parties that you will have no input in selecting. We will manage and control the Partnership’s business.

We will exclusively manage and control all aspects of the business of the Partnership and will make all decisions concerning the business of the Partnership. You will not be permitted to take part in the management or in the decision making of the Partnership. The Partnership intends to acquire Prospects in which EPCO will serve as the operator for the Prospect wells. However, the Partnership may also acquire a minority working interest in oil and natural gas properties in which EPCO may not serve as the operator, and in such case, we would not control the selection of the operator or be able to direct operations under the terms of the applicable operating agreement. As a result, our limited ability to exercise control over the operations of wells in which the Partnership acquires a minority interest may cause a material adverse effect on the Partnership’s results of operations and financial condition.

In the event that the investor partners of the Partnership desire to remove us (or any successor) as managing general partner, they may do so at any time upon 90 days’ prior written notice following the vote of a Super-Majority in Interest (as such term defined in the partnership agreement) of the investor partners, and upon the selection of a successor managing general partner within such 90-day period by the investor partners owning a majority in interest.

The operations of the Partnership may not be geographically or geologically diversified.

The Partnership intends to focus on acquiring properties located primarily in the Electra Arch Field in Wilbarger County, Texas, Big Lake Field, in Reagan County, Texas, and the Polar Bear Field in West Baton Rouge Parish, Louisiana. See “PROPOSED ACTIVITIES.” Even if the Partnership acquires Prospects in other locations, the acquisition activity of the Partnership may be concentrated in very few areas. The Partnership’s risk of loss may be increased as a result of its lack of geographic diversification. Also, if the Partnership is subscribed at a minimum level, it would limit the number of Prospects in which the Partnership could participate, which, in turn, would increase the risk to the investor partners.

Compensation payable to us will affect distributions.

We and/or our affiliates will receive compensation from the Partnership throughout the life of the Partnership. Universe MGP and its affiliates will receive reimbursement of direct costs and general and administrative expenses described in “COMPENSATION TO THE MANAGING GENERAL PARTNER,” regardless of the success of the Partnership’s wells. These fees and direct costs will reduce the amount of cash distributions to you and the other investor partners. With respect to direct costs, the Managing General Partner has sole discretion on behalf of the Partnership to select the provider of the services or goods and the provider’s compensation as discussed in “COMPENSATION TO THE MANAGING GENERAL PARTNER.”

Extensions of the offering period could result in delays in property acquisitions and distributions.

Because the offering period for the Partnership can extend for many months, it is likely that there will be a delay in the investment of your subscription proceeds. This may create a delay in the Partnership’s cash distributions to you (if any), which will be paid only if there is sufficient cash available. See “TERMS OF THE OFFERING“ for a discussion of the procedures involved in the offering of the Units and the formation of the Partnership.

Additional general partners have unlimited joint and several liability for Partnership obligations.

Under Texas law, the state in which the Partnership has been formed, each general partner of the Partnership has unlimited liability, regardless of the amount of a general partner’s capital contribution, for obligations and liabilities of the Partnership. If you purchase Units as an additional general partner, you will be liable for all obligations and liabilities arising from the Partnership’s operations if these liabilities exceed both the assets and insurance of the Partnership and our assets and insurance. Your liability as an additional general partner may exceed the amount of your subscription. Even if you convert your general partner interest into a limited partner interest, you will continue to be liable as a general partner for matters that occurred while you owned a general partner interest. Under the partnership agreement, additional general partners are only liable for their proportionate share of the Partnership’s obligations and liabilities. However, the partnership agreement will not eliminate your liabilities to third parties in the event you invest as an additional general partner and other additional general partners do not pay their proportionate share of the Partnership’s obligations and liabilities.

The Partnership will hold less than all of the Working Interests in the Prospect wells. If a court holds the Partnership’s general partners and the other third-party working interest owners of the Prospect liable for the development and operation of the Prospect and some of the third-party working interest owners do not pay their proportionate share of the costs and liabilities associated with the Prospect, then the Partnership and you and the other additional general partners also would be liable for those costs and liabilities.

As an additional general partner, you may become subject to the following:

If the Partnership’s insurance proceeds and assets, our indemnification of you and the other additional general partners and the liability coverage provided by major subcontractors are not sufficient to satisfy a liability, then we will call for additional funds from the additional general partners to satisfy the liability. Our ability to indemnify you is dependent upon our financial condition.

Your ability to resell your Units is limited due to the lack of a public market and restrictions contained in the partnership agreement.

You may not be able to sell your interests in the Partnership. No public market for the Units exists or is likely to develop. Your ability to resell your Units also is restricted by the partnership agreement. See “Transferability of units.” Accordingly, you will need to bear the financial risks of your investment for an indefinite period of time. In addition, given these restrictions on transferability, the Units may not represent satisfactory collateral for a loan.

Cash distributions are not guaranteed.

Although it is contemplated that cash distributions will begin to be made six months after the effective date of the acquisition of the Prospects, and will be made monthly thereafter, there can be no assurance as to the timing and amount of Partnership distributions. Distributions will depend primarily on the Partnership’s net cash receipts from oil and natural gas operations, if any, and will be affected, among other things, by the price of oil and natural gas and the level of production of the Partnership’s properties. Moreover, distributions could be delayed to repay the principal and interest on Partnership borrowings, if any, or to fund Partnership costs.

We may have conflicts of interest with you and the Partnership.

The continued active participation by our affiliates in oil and natural gas activities individually, and on behalf of other partnerships organized or to be organized by our affiliates, and the manner in which partnership revenues are allocated, could create conflicts of interest with the Partnership. See “CONFLICTS OF INTEREST.” We and our affiliates have interests that inherently conflict with those of the unaffiliated partners, including the following:

We will attempt, in good faith and in accordance with the terms of the partnership agreement, to resolve all conflicts of interest. Any transaction with us may not be on terms as favorable as could have been negotiated with unaffiliated third parties.

Other partnerships sponsored by our affiliates will compete with the Partnership for personnel.

Due to the availability of our personnel, the fact that partnerships previously organized by our affiliates may still be purchasing and developing properties when the Partnership is attempting to acquire properties may make the completion of acquisition activities by the Partnership more difficult.

Extreme weather conditions may adversely affect Partnership properties and distributions.

The Partnership intends to acquire interests in properties primarily located in the Electra Arch Field in Wilbarger County, Texas, Big Lake Field, in Reagan County, Texas, and the Polar Bear Field in West Baton Rouge Parish, Louisiana. The Partnership may also acquire Prospects in other locations, which may be owned by unrelated third parties and/or our affiliates. In the event of strong storm activity, such as hurricanes, windstorms, and tornados in Texas and Louisiana, production and transportation operations in these regions may be adversely affected. As a result, revenues to the Partnership and distributions to the partners, if any, could be delayed or reduced.

The Partnership has limited external sources of funds, which could result in a shortage of working capital.

The Partnership intends to utilize its initial capital from this offering for the acquisition and limited development of Prospects. Depending upon the total amount of funds raised, the Partnership may have only nominal funds available for Partnership purposes until there are revenues from Partnership operations. Any future requirement for additional funding will have to come, if at all, from the Partnership’s revenues, the sale of Partnership properties or interests therein, or from borrowings.

Occasions may arise in which the Partnership will need to raise additional funds in order to finance costs of:

Additional operations requiring funding may include the acquisition of additional oil and natural gas leases and the acquisition of interests in producing oil or gas wells, and the drilling, completing, and equipping of additional wells to further develop the Partnership’s Prospects. If the above-described methods of financing should prove insufficient to maintain the desired level of Partnership operations, such operations could be continued through farmout arrangements with third parties, including us and/or our affiliates. These farmouts could result in the Partnership giving up a substantial interest in Prospects it has acquired and/or developed. The Partnership’s operations may not be sufficient to provide the Partnership with necessary additional funding, and the Partnership may not be able to borrow funds from third parties on commercially reasonable terms or at all. If the Partnership expends all of its capital on the acquisition and development of the Prospects and such properties fail to generate sufficient revenues, then there may be doubt as to the Partnership’s ability to continue as a going concern.

Your subscription for Units is irrevocable.

Your execution of the subscription agreement is a binding offer to buy Units in the Partnership. Once you subscribe for Units, you will not be able to revoke your subscription.

Lack of drilling rig availability may increase the Partnership’s costs and may result in delays in operations conducted on Prospects, and therefore, may delay the investor partners’ ability to deduct IDC in the year of their investment.

From time to time, there are shortages of drilling rigs and personnel available to drill wells. Such shortages could result in delays in the operations conducted on any well and, therefore, delay the investor partners’ ability to deduct IDC in the year of their investment. Such shortages could also result in increased costs to the Partnership for the Partnership’s proportional obligations for drilling rigs and personnel used in operations, and, as a result, decrease the amount of cash, if any, available for distribution to the partners in the Partnership.

The Partnership agreement limits our liability to you and the Partnership and requires the Partnership to indemnify us against certain losses.

We will have no liability to the Partnership or to any partner for any loss suffered by the Partnership, and will be indemnified by the Partnership against loss sustained by us in connection with the Partnership if:

The Partnership may become liable for joint activities of other working interest owners.

It is anticipated that the Partnership will hold interests in properties in its own name and/or in the name of an REI Energy affiliate who may serve as a title-holding nominee for the Partnership. It has not been clearly established whether joint working interest owners have several liability or joint and several liability with respect to obligations relating to the working interest. Although the operating agreements relating to properties ordinarily specify that the liabilities of joint working interest owners will be several, if the Partnership and other working interest owners are determined to have joint and several liability, the Partnership could be responsible for the obligations of these other parties relating to the entire working interest.

We are dependent upon Joe Vaughan and David Vaughan to operate.

Our ability to manage the Partnership is predominantly dependent upon our managers and principal executive officers, Joe Vaughan and David Vaughan. See “Management.”

Purchase of Units by our affiliates or us may assure the minimum aggregate subscription in the Partnership needed to acquire the Prospects is obtained.

We will contribute 1% of the total capital contributions of the Partnership. We and our affiliates also may, but are not required to, purchase additional Units in the Partnership, the effect of which may be to assure that the minimum aggregate subscription amount is obtained.

The partnership agreement prohibits your participation in the Partnership’s business decisions.

We will exclusively manage and control all aspects of the business of the Partnership and will make all decisions concerning the business of the Partnership. You may not participate in the management of the Partnership’s business. The partnership agreement forbids you from acting in a manner harmful to the business of the Partnership. If you violate the terms of the partnership agreement, you may have to pay the Partnership or other partners for all damages resulting from your breach of the partnership agreement.

Our affiliates’ past experience is not indicative of the results of this Partnership.

Information concerning the experience of previous partnerships sponsored by our affiliates, presented under the caption “Prior Activities,” does not indicate the results to be expected by this Partnership.

Our insurance coverage may be inadequate.

The Partnership’s operations will be subject to all of the operating risks normally associated with producing oil and natural gas, such as blow-outs and pollution, which could result in the Partnership incurring substantial liabilities or losses. Although the partnership agreement provides for the securing of such insurance as we deem necessary and appropriate, certain risks are uninsurable and others may be either uninsured or only partially insured because of high premium costs or other reasons. In the event the Partnership incurs uninsured losses or liabilities, the Partnership’s funds available for Partnership purposes may be substantially reduced or lost completely, and additional general partners may be jointly and severally liable for such amounts.

The effect of borrowing and other financing may negatively impact Partnership distributions.

We anticipate that the net proceeds from the sale of Units in the Partnership will be sufficient to finance the Partnership’s acquisition of interests in Prospects. Costs of operations may also be financed through Partnership borrowings and through utilization of Partnership revenues obtained from production, the sale of producing or non-producing reserves, the sale of net profits interests or other operating or non-operating interests in properties, or other methods of financing. See “Sources of Funds and Use of Proceeds – Subsequent Sources of Funds; Borrowings.” If these methods of financing should prove to be unavailable or insufficient to maintain the desired level of operations for the Partnership, operations could be continued through farmout arrangements with third parties (including affiliated partnerships), the sale of net profits interests or other operated or non-operating interests in properties, or borrowings. This could result in the Partnership giving up a substantial interest in oil and natural gas reserves. If the Partnership sells net profits interests in properties, the Partnership will incur costs that it cannot recover from the holders of the net profits interests, except in certain cases from future revenues, if any, relating to such properties. The effect of borrowing or other financing could be to increase funds available to the Partnership, but also could be to reduce cash available for distributions to the extent cash is used to repay borrowing obligations, or to reduce reserves if properties are farmed out or interests in the properties are sold.

The management of the Managing General Partner and of the Partnership is not subject to supervision or review by an independent board, independent officers, audit committee, or compensation committee.

The principal executive officers of the Managing General Partner are Joe Vaughan and David Vaughan. As a result, the activities of the Managing General Partner are not subject to the review and scrutiny of an independent board of directors. In addition, the Managing General Partner does not have an audit committee or compensation committee. Thus, there is no independent supervision of management representing the interests of the partners.

Should a legal dispute arise between u and, the Partnership, additional outside counsel may have to be retained.

Because our affiliates have the same legal counsel as we have, there may be conflicts of interest inherent in our legal representation. The Partnership has not engaged its own independent counsel. As a result, in the event of a legal dispute between us and the Partnership, additional outside counsel may have to be retained.

We may rely upon a small number of marketers to purchase a majority of oil and gas from the Partnership, which could pose a credit risk in the event one or more of them fails to pay in a timely manner or at all.

The various Prospect Well operators may sell the Partnership’s share of oil and natural gas on credit terms to refiners, pipelines, marketers, and other users of petroleum commodities. Revenues are paid to the operator who then disburses to the Partnership the Partnership’s percentage share of the revenues. We expect that a small group of marketers will account for a significant portion of this sales revenue. Despite the competitive nature of the market for oil and natural gas, the loss of any particular purchaser could have a material adverse impact on the Partnership by affecting prices, delaying sales of production or increasing costs. The operator’s reliance upon a small number of marketers to purchase the oil and natural gas from its properties poses a credit risk in the event one or more of such marketers should fail to pay in a timely manner or at all. In such event, the amount of distributions available to the Partnership and, as a result, the investor partners could be substantially diminished, even if the Partnership’s properties are successfully producing. Because the Partnership may not select the operator of its properties, our ability to monitor and evaluate the credit status of these purchasers and adjust sales terms as appropriate is limited.

Because investor partners bear the Partnership’s acquisition, drilling, and development costs, they bear most of the risk of non-productive operations.

Under the cost and revenue sharing provisions of the partnership agreement, we will share costs with you differently than the way we will share revenues with you. Because investor partners will bear a substantial amount of the costs of acquiring, drilling, and developing the Partnership’s properties, investor partners will bear a substantial amount of the cost and risks of drilling a dry hole and/or a marginally productive well.

You should not rely on the financial status of other additional general partners as a limitation on your liability.

No financial information will be provided to you concerning any investor who has elected to invest in the Partnership as an additional general partner. In no event should you rely on the financial wherewithal of additional general partners, including in the event we should become bankrupt or are otherwise unable to meet our financial commitments.

Lack of an independent underwriter may reduce the due diligence investigation conducted on the Partnership and us.

There has not been an extensive in-depth “due diligence” investigation of the existing and proposed business activities of the Partnership and us that would be provided by independent underwriters, and there is no assurance that any dealer will conduct extensive due diligence.

Unauthorized acts of general partners could be binding against the Partnership, and such unauthorized acts could be contrary to the best interests of the Partnership.

Under Texas law, the act of a general partner of a partnership apparently carrying on the business of the partnership binds the partnership, unless the general partner in fact has no authority to act for the partnership and the person with whom the partner is dealing has knowledge in good faith of the fact that such general partner has no such authority. As such, there is a risk that a general partner might bind a partnership by his unauthorized acts. Under the partnership agreement for the Partnership, the Managing General Partner is granted exclusive control over the conduct of the business of the Partnership, and as such, it is unlikely that a third party, in the absence of bad faith, would deal with an additional general partner in connection with a Partnership’s business. The participation by an additional general partner in the management and control of the Partnership’s business is expressly prohibited by the partnership agreement, and a violation of such prohibition would give rise to a cause of action by the partnership against an additional general partner engaging in such activities. Nevertheless, there is always the possibility that an additional general partner could attempt to take unauthorized actions on behalf of the Partnership, and if a court were to hold that such actions were binding against the Partnership, such unauthorized actions could be contrary to the best interests of the Partnership and could adversely affect the Partnership.

The Partnership may incur substantial impairment losses for accounting purposes.

If the reserve report used by the Partnership when estimating the Partnership’s proven reserves is revised downward or if oil and natural gas prices decline, the Partnership may be required to record non-cash impairment write-downs in the future, which would result in a negative impact to the Partnership’s financial statements.

Risks of Oil and Natural Gas Investments

Oil and natural gas investments are risky.

Oil and gas exploration and development operations and the selection of oil and natural gas properties for acquisition is highly speculative. There is a possibility you will lose all or substantially all of your investment in the Partnership. We cannot predict whether any Prospect will produce oil or natural gas or commercial quantities of oil or natural gas, nor can we predict the amount of time it will take to recover any oil or gas we do produce. Drilling activities may be unprofitable, not only from non-productive wells, but also from wells that do not produce oil or natural gas in sufficient quantities or quality to return a profit. Delays and added expenses may also be caused by poor weather conditions that could affect operations or the ability to ship oil or natural gas.

Furthermore, the Partnership may be subject to liability for pollution and other damages and will be subject to statutes and regulations relating to environmental matters. Although we will maintain, on behalf of the Partnership, insurance coverage that is normal and customary for the industry in the area and that we feel is adequate under the circumstances, including worker’s compensation, and operating, liability, and umbrella protection, the Partnership may suffer losses due to hazards against which it cannot insure or against which we may elect not to insure. Any such uninsured losses will reduce Partnership capital and/or cash otherwise available for distributions.

Prices of oil and natural gas are volatile.

Global economic conditions, political conditions, and energy conservation have created volatile prices for oil and natural gas. Oil and natural gas prices may fluctuate significantly in response to minor changes in supply, demand, market uncertainty, political conditions in oil-producing countries, activities of oil-producing countries to limit production, global economic conditions, weather conditions and other factors that are beyond our control. The prices for domestic oil and natural gas production have varied substantially over time and may in the future decline, which would adversely affect the Partnership and the partners. Prices for oil and natural gas have been and are likely to remain volatile.

Competition, market conditions and government regulation may adversely affect the Partnership.

The Partnership will compete with a number of other potential purchasers of properties, many of which have greater financial resources. This may result in the Partnership not being able to acquire certain properties otherwise desired for acquisition. The sale of any oil or natural gas found and produced by the Partnership properties will be affected by fluctuating market conditions and regulations, including environmental standards, set by state and federal agencies. State and federal governmental regulation of the oil and gas industry is in a potentially fluid situation and could change dramatically because of many outside factors, including a shift in the philosophy of the governmental environmental policies, continued increases in the price of oil and national security concerns. Governmental regulations may fix rates of production from Partnership properties, and the prices for oil and natural gas produced from the properties may be limited. From time-to-time, a surplus of oil and natural gas occurs in areas of the United States. The effect of a surplus may be to reduce the price the Partnership may receive for its oil or natural gas production, or to reduce the amount of oil or natural gas that the Partnership may produce and sell.

Government regulation may adversely affect the Partnership’s profitability.

The oil and natural gas business is subject to extensive governmental regulation under which, among other things, rates of production from the Partnership well may be fixed and the prices for natural gas produced from the Partnership well may be limited. Governmental regulation also may limit or otherwise affect the market for the Partnership’s oil and natural gas production, if any, and the price that may be paid for that production. Governmental regulations relating to environmental matters could also affect the Partnership’s operations by increasing the costs of operations or by requiring the modification of operations in certain areas. State and federal governmental regulation of the oil and gas industry is in a potentially fluid situation and could change dramatically because of many outside factors, including a shift in the philosophy of the governmental environmental policies, continued increases in the price of oil and national security concerns. The nature and extent of various regulations, the nature of other political developments, and their overall effect upon the Partnership are not predictable. Investment in the Partnership involves a high degree of risk and is suitable only for investors of substantial financial means who have no need for liquidity in their investments.

Environmental regulation relating to disposal of water produced by wells may adversely impact the Partnership’s profitability.

The Partnership may acquire properties that produce water as well as oil or natural gas. Environmental regulations governing the operator’s ability to remove and dispose of water will affect production, and the cost of water treatment and disposal may affect profitability of the Partnership’s wells. The imposition of new environmental initiatives and regulations could also include restrictions on the operator’s ability to dispose of produced water and other substances associated with the production of gas and oil.

The production and producing life of Partnership properties is uncertain. Production will decline.

It is not possible to predict the life and production of any Prospect. The actual lives could differ from those anticipated. Sufficient oil or natural gas may not be produced for you to receive a profit or even to recover your initial investment. In addition, production from the Partnership’s oil and natural gas properties, if any, will decline over time, and does not indicate any consistent level of future production. This production decline may be rapid and irregular when compared to a property’s initial production.

The Partnership may be required to pay delay rentals to hold its rights to any Prospects it acquires, which may deplete Partnership capital.

Oil and natural gas leases generally must be drilled upon by a certain date or additional funds known as delay rentals must be paid to keep the lease in effect. Delay rentals typically must be paid after the first year of entering into a lease if no production or drilling activity has commenced. If delay rentals become due on any property the Partnership acquires, the Partnership will have to pay its share of such delay rentals or lose its lease on the property. These delay rentals could equal or exceed the cost of the property. Further, payment of these delay rentals could seriously deplete the Partnership’s capital available to fund drilling activities when they do commence.

Increases in drilling costs could affect the profitability of the Partnership.

When levels of drilling activity are high, there could be shortages of drilling rigs, fracturing equipment, pipes and other equipment and personnel available for Partnership operations. Actual costs may also exceed original estimates of drilling and completion costs for a number of reasons including, but not limited to, weather delays, pressure or irregularities in formations and other risks. As a result, there could be an increase in the costs associated with the drilling of oil and natural gas wells. In addition, the cost of insurance relating to oil and gas operations may continue to increase. Such increases could result in limiting the profitability of each well once completed.

Environmental hazards and liabilities may adversely affect the Partnership and result in liability for the additional general partners.

There are numerous natural hazards involved in the drilling of oil and natural gas wells, including unexpected or unusual formations, pressures, blowouts involving possible damages to property and third parties, surface damages, bodily injuries, damage to and loss of equipment, reservoir damage and loss of reserves. There are also hazards involved in the transportation of oil and natural gas from our well to market. Such hazards include pipeline leakage and risks associated with the spilling of oil transported via barge instead of pipeline, both of which could result in liabilities associated with environmental cleanup. Uninsured liabilities would reduce the funds available to the Partnership, may result in the loss of Partnership properties and may create liability for you if you are an additional general partner. Although the Partnership will maintain insurance coverage in amounts we deem appropriate, it is possible that insurance coverage may be insufficient. In that event, Partnership assets would be utilized to pay personal injury and property damage claims and the costs of controlling blowouts or replacing destroyed equipment rather than for additional drilling activities.

The Partnership may incur liability for liens against its subcontractors.

Although we will try to determine the financial condition of nonaffiliated subcontractors, if subcontractors fail to timely pay for materials and services, the properties of the Partnership could be subject to materialmen’s and workmen’s liens. In that event, the Partnership could incur excess costs in discharging the liens.

Shut-in wells and delays in production may adversely affect Partnership operations.

Production from wells may be reduced or delayed due to seasonal marketing demands and storage capacity limitations. Wells may have access to only one potential market. Local conditions, including closing businesses, conservation, shifting population, pipeline maximum operating pressure constraints, and development of local oversupply or deliverability problems could halt sales from Partnership wells.

Delays in the transfer of title to the Partnership could place the Partnership at risk.

Under certain circumstances, we will hold title to Partnership properties on the Partnership’s behalf. In some instances, title may not be transferred to us or the Partnership until after a well has been completed. When this is the case, the Partnership runs the risk that the transfer of title could be set aside in the event of the bankruptcy of the party holding title. In this event, title to the leases and the wells would revert to the creditors or trustee, and the Partnership would recover nothing or only the amount paid for the leases and the cost of drilling the wells. Assigning the leases to the Partnership after the wells are drilled and completed, however, will not affect the availability of the tax deductions for IDC since the Partnership will have an economic interest in the wells under the drilling and operating agreement before the wells are drilled. See “PROPOSED ACTIVITIES - Title to Properties.”

Our dependence on third parties for the processing and transportation of oil and gas may adversely affect the Partnership’s revenues and distributions.

We rely on third parties to process and transport oil and gas produced by wells in which the Partnership participates. In the event a third party upon which we rely is unable to provide transportation or processing services, and another third party is unavailable to provide such services, then the Partnership will be unable to transport or process the oil and gas produced by the affected wells. In such an event, revenues to the Partnership and distributions to the partners may be delayed.

Tax Risks

You should read carefully the following discussion of tax risks together with the section entitled “Tax Considerations” below, which includes a more detailed discussion of the U.S. federal income tax consequences associated with becoming a partner in the Partnership. Except where specifically mentioned, this offering circular does not discuss the foreign, state or local tax consequences or risks related to becoming a partner in the Partnership.

Tax risks of becoming a partner.

There are substantial risks associated with the U.S. federal income tax consequences of becoming a limited partner or an additional general partner in the Partnership. The following paragraphs summarize some of the tax risks to a limited partner. Because the tax consequences of becoming a limited partner or an additional general partner are complex and certain tax consequences may differ depending on individual tax circumstances, each investor should consult with and rely on his or her own tax advisor about the tax consequences of becoming a limited partner. No representation or warranty of any kind is made in this offering circular with respect to the acceptance by the IRS or any court of law regarding the treatment of any item of income, deduction, gain, loss or credit by an investor on his or her tax return.

Changes in the tax law may occur at any time and may result in fewer tax benefits to you.

All U.S. federal tax matters discussed in this offering circular are subject to change without notice by legislation, administrative action and judicial decision. Such changes could deprive the Partnership and you of certain tax benefits, and any changes may or may not be retroactive with respect to transactions occurring prior to the effective date thereof.

It is not possible to predict whether any legislative proposals concerning the tax treatment of oil and gas properties will become law. Therefore, we urge you to consult with your own tax advisor regarding the impact that a change in the U.S. federal tax law could have on your decision to participate in the Partnership.

Tax treatment depends upon partnership classification.

The availability of the tax benefits of participating in the Partnership depends upon the classification of the Partnership as a “partnership” rather than “an association taxable as a corporation” for federal income tax purposes. The Partnership’s status as a limited partnership under Texas state law is not determinative of this issue. However, we believe that under current law the Partnership will be treated as a partnership for federal income tax purposes and not as an association taxable as a corporation so long as an election is not made to treat the Partnership as a corporation for U.S. federal income tax purposes. It is anticipated that no such election will be made. Should the Partnership elect to be, or should the IRS successfully assert that the Partnership should be, treated as an association taxable as a corporation for federal income tax purposes, (i) income, gains, losses, deductions and credits of the Partnership would not flow through to the partners, (ii) the taxable income of the Partnership would be subject to the federal income tax imposed on corporations at the Partnership level, and (iii) distributions would be treated as corporate distributions to the partners and could be taxable as dividends or capital gain.

Tax liabilities may exceed cash distributions.

You must include in your own taxable income for a taxable year your share of the items of the Partnership’s income, gain, loss, deduction and credit for the year, whether or not cash proceeds are actually distributed to you. As a result, you could be required to pay federal income tax based on your distributive share of Partnership taxable income regardless of whether you receive a cash distribution. Although we intend to distribute 100% of the cash generated by the Partnership’s operations, net of amounts necessary to pay the Partnership’s obligations and expenses and a reserve for future expenditures and contingencies, we cannot guarantee that we will be able to make any cash distributions. If your tax liability exceeds the cash that is distributed to you from the Partnership, you will have to use funds from other sources to pay your tax liability.

Your individual circumstances may prevent you from receiving certain tax deductions.

Certain tax deductions, such as depletion, must be computed separately by the partners and not at the Partnership level. Therefore, the availability of such deductions to you as a limited partner will depend in part upon your individual circumstances. We will provide sufficient information to you in order for you to compute available deductions. However, there can be no assurance of the amount, if any, or the type of deductions that may be available to a particular limited partner. See “Tax Considerations – Depletion.”

We cannot assure that IDC will be incurred by the Partnership and will be deductible by investors in the year when they are admitted to the Partnership.

IDC is cost incident to the drilling of wells and the preparation of wells for production that have no salvage value. The Partnership may not expend or contract to expend any of its capital for IDC in the year in which investors are admitted as partners or in any later year. In addition, if and to the extent that the Partnership spends or contracts to expend a portion of its capital for IDC in the year in which investors are admitted as partners, the tax deductions for such expenditures may be delayed until later years. As a result, the Partnership’s subscriptions, and therefore your investment in the Partnership, may not result in IDC that is deductible in the year in which you are admitted as a partner in the Partnership.

The IRS may challenge the Partnership’s characterization of its costs as IDC.

The Partnership intends to enter into one or more operating agreements with its affiliate, Energy Production Corporation (“EPCO”) and potentially unaffiliated operators to conduct and direct all operations for the Partnership’s Prospects. The Partnership will pay the unaffiliated operators and/or EPCO its proportionate share to drill and complete the Partnership’s Prospect wells. The Partnership intends to treat the drilling compensation paid to EPCO (or other its affiliates) as IDC. There is, however, no guarantee that the IRS will agree with the Partnership’s characterization of such costs as IDC and/or the Partnership’s characterization of any of its other costs as IDC. The IRS could assert that the costs are not reasonable or are not incident and necessary to the drilling of the Partnership’s Prospects and, therefore, do not constitute IDC. The IRS may also assert that all or portions of the costs are properly allocable to tangible property, leasehold costs, syndication costs or other non-currently deductible items. If the IRS successfully asserts that any of the costs treated by the Partnership as currently deductible IDC is properly allocable to some other non-currently deductible items, you could owe additional taxes, penalties and interest. See “TAX CONSIDERATIONS – Intangible Costs.”

The IRS could challenge the timing of the Partnership’s deductions for IDC.

If and to the extent that the Partnership acquires one or more drilling Prospects and participates in the drilling and development work on such Prospects, the Partnership may prepay some or all of the drilling costs to the operator of the wells for drilling and completion operations that in large part may be performed during a subsequent year. IDC is generally deductible for the tax year during which the drilling services are provided. However, if certain specific requirements are met, all or a portion of such prepayments may be deductible for the year during which the amounts are paid to the operator. The prepayments, however, could fail to satisfy the requirements to be deductible when paid and/or the IRS may challenge the timing of the deductions of such prepayments. If such a challenge were successful, you could owe additional taxes, penalties and interest. However, any such amounts prepaid to an operator of the Partnership’s wells after formation of the Partnership that are properly characterized as IDC should be deductible in the tax year during which the drilling services are actually performed. See “Tax Considerations – Intangible Costs.”

Current deductions for IDC, depletion and depreciation may only defer your tax liability to a later year.

Deductions for IDC, depletion and depreciation must be recaptured as ordinary income if the Partnership disposes of its oil and gas properties at a gain for tax purposes, or if you dispose of your Units in the Partnership at a gain for tax purposes. Therefore, some or all of your taxable gain on the sale of your Units in the Partnership or your allocable share of the Partnership’s taxable gain on the sale of an oil and gas property may be taxable at ordinary income rates. As a result, deductions in early years for IDC, depletion and depreciation may only defer your tax liability to a later year.

Losses may be considered to be passive losses for tax purposes.

If the Partnership owns one or more working interests in one or more oil or gas leases at any time during a tax year, individual investors that own general partnership interests directly or through entities that do not limit their liabilities with respect to their Units should not be subject to the passive activity loss rules with respect to such working interests for the tax year. As a result, such investors should be able to utilize losses from the Partnership from such working interests to offset future income from the Partnership and their other so-called “active income” (e.g., salary) and “portfolio income” (e.g., dividends, interest and royalties not derived in the active conduct of a trade or business). On the other hand, individual investors that own limited partnership interests or hold their general partnership interests through an entity that limits their liability, such as a limited liability company or limited partnership, should be subject to the passive activity loss rules. In such case, any losses from the Partnership should be treated as passive and, consequently, will only be available to offset the investors’ future income from the Partnership and other passive income, if any, that they may have.

A material portion of subscriptions will be allocated to costs that are not currently deductible.

A material portion of the subscriptions of the limited and additional general partners will be used for costs and expenses that are not currently deductible, including, for example, the Management Fee out of which we will pay all sales commissions. The Partnership intends to allocate the tax attributes of the sales commissions to the limited and additional general partners.

There are risks associated with Partnership borrowings.

We are authorized to cause the Partnership to borrow funds to fund Partnership operations required to maintain, repair or restore Partnership properties, or for general Partnership purposes. Your share of Partnership income applied to the repayment of loans will be included in your taxable income. Although the taxable income may be offset in part by deductions for IDC, depletion, depreciation, and interest, the required loan repayments could reduce the Partnership’s available cash so that you have an income tax liability in excess of the amount of cash distributions you receive from the Partnership. In such event, you will have to use funds from other sources to pay your tax liability.

The IRS may not respect the Partnership’s allocation of tax items.

The Partnership intends to allocate items of income, gain, loss, deduction and credit among the partners in accordance with the terms of the partnership agreement. We can provide no assurance that the IRS will respect such allocations and will not challenge the allocations and assert that the Partnership’s income, gain, loss, deduction and credit should be allocated among the partners in some other manner. If the IRS successfully argues that the Partnership’s federal income tax items should be allocated in a different manner, you could owe additional taxes, penalties and interest.

The Partnership will generate taxable events for investor partners that are generally exempt from taxation.

Certain entities that are otherwise exempt from federal income tax, such as individual retirement accounts and annuities (“IRAs”), qualified plans, and charitable organizations are nonetheless taxed on “unrelated business taxable income” (“UBTI”) of $1,000 or more that they earn in any particular year. Substantially all the income from the Partnership’s operations should constitute UBTI and may give rise to a tax liability to an otherwise tax-exempt investor. For partners that invest with money from their IRAs, it is possible that the earnings from the Partnership could be subject to tax twice: once when amounts are earned by the Partnership and then again when distributions are made from the IRA to the investor. In addition, tax-exempt charitable remainder trusts and charitable remainder unitrusts will be subject to a 100% excise tax on any unrelated business taxable income that they receive. Therefore, tax exempt prospective investor partners are urged to consult their tax advisors before investing in the Partnership. See “TAX CONSIDERATIONS – Participation by IRAs, Employee Benefit Plans and Similar Tax-Exempt Organizations.”

FORWARD-LOOKING STATEMENTS

This offering circular and information provided with this offering circular contain forward-looking statements that involve risks and uncertainties. You should exercise extreme caution with respect to all forward-looking statements made in the offering circular. Specifically, the following statements are forward-looking:

Forward-looking statements reflect the current view of management with respect to future events and are subject to numerous risks, uncertainties and assumptions, including, without limitation, the factors listed above in the section captioned “Risk Factors.” Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Should any one or more of these or other risks or uncertainties materialize or should any underlying assumptions prove incorrect, actual results are likely to vary materially from those described herein. There can be no assurance that the projected results will occur, that these judgments or assumptions will prove correct or that unforeseen developments will not occur.

We do not intend to update our forward-looking statements. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the applicable cautionary statements.

TERMS OF THE OFFERING

General

We are offering general and limited partner interests in Universe Energy Partners, LP, which we refer to in this offering circular as the “Partnership.” The Partnership is a limited partnership formed under provisions of the Texas Business Organizations Code (“TBOC”) cited as the Texas Limited Partnership Law. We are offering for sale 2,000 Units of limited and general partnership interests in the Partnership at an offering price of $25,000 per unit. The minimum subscription per subscriber is $10,000 (0.40 unit).

We will accept subscriptions for Units until the offering has reached the offering level of subscription (2,000 Units), or the offering expires or is otherwise terminated by the Managing General Partner. Capital of the Partnership will not be utilized for any purposes until subscriptions have been accepted for at least 20 Units ($500,000). To the extent we or our affiliates purchase Units, we (or our affiliates, as applicable) will be entitled to the same ratable interest per unit of partnership interest we may own in the Partnership as other unit holders of partnership interest. The purchase of Units by us or our affiliates may permit the Partnership to satisfy its requirements to sell the minimum number of Units in order to close the offering. Any Units purchased by us or our affiliates will be made for investment purposes only and not with a view toward redistribution or resale of the Units. All Units purchased by us or our affiliates shall be purchased at the same purchase price as unaffiliated subscribers at $25,000 per Unit.

Offering Period

The offering period for the Partnership began on the date of this offering circular and will terminate one year after this offering is declared qualified by the SEC; provided, however, that we may extend the offering period for up to two consecutive six-month periods, and may terminate the offering period at any time.

Types of Units

You May Choose to Be a Limited Partner, an Additional General Partner or Both. You may purchase Units as a limited partner, an additional general partner or both. Although income, gains, losses, deductions and cash distributions allocable to the investor partners are generally shared pro rata based upon the amount of their subscriptions, there are material differences in the federal income tax effects and the liability associated with these different types of Units.

Each investor partner must indicate the number of limited partner Units or additional general partner Units subscribed for and fill in the appropriate line on the investor partner signature page of the subscription agreement. If you fail to indicate on the subscription agreement a choice between investing as a limited partner or as an additional general partner, we will not accept the subscription and will promptly return the subscription agreement and the tendered subscription funds to you.

Limited Partners. The liability of a limited partner of the Partnership for the Partnership’s debts and obligations will be limited to that partner’s capital contributions, its share of Partnership assets and the return of any part of his capital contribution. Under Texas law, a limited partner is liable for all or part of a returned capital contribution or partnership distribution if the limited partner received a partnership distribution in violation of the partnership agreement of the partnership or Texas Limited Partnership Law and such limited partner knew at the time of the distribution that the distribution violated the terms of the partnership agreement or the Texas Limited Partnership Law.

General Partners. The general partners of the Partnership will consist of us as the Managing General Partner and each investor partner purchasing Units of general partner interest. Each additional general partner will be fully liable for the debts, obligations and liabilities of the Partnership individually and as a group with all other general partners as provided by the TBOC to the extent liabilities are not satisfied from the proceeds of insurance, from indemnification by us or from the sale of Partnership assets. See “RISK FACTORS.” While we anticipate that the activities of the Partnership will be covered by substantial insurance policies and indemnification by us, the additional general partners may incur personal liability because of Partnership activities that are not covered by insurance, Partnership assets or indemnification.

Conversion of Units by Additional General Partners and Us. We will convert all Units of additional general partner interest of the Partnership into Units of limited partner interest when practicable after the end of the year in which substantially all drilling planned by the Partnership has been completed or, in our opinion, in any year when we believe that the Partnership may have positive taxable income. Additional general partners may, however, upon written notice to us, and except as provided below and in the partnership agreement, convert their interests into limited partnership interests of the Partnership at any time within the 30-day period prior to any material change in the amount of the Partnership’s insurance coverage. Upon conversion, an additional general partner of the Partnership will become a limited partner of the Partnership. Conversion will not be permitted if it will cause a termination of the Partnership for federal income tax purposes.

Conversion of an additional general partner to a limited partner in the Partnership will not be effective until we file an amendment to the Partnership's certificate of formation. We are obligated to file an amendment to the Partnership's certificate at any time during the full calendar month after receiving the required notice of the additional general partner requesting conversion because of a change in insurance coverage, as long as the conversion will not result in a termination of the Partnership for tax purposes. After the conversion of his general partner interest to that of a limited partner, each converting additional general partner will continue to have unlimited liability for Partnership liabilities arising prior to the effective date of such conversion, and will have limited liability to the same extent as limited partners for liabilities arising after conversion to limited partner status is effected. Except with respect to Units we buy in the Partnership for cash, we are not entitled to convert our interests into limited partnership interests.

Subscriptions for Units; Escrow Account

After a potential investor partner has carefully read this offering circular and the related documents attached to or described in this offering circular, subscriptions may be made by following the instructions at the front of the Subscription Booklet accompanying this offering circular. Specifically, each potential investor partner should (1) complete and sign (a) the Subscription Agreement (in the form attached as Exhibit (4)(a) and included as Document No. 1 in the Subscription Booklet); and (b) the Questionnaire, including the Purchaser Representative Questionnaire, if necessary (in the form attached as Exhibit (4)(a) and included as Document No. 2 in the Subscription Booklet) and (2) deliver or mail the completed Subscription Booklet, together with the entire amount of the purchase price of the Units, to Premier Place, 5910 North Central Expressway Suite 370, Dallas, Texas 75206. Subscriptions for Units are payable in cash upon subscription. Checks for Units should be made payable to “Universe Energy Partners, LP”

The execution of the Subscription Agreement by a subscriber, or by his or her authorized representative in the case of fiduciary accounts, constitutes a binding offer to buy Units in the Partnership and an agreement to hold the offer open until the subscription is accepted or rejected by us. Once you subscribe for Units, you will not have any revocation rights, unless otherwise provided by state law.

We may, in our sole and absolute discretion, reject all or part of the subscription of any potential investor partner without liability to the subscriber. The execution of the Subscription Agreement and its acceptance by us also constitutes the execution of the partnership agreement by a potential investor partner and an agreement to be bound by its terms as a limited partner or additional general partner, as the case may be, including the granting of a special power of attorney to us appointing us as the partner’s lawful representative to make, execute, sign, swear to, and file an amendment to the Partnership’s Certificate of Formation, governmental reports, certifications, contracts, and other matters.

In accordance with the terms of the offering, subscription proceeds of the Partnership will be held in a separate non-interest-bearing escrow account with _____________ as escrow agent (the “Escrow Agent”) until at least five (5) Units in the Partnership are subscribed for. If at least five (5) Units in the Partnership is not subscribed for prior to the termination of the offering period, the Escrow Agent will return promptly all subscription proceeds to subscribers in full, without interest. If at least five (5) Units have been subscribed for during the offering period, then we may, in our discretion, direct the Escrow Agent to disburse the funds in the escrow account, in whole or in part, at any time during the remainder of the offering period, and to pay to us all funds in the escrow account upon termination of the offering period.

Termination; Waiver

We reserve the right, in our sole discretion, to abandon or terminate the offering at any time during the offering period, to reject all or part of any subscription from any potential investor partner for any reason and, in the event that the offering is oversubscribed, to allot a lesser number of Units than are subscribed by any method that we deem appropriate. We are not obligated to accept subscriptions in the order in which they are received. If the offering is terminated for any reason or if a subscriber’s subscription is not accepted, we will cause all funds to be refunded promptly to the affected subscribers, without interest.

Determination of Offering Price

There is no market or market price for the Units. We established the offering price of the Units arbitrarily, without any arms-length negotiations or appraisal. Furthermore, because the Partnership was recently formed, the offering price does not necessarily bear any relationship to the Partnership’s assets (tangible or intangible), book value, net worth or expected earnings. The offering price has not been derived using any recognized criteria of value.

Investor Suitability

As a Tier II, Regulation A offering, investors must comply with the 10% limitation to investment in the offering, as prescribed in Rule 251, or otherwise qualify as an “Accredited Investor,” as defined under Rule 501 of Regulation D. The Units are suitable only for those investors (a) whose business and investment knowledge and experience makes them capable of evaluating the merits and risks of their prospective investment in the Units and (b) who can afford to bear the economic risk of their investment for an indefinite period and have no need for liquidity in this particular investment. Each investor will be required to represent in writing that (i) he or she is acquiring Units for his or her own account as principal, for investment and not with a view to resale or redistribution and (ii) he or she is aware that his or her transfer rights are restricted by the Securities Act, applicable state securities laws, and the absence of a market for the Units.

Accredited Investors include those persons that meet at least one of the following standards:

Under Rule 251 of Regulation A, non-accredited, non-natural investors are subject to the investment limitation and may only invest funds which do not exceed 10% of the greater of the purchaser's revenue or net assets (as of the purchaser’s most recent fiscal year end). A non-accredited, natural person may only invest funds which do not exceed 10% of the greater of the purchaser’s annual income or net worth (please see below on how to calculate your net worth).

NOTE: For the purposes of calculating your net worth, Net Worth is defined as the difference between total assets and total liabilities. This calculation must exclude the value of your primary residence and may exclude any indebtedness secured by your primary residence (up to an amount equal to the value of your primary residence). In the case of fiduciary accounts, net worth and/or income suitability requirements may be satisfied by the beneficiary of the account or by the fiduciary, if the donor or grantor is the fiduciary and the fiduciary directly or indirectly provides funds for the purchase of the Units.

Each investor partner must represent to the Partnership that he or she, either alone or with his or her purchaser representative, has such knowledge and experience in financial and business matters that he or she is capable of evaluating the merits and risks of investing in the Units. Each investor partner must also represent that: (a) his or her overall commitment to investments that are not readily marketable is not disproportionate to his or her net worth, and his or her investment in the Units will not cause such overall commitment to become excessive; (b) he or she has adequate net worth and means of providing for his or her current financial needs and personal contingencies to sustain a complete loss of his or her investment in the Units; (c) he or she has evaluated the risks of investing in the Units and understands that there is a substantial risk that he or she may lose all or substantially all of his or her investment in the Units; and (d) he or she has substantial experience in making investment decisions of this type or is relying on his or her own tax advisor or other qualified purchaser representative in making his or her investment decision.

Each potential investor partner is required to complete and submit a Subscription Agreement and Suitability Questionnaire to demonstrate that he or she is appropriately qualified to invest in the Partnership. In addition, investor partners may be required to provide the Partnership with any additional information needed by the Partnership to verify each prospective investor partner’s qualification.

Transferees of Units seeking to become substituted partners must also meet the suitability requirements discussed above, as well as the requirements for transfer of Units and admission as a substituted partner imposed by the partnership agreement. These requirements apply to all transfers of Units, including transfers of Units by a partner to a dependent or to a trust for the benefit of a dependent or transfers by will, gift or by the laws of descent and distribution.

Where any Units are purchased by an investor partner in a fiduciary capacity for any other person (or for an entity in which such investor partner is deemed to be a “purchaser” of the subject Units) all of the suitability standards above will be applicable to such other person.

Investor partners are required to execute their own subscription agreements. We will not accept any subscription agreement that has been executed by someone other than the investor partner(or, in the case of fiduciary accounts, someone who does not have the legal power of attorney to sign on the investor partner’s behalf).

PLAN OF DISTRIBUTION

Distribution

Units are being offered for sale through broker-dealers and finders. Units are being offered on a “best efforts” basis for the Partnership, to a select group of investor partners who meet the suitability standards set forth under “Terms of the Offering – Investor Suitability.” “Best efforts” means the various broker-dealers and finders that will sell the Units will not be obligated to sell or to purchase any amount of Units, but will be obligated to make a reasonable and diligent effort (that is, their “best efforts”) to sell as many Units as possible. Subscription proceeds will be held in an escrow account until and unless the minimum offering amount has been reached.

Units will be sold only to subscribers who execute and return a Subscription Agreement (together with a check in the amount of their subscription made payable to “Universe Energy Partners, LP” and represent that they meet the eligibility criteria set forth above under “Terms of the OfferinG – Investor Suitability.”

We will review each subscription and notify you of whether your subscription has been accepted or rejected. Subscription funds will be held in an account with the escrow agent for up to the full term of the offering period pending our decision of whether to accept or reject each subscription. Investor partners subscribing for Units will become investor partners of the Partnership only after we accept their subscriptions. We may refuse, in our sole discretion, to accept any subscription tendered in connection with this offering. Subscription funds received from prospective investor partners whose subscriptions are not accepted by us will be promptly returned to them, without interest. If the offering is oversubscribed, we will in our discretion, allot a lesser number of Units than are subscribed by any method that we deem proper.

Compensation

Out of the Management Fee, FINRA-licensed broker-dealers for the Partnership may receive a sales commission, payable in cash, of up to 10% of the limited and additional general partners’ subscriptions. Finders that we may engage (if permitted) may receive fees of up to 10% of the limited and additional general partners’ subscriptions. The fees paid to finders, if any, will not increase the Management Fee or the total sales commissions paid from investor partner subscriptions.

No sales commissions will be paid on sales of Units to officers, directors, employees, or registered representatives of a soliciting dealer (or the spouses, parents or children of such persons) if the soliciting dealer, in its discretion, has elected to waive its sales commissions. Any Units so purchased will be held for investment and not for resale.

Qualification to Sell

Appropriately licensed soliciting dealers and finders who offer the Units may receive commissions in connection with the sale of Units, but only in those states in which it is lawfully qualified to do so.

Our Purchase of Units

We intend to purchase Units representing a 1% limited partnership interest in the Partnership. The purchase of Units by us or our affiliates may have the effect of allowing the offering to be subscribed to the minimum, thereby satisfying an express condition of the offering, and thus allow the offering to close. Any Units purchased by us and/or our affiliates will be held for investment and not for resale.

SOURCES OF FUNDS AND USE OF PROCEEDS

Initial Sources of Funds

Upon completion of the offering, the sole funds available to the Partnership will be the capital contributions of the partners, which will range from the minimum subscribed amount of $500,000 (20 Units) to an offering amount of up to $50,000,000 (2,000 Units). We will contribute 1% of the total capital contributions to the Partnership. In addition, we and our affiliates may, but are not required to, purchase Units in the Partnership. There is no limit on the number of Units we and our affiliates may elect to purchase in the Partnership.

Use of Proceeds

The total proceeds from the offering will be $500,000 if the minimum number of Units offered (20 Units) (the “Minimum Subscription”) are sold, and $50,000,000 if 2,000 Units are sold (the “Maximum Offering”). We estimate that the net proceeds available for investment activity from the sale of Units in the Partnership will be approximately $395,000 assuming only the Minimum Subscription is achieved, and $39,500,000 if the Maximum Offering is achieved, each after deducting the one-time Management Fee (15% of the subscribed amount) and the estimated overhead attributed to the Managing General Partner for a period of two years. From the Management Fee, we will pay all syndication costs including sales commissions (15% of subscriptions received). We intend to use the net proceeds from this offering to fund acquisition and drilling activities on various Prospects. The table below reflects our pro forma anticipated use of the proceeds based on assumptions and estimates as of the date of this Offering circular.

ESTIMATED EXPENDITURES OF NET PROCEEDS⁽¹⁾

Electra Arch Leasehold Interest

(Purchase of 42% Working Interest purchased from EPCO)

Big Lake Farmout Interest

(Purchase of 100% Working Interest purchased from EPCO)

Polar Bear Leasehold

(Purchase of 63% Working Interest purchased from EPCO)

The table above represents our best estimate of the allocation of the proceeds of the offering, based upon our current plans and current economic conditions. This estimate is subject to change, provided that the Management Fee will not exceed 15% of offering proceeds. If at any time the fees payable exceed 15% of the investor partner proceeds, any such payments exceeding 15% will be paid by an affiliate of the Partnership. We retain broad discretion with respect to use of proceeds in connection with the acquisition and development of the Prospects. The amount and timing of expenditures will vary depending upon a number of factors, including our ability to secure developmental and exploratory oil and gas leases and properties and develop such properties in a timely fashion. Subscription proceeds will be held in a separate non-interest-bearing escrow account until we reach the Minimum Subscription and may be released before the end of the offering period.

Subsequent Sources of Funds

We anticipate that substantially all of the Partnership’s initial capital will be committed or expended within 12 months after the termination of this offering. A portion of the Partnership’s aggregate capital may be set aside as a reserve for unexpected developmental and operational expenses for the Partnership. Any additional funds needed for Partnership operations must come from cash flow from operations, borrowings or the sale of interests in Partnership properties. We also intend for the Partnership to retain a portion of its operating cash flow each month to create a reserve to cover potential eventual plugging, abandonment and restoration costs.

Borrowing. The Partnership will not commence any operation for which it believes that it does not have sufficient capital, including borrowed funds, to pay all costs to be incurred during the first 12 months of ownership. The Partnership may borrow funds to complete acquisitions or pay for the development and operation of its wells, such as drilling and completion costs, repairs, maintenance and restoration operations. There can be no assurance that any funds can be obtained or that they can be obtained at commercially reasonable rates.

Sale of Operating Interests. The Partnership may sell part or all of its working interests to third parties or its affiliates in order to finance Partnership operations. Working interests are operating interests that obligate the holder to pay a portion of all operating and development expenses and entitle the holder thereof to a share of the revenues from oil and natural gas production from those producing properties. The proceeds from sales of working interest may be used to finance the acquisition of new properties, to finance other Partnership operations or to provide funds for distribution to partners.

Sale of Net Profits or Other Non-Operating Interests. The Partnership may sell to third parties or its affiliates net profits, overriding royalty or other non-operating interests that will burden the Partnership’s interest in Partnership properties in order to finance Partnership operations. Net profits, overriding royalty or other non-operating interests are real property interests that entitle the holder thereof to a share of the revenues from oil and natural gas production from those producing properties. The proceeds from sales of net profits, overriding royalty or other non-operating interests burdening Partnership properties may be used to finance the acquisition of new properties, to finance other Partnership operations or to provide funds for distribution to partners.

PARTICIPATION IN DISTRIBUTIONS, PROFITS AND LOSSES

Participation in Cash Distributions

“Net Cash” means the gross cash proceeds of the Partnership from all sources, reduced by (i) Capital Contributions, and (ii) amounts used to pay or establish reserves for all Partnership expenses, debt payments (except as may otherwise be provided in the partnership agreement), capital improvements, replacements and contingencies, all as determined by the Managing General Partner. Net Cash shall not be reduced by depreciation, amortization, cost recovery deductions or similar allowances, but shall be increased by any reductions of reserves previously established.

Except for distributions upon liquidation of the Partnership, cash distributions, if any, from operations will be made 21% to us (which includes the 1% interest in the Partnership for which we will contribute cash) and 79% to the Unit Holders pro rata.

Distributions to the limited and additional general partners will be allocated among them based on the relative number of Units that are held by the limited and additional general partners.

If and to the extent that we determine in our sole discretion that a partner (or partners) and/or we will have a tax liability for a taxable period as a result of the allocation of income, gain and profits from the Partnership that exceeds the amount of cash distributed to it from the Partnership for such taxable period, we are authorized to cause the Partnership to distribute cash to such partner (or partners) and/or us in such amounts as we determine to permit the payment of the tax liability. Any distributions that are made to a limited or additional general partner (or partners) and/or to us for tax purposes shall be considered to be advance distributions from the Partnership and will reduce the future operating distributions from the Partnership to the investor partner (or investor partners) and/or us to the extent of such tax distributions.

Profits and Losses

Each year profits generally will be allocated (i) first to the extent of and in the same proportion and ratio that any losses that were allocated to the limited or additional general partners and to us in prior years pursuant to (b) below, which have not previously been restored through an allocation of profits, and (ii) second to the limited and additional general partners and us in accordance with our respective entitlement to cash distributions. Except as limited by federal tax laws, losses generally will also be allocated (a) first to the extent of and in the same proportion and ratio that any undistributed profits that were previously allocated to the limited and additional general partners and us pursuant to (ii) above, and (b) second to us and the limited and additional general partners in accordance with our respective positive capital account balances.

For purposes of determining the amount of profits or losses that will be allocated among the partners as set forth above, the expense items that are specially allocated by the Partnership will not be taken into account. In addition, items of gross income and gain will be specially allocated to us in an amount equal to the amount that is distributed to us, which exceeds our capital contribution to the Partnership for our 1% interest as the Managing General Partner. If we receive distributions that exceed an amount equal to the sum of (i) the amount that we contribute to the Partnership for our 1% interest as the Managing General Partner and (ii) the amount of gross income that is allocated to us, the excess will be treated as a guaranteed payment to us.

Cash Distribution Policy

We will review the accounts of the Partnership at least monthly for the purpose of determining the net cash (as defined in the partnership agreement) that is available for distribution. These distributions, if any, will not be made on a regular or scheduled basis. The ability of the Partnership to make or sustain cash distributions will depend upon numerous factors. No assurance can be given that any level of cash distributions to the investor partners will be attained, or that any level of cash distributions can be maintained. In our discretion, and based upon the amount of funds available for distribution, we may make distributions on a monthly basis. In the event any unused capital contributions are returned to the limited and additional general partners, then we will notify the partners of the nature of the distribution. See “Risk Factors.”

Termination

Upon termination and final liquidation of the Partnership, the assets of the Partnership that remain after due provision has been made for, among other things, payment of all Partnership debts and liabilities will be distributed to the partners in accordance with their respective positive capital account balances after taking into account all contributions, distributions, and allocations for prior periods. No limited partner will have any obligation to make any contribution to the capital of the Partnership in the event such limited partner has a capital account deficit balance.

Amendment of Partnership Allocation Provisions

We are authorized to amend the partnership agreement if, in our sole discretion based on advice from our legal counsel or accountants, an amendment to revise the cost and revenue allocations is required or advisable for the allocations of profits and losses (or any item thereof) to be recognized for federal income tax purposes either because of the promulgation of Treasury Regulations or other developments in the tax law. Any new allocation provisions provided by an amendment are required to be made in a manner to conform as nearly as possible to the original allocations.

COMPENSATION TO THE MANAGING GENERAL PARTNER

The following table summarizes the items of compensation to be received by us and our affiliates from the Partnership:

We will purchase a 1% interest in the Partnership for an amount equal to 1% of the total Partnership capital.

Our affiliates and we will be reimbursed for direct costs and all documented out-of-pocket expenses incurred on behalf of the Partnership, including service fees which may be payable to our affiliates. We also will be reimbursed for general and administrative expenses reasonably allocable to the Partnership. Our general and administrative costs include all customary and routine expenses, accounting, office rent, telephone, secretarial, salaries and other incidental expenses incurred by us or our affiliates that are necessary to the conduct of the Partnership’s business, whether generated by us, our affiliates or by third parties, but excluding direct costs and operating costs.

The Partnership will reimburse the Managing General Partner and its affiliates for their costs relating to the evaluation and acquisition of Prospects and for costs relating to the development of Prospects. Acquisition costs include all reasonable and necessary costs and expenses incurred in connection with the evaluation and acquisition of a Prospect or arising out of or relating to the evaluation or acquisition of Prospects, including but not limited to all reasonable and necessary costs and expenses incurred in connection with searching for, screening and negotiating the possible acquisition of Prospects for the Partnership, the conduct of reserve analyses and other technical studies of Prospects for purposes of acquisition of Prospects, and the actual purchase price of a Prospect and any other assets acquired with such Prospects. Development costs include the cost of drilling, testing, completing, equipping, plugging, abandoning, deepening, plugging back, reworking, recompleting, fracturing and similar activities on the Partnership’s properties that are not defined as routine operating costs.

Our affiliates and we may enter into other transactions with the Partnership for services, supplies and equipment, and will be entitled to compensation at competitive prices and terms as determined by reference to charges of unaffiliated companies providing similar services, supplies and equipment. See “Conflicts of Interest.”

PROPOSED ACTIVITIES

The Partnership was formed to acquire interests in various oil and gas mineral rights, leases, producing wells, and drilling opportunities from our affiliate, EPCO, and potentially from unrelated third parties, including interests in oil and gas wells that may be in the process of being drilled at the time of acquisition. These opportunities are referred to collectively as the “Prospects” and individually as a “Prospect.” Prospects are expected to be located in Texas and Louisiana. However, the Partnership may acquire Prospects in other locations and may acquire Prospects that may employ non-conventional drilling techniques.

The Prospect Wells

Assuming all Units are subscribed, the Partnership intends to acquire (i) approximately 63% of the Working Interest (being approximately 47.03832% of the net revenue interest) in the Prospect wells to be located in the Polar Bear Field in West Baton Rouge Parish, Louisiana, currently owned by our affiliate, Energy Production Corporation (“EPCO”) (ii) 42% of the Working Interest (being approximately 32.76% of the net revenue interest) in the Prospect wells to be located in the Electra Arch Field in Wilbarger County, Texas currently owned by our affiliate, EPCO and (iii) all of the rights EPCO owns pursuant to a Farmout Agreement with Apache Permian Exploration and Production LLC in Prospect wells in, or to be drilled in, Reagan County, Texas. Unaffiliated third parties will hold the remaining working interest in the Prospect wells. Landowners and or unrelated third parties are also expected to retain landowner’s royalty or overriding royalty interest in the Prospect wells. Notwithstanding the proposed operations described above, we may abandon the Prospect wells if (i) granite or other practically impenetrable substance is encountered, (ii) a condition in the hole occurs which renders further drilling impractical, or (iii) the operator decides to abandon the Prospect wells because to do so is a commercially reasonable decision for the Partnership under the conditions or situation encountered.

Although we believe that commercial quantities of oil will exist in the Prospect wells, there can be no assurance that the Prospect wells will be successful in producing oil in commercial quantities, if at all.

Prospect Wells Summary

The Partnership Prospects currently identified and discussed in the offering circular are three specified large oil and gas fields which are producing from conventional reservoir rock situated on large anticline structures. These Prospects were discovered and/or extended beginning in 1974 with a 38-year partnership between E.R. Carpenter Chemical Company and Energy Production Corporation. These Prospects are conventional reservoir rock and do not require non-conventional (shale and limited permeability rock) expensive extraction methods like fracking. The identified Prospects’ finding and development costs range from $4-15 per barrel of oil and $0.50-$1.00 per MCF/natural gas from the conventional rock. The expensive extraction methods required by non-conventional reservoir rock, primarily hydraulic fracking, have been deemed by many to be harmful to the environment. These Prospects are expected to require only each reservoir’s natural pressure to extract the oil and gas. Historically, conventional oil and gas rock has generally been deemed superior to non-conventional rock in ultimate recovery of “original oil and gas in place” and finding and development costs, with the additional benefit of less environmental harm expected than the extraction methods of non-conventional extraction methods such as fracking, thus resulting in an anticipated reduced carbon footprint for the Partnership’s operations.

The Partnership intends to primarily utilize wind and solar generated electricity by contracting with Reliant Energy to furnish the electric power needed for drilling and producing oil and gas wells with the goal of reducing the carbon impact of the Partnership’s operations. Although the Partnership intends to focus on the above green energy technologies, it is not prohibited from, and may still engage in, drilling and production activities that do not employ green energy technologies.

Electra Arch Field on the Waggoner Ranch in Wilbarger County, Texas

The Electra Arch oilfield is located on the W.T. Waggoner Ranch, in Wilbarger County, Texas in the North Texas region. Electra Arch is a 20 mile-long oil and gas anticline with approximately 60 old oil fields dating back to the 1920s. The Waggoner Ranch, which is believed to be the largest contiguously-fenced ranch in the United States has over 500,000 acres and has produced more than 200 million barrels of oil since the 1920s, primarily from the Electra Arch anticline. Approximately 3,000 oil wells were drilled on the Electra Arch, comprising a large portion the oil produced from the Waggoner Ranch. However, relatively few wells were drilled below 2,500 feet. Most of the wells were drilled in the 1950s and 1960s by small operators.

In 2006, EPCO purchased 42% of the undivided oil and gas leasehold rights in and to 19,500 acres of the Electra Arch from Waggoner Ranch. Beginning that year, EPCO began to operate wells that drilled deeper inside and on the flanks of the old, shallow oilfields and discovered virgin oil pressures. EPCO currently owns 32.76% net revenue interest in the 19,500 acres of the Electra Arch oil and gas leaseholds. EPCO intends to sell all of its 42% working interest in its leasehold rights.

The following chart shows the Landowner Royalty Interest (“RI”), Working Interests (“WI”) and Net Revenue Interests (“NRI”) to be acquired or retained in the Prospect wells in the Electra Arch Field, assuming all 500 Units are subscribed.

Big Lake Field in Reagan County, Texas

The Big Lake oilfield is located in Reagan County in West Texas on University of Texas land, and is part of the Permian Basin, which became well known after the famous Santa Rita #1 well blew in 1923. According to a report published by the petroleum consulting firm Cawley, Gillespie and Associates, Inc., as of December 20, 2017, Big Lake oilfield has produced approximately 100 million barrels of oil from shallow drilling in conventional reservoir rock with a natural water drive mechanism. Approximately 129 million barrels have been produced from the Big Lake Field, primarily from 3,000-foot wells drilled in the Grayburg dolomite formation, and according to the report, 246 Grayburg wells have averaged 406,000 barrels of oil per well.

Energy Management Company (“EMC”), an affiliate of Energy Production Corporation, entered into a Farmout Agreement (the “Farmout Agreement”) with Apache Permian Exploration and Production LLC (“Apache”) in January 2018. EMC wholly merged with EPCO into 2019, with EPCO as the surviving corporation, and, upon that merger, EPCO was assigned the rights under the Farmout Agreement, resulting in EPCO becoming the operator pursuant to the Farmout Agreement. Pursuant to the Farmout Agreement, EPCO is authorized to engage in oil and gas operations as the operator on certain oil and gas leaseholds on University of Texas lands currently held by Apache. Pursuant to the Farmout Agreement, upon successfully drilling and completing a well on the leasehold, Apache will assign to EPCO a 20-acre oil and gas proration unit around said well, and EPCO would earn a 100% working interest (80% net revenue interest) in any subject well. EPCO intends to assign all of its rights under the Farmout Agreement to the Partnership including all of its rights to any oil and gas wells drilled by EPCO pursuant to the Farmout Agreement, and EPCO will serve as the operator.

The following chart shows the Landowner Royalty Interest (“RI”), Working Interests (“WI”) and Net Revenue Interests (“NRI”) to be acquired or retained in the Prospect Wells in the Big Lake Field, assuming all 2,000 Units are subscribed.

“Polar Bear” False River Field in West Baton Rouge Parish, Louisiana

Polar Bear Field is a deep Tuscaloosa gas field located in West Baton Rouge Parish, in close proximity to South Louisiana liquefied natural gas terminals. With an estimated reserve of 1 trillion cubic feet (“TCF”) natural gas and condensate, Polar Bear is believed to be the largest remaining undeveloped natural gas field onshore in the continental United States. It’s four-way dip structure is estimated to be 18,000 acres from syncline to syncline. The discovery well, the #1 H.H. White Jr. well, is the only well drilled on the oil and gas leaseholds to date, which have been designated as the 1,280-acre Sand Unit J by the Louisiana Conservation Commission. 

EPCO currently owns 63% of the working interests (47.03832% net working interest) in the Polar Bear Field, and intends to sell all of its working interests to the Partnership.

The following chart shows the Landowner Royalty Interest (“RI”), Working Interests (“WI”) and Net Revenue Interests (“NRI”) to be acquired or retained in the Prospect Wells in the Polar Bear Field, assuming all 2,000 Units are subscribed.

Other Areas of Interest

The Managing General Partner is also targeting other proven oil and gas plays throughout the United States including, but not limited to, multiple onshore plays located in Texas or Louisiana.

Matters Applicable to Oil and Gas Plays

We will evaluate any Prospect based on its oil and natural gas producing potential. Until the amount of funds available for the Partnership’s drilling activities is determined, the precise number of Prospects and wells to be drilled and developed, and the size of the working interests in any additional Prospects and wells, if any, to be acquired by the Partnership cannot be determined and the drilling budget cannot be formulated.

The Partnership’s capital used in drilling activities is expected to be devoted to the drilling of developmental wells. A developmental well is a well drilled close enough to a well that has already produced in the same formation and sold oil or natural gas so that the oil and gas reserves to be accessed by the development well are classified as “proven.” The reserves in a well that is to be drilled into such a formation but that is located at a distance from a producing well (or a well that has produced) greater than the commonly accepted well spacing limitations, however, usually must be classified as non-proven, and thus such well is an exploratory well. In the broader sense of the definition, the term “exploratory well” also applies to wells that are drilled in areas where there has been no oil or natural gas production, or wells that are drilled to a previously untested or non-producing zone in an area where there are wells producing from other formations. We do not anticipate that the Partnership will participate in drilling exploratory wells.

Interests in the wells to be drilled that may be acquired by the Partnership will be subject to landowners’ royalty interests and other royalty interests payable to unaffiliated third parties in varying amounts. In all of the wells to be drilled in the Prospects to be acquired, the Partnership is expected to acquire minority fractional working interests and will not have control over their drilling and development.

It is expected that an affiliate of Managing General Partner, EPCO, will serve as operator of the wells to be drilled in the three currently identified Prospects acquired by the Partnership. The operator is responsible to oversee all drilling, testing and completion operations. The operator is responsible for selling oil and natural gas production.

For purposes of Prospects not yet identified by the Partnership and in which the Partnership later chooses to invest in, there is no guarantee EPCO will serve as the operator of its wells. In general, the owners of a majority of working interest in a Prospect usually have the right to appoint or change the operator and determine various operations for the Prospect. If the Partnership obtains sufficient working interest that it can influence the selection of the operator of a Prospect, the Partnership may vote in favor of an entity designated by Managing General Partner, to be the operator. In acquiring interests in any Prospects, the Partnership will pay such consideration and make such contractual commitments and agreements as it deems fair, reasonable and appropriate. The actual number, identity and percentage of working interests or other interests in the Prospects to be acquired by the Partnership will depend upon, among other things, matters such as the total amount of capital contributions to the Partnership, the latest geological and geophysical data, availability and price of drilling services, tubular goods and services, approvals by federal and state departments or agencies, potentially agreements with other working interest owners, and continuing review of other Prospects that may be available.

The Managing General Partner, Joe Vaughan, David Vaughan, and/or their affiliates, for their sole benefit, may sell or otherwise dispose of Prospect interests not acquired by the Partnership or may retain a working interest in the Prospect wells and participate in the drilling and development of the Prospect wells on the same basis as the Partnership.

The Partnership may acquire interests in Prospects that are subject to operating agreements, or enter new operating agreements, with operators engaged to conduct and direct all operations for the Prospect. It is expected that third parties will serve as operators of the properties acquired by the Partnership, but an affiliate of ours may serve as the operator of some wells. The operators will be responsible to oversee all drilling, testing and completion operations for the Prospects covered by the operating agreements. Once a Prospect well is completed, the operator will be responsible for selling the oil and natural gas production from that Prospect. Any working interest owner may also propose future wells to be drilled on a Prospect where applicable.

The timing of any sale of Partnership properties in not currently contemplated and will depend upon market conditions. In our discretion, we may delay any proposed sale if the Partnership does not receive suitable offers from prospective buyers for a property or if market conditions do not warrant the sale of the property at that time. The amount of the sales proceeds will depend primarily upon the estimated reserves remaining in the properties at the time of the sale, the level of oil and natural gas production from the properties, and the price of crude oil and natural gas at that time. For varying reasons regarding operations, economics, or market conditions, we may make a determination that it is in the best interest of the Partnership to sell a Prospect, or part of a Prospect.

Title to Properties

The Partnership believes that the title to its oil and natural gas properties will be good and defensible in accordance with standards generally accepted in the oil and natural gas industry, subject to exceptions that, in the opinion of the Partnership, will not be so material as to detract substantially from the use or value of such properties. The Partnership’s properties will be typically subject, in one degree or another, to one or more of the following: royalties and other burdens created by the Partnership or its predecessors in title; a variety of contractual obligations (including, in some cases, development obligations) arising under operating agreements, farmout agreements, production sales contracts and other agreements that may affect the properties or their titles; liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors and contractual liens under operating agreements; pooling, unitization and communitization agreements, declarations and orders; and easements, restrictions, rights-of-way and other matters that commonly affect property. To the extent that such burdens and obligations affect the Partnership’s rights to production revenues, they will be taken into account in calculating the Partnership’s new revenue interests and in estimating the quantity and value of the Partnership’s reserves. The Partnership believes that the burdens and obligations affecting its properties will be conventional in the industry for properties of their kind.

Marketing of Oil and Natural Gas Production

We will have the authority to market the oil and natural gas production of the Partnership in connection with our day-to-day operations. In this connection, we may execute division orders, contracts for the marketing or sale of oil, natural gas or other hydrocarbons or other marketing agreements on behalf of the Partnership. It is anticipated that all sales of the oil and natural gas production will be to independent third parties.

Insurance

We intend to maintain various types of insurance coverage in amounts we deem appropriate. We believe the Partnership will maintain adequate amounts of insurance coverage to protect the Partnership from most losses. However, in the event the Partnership is held liable for a loss for which it has not obtained adequate insurance, it would reduce the cash available from the Partnership for distributions and might severely adversely affect the Partnership, including but not limited to total loss of all Partnership’s assets. Investor partners who are limited partners could lose up to the entire amount of their investment in the Partnership, but they would not be responsible for any additional amounts owed by the Partnership stemming from such a loss. General partners will be jointly and severally liable to the extent of such a loss.

Farmouts and Similar Arrangements; Disposition of Properties

Properties and various other contractual rights owned by the Partnership may under certain circumstances be sold to, farmed out or assigned to drilling or other programs organized by our affiliates, third parties or us. A “farmout” generally is an assignment of specific acreage conditioned upon the drilling of a well by the assignee, with an interest in the production retained by the property holder.

The timing of any sale of Partnership properties will depend upon market conditions. In our discretion, we may delay any proposed sale if the Partnership does not receive suitable offers from prospective buyers or if market conditions do not warrant the sale of the property at that time. The amount of the sales proceeds will depend primarily upon the estimated reserves remaining in the properties at the time of the sale, the level of oil and natural gas production from the properties, and the price of crude oil and natural gas at that time. Occasions may arise where we will determine to sell a Prospect, or part of it, earlier rather than keep and operate it. For varying reasons regarding operations, economics, or market conditions, we may make a determination that it is in the best interest of the Partnership to sell a Prospect, or part of a Prospect.

COMPETITION, MARKETS AND REGULATION

Competition

There are thousands of oil and natural gas companies in the United States. Competition is strong among persons and companies involved in the acquisition of oil and gas wells and production of oil and natural gas. We expect the Partnership to encounter strong competition. The Partnership will compete with entities having financial resources and staffs substantially larger than those available to the Partnership.

The national supply of natural gas is widely diversified, with no one entity controlling over 5%. As a result of deregulation of the natural gas industry by Congress and the Federal Energy Regulatory Commission (“FERC”), competitive forces generally determine natural gas prices. Prices of crude oil, condensate, and natural gas liquids are not currently regulated and are generally determined by competitive forces. Such competition may affect the ability of the Partnership to acquire producing oil and gas wells at prices we believe will be favorable.

Markets

The marketing of any oil and natural gas produced by the Partnership will be affected by a number of factors that are beyond the Partnership’s control and whose exact effect cannot be accurately predicted. These factors include:

The supply and demand balance of crude oil and natural gas in world markets has caused significant variations in the prices of these products over recent years. The North American Free Trade Agreement eliminated trade and investment barriers in the United States, Canada, and Mexico, resulting in increased foreign competition for domestic natural gas production. New pipeline projects recently approved by, or presently pending before, FERC as well as nondiscriminatory access requirements could further substantially increase the availability of natural gas imports to certain U.S. markets. Such imports could have an adverse effect on both the price and volume of natural gas sales from Partnership wells.

Members of OPEC establish prices and production quotas for petroleum products (which are not always followed by its members) from time to time with the intent of reducing the current global oversupply and maintaining, lowering or increasing certain price levels. We are unable to predict what effect, if any, such actions will have on both the price and volume of crude oil sales from the Partnership’s wells. In several initiatives, FERC has required pipeline transportation companies to develop electronic communication and to provide standardized access via the Internet to information concerning capacity and prices on a nationwide basis, so as to create a national market. Parallel developments toward an electronic marketplace for electric power, mandated by FERC, are serving to create multi-national markets for energy products generally. These systems will allow rapid consummation of natural gas transactions. Although this system may initially lower prices due to increased competition, it is anticipated to expand natural gas markets and to improve their reliability.

Regulation

The Partnership’s operations will be affected from time to time in varying degrees by domestic and foreign political developments, federal and state laws and regulations. State and federal governmental regulation of the oil and gas industry is in a potentially fluid situation and could change dramatically as a result of many outside factors, including a shift in the philosophy of the governmental environmental policies, continued increases in the price of oil and national security concerns.

Production. In most areas of operations within the United States the production of oil and natural gas is regulated by state agencies that set allowable rates of production and otherwise control the conduct of oil and natural gas operations. Among the ways that states control production is through regulations that establish the spacing of wells or in some instances may limit the number of days in a given month during which a well can produce.

Environmental. The Partnership’s drilling and production operations will also be subject to environmental protection regulations established by federal, state, and local agencies that in turn may necessitate significant capital outlays that would materially affect the financial position and business operations of the Partnership. These regulations, enacted to protect against waste, conserve natural resources and prevent pollution, could necessitate spending funds on environmental protection measures, rather than on acquisition and production activities. If any penalties or prohibitions were imposed on the Partnership for violating such regulations, the Partnership’s operations could be adversely affected.

Natural Gas Transportation and Pricing. FERC regulates the rates for interstate transportation of natural gas as well as the terms for access to natural gas pipeline capacity. Pursuant to the Wellhead Decontrol Act of 1989, however, FERC may not regulate the price of natural gas. Such deregulated natural gas production may be sold at market prices determined by supply and demand, Btu content, pressure, location of wells, and other factors. We anticipate that all of the natural gas produced by Partnership wells will be considered price decontrolled natural gas and that the Partnership’s natural gas will be sold at market value.

Proposed Regulation. In the past, Congress has been very active in the area of oil and gas regulation. In addition, legislative proposals are pending in various states that, if enacted, could significantly affect the petroleum industry.

We cannot predict whether any such federal, state or local laws or regulations will be enacted or repealed and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed through the adoption of new laws and regulations, the Partnership’s business and operations could be subject to delays, increased operating and compliance costs and process prohibitions.

No prediction can be made as to what additional legislation may be proposed, if any, affecting the competitive status of an oil and gas producer, restricting the prices at which a producer may sell its oil and/or gas, or the market demand for oil and/or gas, nor can it be predicted which proposals, including those presently under consideration, if any, might be enacted, nor when any such proposals, if enacted, might become effective.

Hydraulic fracturing is commonly used in completing oil and gas wells drilled today in the United States. Certain environmental and other groups have suggested that additional federal, state and local laws and regulations may be needed to more closely regulate the hydraulic fracturing process. We cannot predict whether any such federal, state or local laws or regulations will be enacted or repealed and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed through the adoption of new laws and regulations, the Partnership’s business and operations could be subject to delays, increased operating and compliance costs and process prohibitions. The Partnership does not plan on engaging in any hydraulic fracturing activities.

There are proposals in the U.S. Congress to, among other things, limit the disposal of waste water from wells and to impose federal laws on hydraulic fracturing of wells. No prediction can be made as to what additional legislation may be proposed, if any, affecting the competitive status of an oil and gas producer, restricting the prices at which a producer may sell its oil and/or gas, or the market demand for oil and/or gas, nor can it be predicted which proposals, including those presently under consideration, if any, might be enacted, nor when any such proposals, if enacted, might become effective.

On December 19, 2007, President Bush signed into law the Energy Independence and Security Act (“EISA”), a law targeted at reducing national demand for oil and increasing the supply of alternative fuel sources. While EISA does not appear to directly impact the Partnership’s operations or cost of doing business, its impact on the oil and gas industry in general is uncertain.

The Paris Climate Accords and Kyoto Protocol to the United Nations Framework Convention on Climate Change became effective in December 2015 and February 2005, respectively (the “Protocols”). Under the Protocols, participating nations are required to implement programs to reduce emissions of certain gases, generally referred to as greenhouse gases that are suspected of contributing to global warming. The United States is not currently a participant in either of the Protocols. However, the U.S. Congress has considered proposed legislation directed at reducing greenhouse gas emissions. In addition, there has been support in various regions of the country for legislation that requires reductions in greenhouse gas emissions, and some states have already adopted legislation addressing greenhouse gas emissions from various sources, primarily power plants. The natural gas and oil industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact the operations on wells by the Partnership. At this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would affect the Partnership’s business.

The preceding discussion of regulation of the oil and gas industry is not intended to constitute a complete discussion of the various statutes, rules, regulations or governmental orders to which well operations may be subject.

MANAGEMENT

General

We are Universe Energy, LLC (the “Managing General Partner” ), and we will serve as the managing general partner of the Partnership. We were formed for the principal purpose of engaging in energy acquisition, exploration, development and production activities directly or through business ventures such as the Partnership.

EPCO’s predecessor, a Texas corporation also named Energy Production Corporation, was formed in 1969. It was subsequently wound up and terminated in 2019, and a new Energy Production Corporation (“EPCO”) was incorporated in 2019 with Joe Vaughan as its sole shareholder and one of its directors. The Managing General Partner intends for EPCO to serve as the operator of oil and gas wells to be acquired for development on several of the Prospects owned by Partnership and serve as the provider of technical services to the Partnership. However, we may choose third-party operators or consent to the current operator of a Prospect to continue to serve as operator. EPCO may also serve as the provider of administrative services for partnerships sponsored by us and our affiliates, including the Partnership.

We, whether directly or through an affiliate, will actively manage and conduct the business and oversee the day-to-day operations of the Partnership. We will be responsible for acquiring interests in leases and producing oil and gas wells, negotiating farmout agreements or sales of leases, maintaining the Partnership’s bank accounts, collecting Partnership revenues, making distributions to the partners, and delivering reports to the partners. We have no employees and utilize the experienced Joe Vaughan and David Vaughan to conduct our business and manage the Partnership. Subject to limitations set forth in the partnership agreement, such individuals intend to continue to engage in the oil and natural gas business for their own account and for the account of others, independent of the Partnership. See ‘‘Conflicts of Interest.’’ We and such officers and employees will devote as much of their time and talents to the management of the Partnership as necessary for the proper conduct of the Partnership’s business.

Joe Vaughan and David Vaughan, our managers, oversee all aspects of prospect and project generation and review and intend to work closely with a technical staff that includes, but is not limited to, accountants, geologists, geophysicists, petrophysicists, paleontologists, drilling engineers, completion engineers, reservoir engineers, drilling rig supervisors, landmen, surveyors and other specialists with expertise in the search, acquisition, development, exploitation and day-to-day operations associated with petroleum exploration and production.

We intend for EPCO to serve as operator of several of the Prospects acquired or developed by the Partnership. However, even in some cases where EPCO may have the opportunity to serve as operator, we may choose third-party operators or consent to the current operator continuing to serve as operator. In the case where we may choose the operator, and if we choose not to select EPCO, we will choose a third-party operator who is experienced in the operation of oil and natural gas properties. EPCO currently serves as the operator of one well in the Polar Bear field.

Management of the Managing General Partner

Joe E. Vaughan and David W. Vaughan are the managers of the Managing General Partner. Joe Vaughan is the father of David Vaughan.

Joe Earl Vaughan, 89, is the sole member and a manager of the Managing General Partner and is the sole shareholder and a director of EPCO. EPCO’s predecessor by the same name was formed in 1969. The original Energy Production Corporation was wound up and terminated in 2019. Subsequently to that termination, a new Energy Production Corporation was formed and continues operations today. Mr. J. Vaughan has nearly 65 years of experience in the oil and gas industry beginning in 1956. Most notably, in 1974, Mr. J. Vaughan formed an oil and gas partnership with Carpenter Chemical Company (Carpenter), known as COG-EPCO Limited Partnership, with EPCO serving as managing partner. COG-EPCO engaged in a 38-year wildcat operation in oil and gas fields across the U.S, resulting in the discovery and/or extension of the Prospects. Prior to his tenure with COG-EPCO, he worked for various oil and gas companies, including Continental Oil Company (Conoco) as a petroleum geologist, and with both Texas Eastern Transmission and Hunt Oil Company as a geological engineer. Between 1966-1974, he worked as an attorney with a focus on oil and gas securities law and also served in an advisory role with the SEC assisting with legal, geological and engineering technical matters related to the oil and gas industry. Mr. J. Vaughan also previously served as an officer in the United States Air Force. Mr. J. Vaughan obtained his bachelor’s degree in geology from the University of Texas in 1954 and his Juris Doctor from Southern Methodist University in 1965. He has been a member of the American Association of Petroleum Geologists, Society of Petroleum Engineers, Society of Petroleum Evaluation Engineers, the American Bar Association and the Texas Bar Association for more than 50 years.

David William Vaughan, 62, is a manager of the Managing General Partner and has served as a director and the president of EPCO since 2019. Mr. W. Vaughan also served as Vice-President and General Counsel for EPCO from 1993-2010. Between 2011-2019, David served as the president of Energy Management Company. Mr. W. Vaughan has 28 years of experience in the oil and gas industry, including lease acquisitions, litigation management, environmental and regulatory human resources, risk management and lease/title contract negotiation. He also worked in private practice as an attorney prior to beginning his tenure with EPCO. He obtained his bachelor’s degree in liberal arts from Rice University in 1981 and his Juris Doctor from Southern Methodist University School of Law in 1984.

Security Ownership of the Managing General Partner

Significant Employees

Chet McLain, 62, is the Vice President of Geosciences for the Managing General Partner. Prior to taking this role, he served as Exploration and Operations Manager for EPCO where he directed exploration and development programs in the East Texas salt dome, North Texas shallow oil project, among others. Prior to his work with the Managing General Partner, he held technical management positions for Mustang Fuel Corporation and American Cometra, Inc. Mr. McLain has 33 years of experience in the oil and gas industry with experience overseeing exploration projects and development teams and planning, acquiring, and interpreting 3D seismic surveys. Mr. McLain holds a bachelor’s degree in geology and mathematics from Stephen F. Austin University, is a Texas licensed Professional Geoscientist, an American Association of Petroleum Geologists Certified Petroleum Geologist, and a member of the Society of Exploration Geophysicists.

Compensation

No officer, manager or director of Universe Energy, LLC or EPCO or its affiliates will receive any direct remuneration or other compensation from the Partnership.

Legal Proceedings

Neither the Partnership nor the Managing General Partner is the subject of any litigation as of the date of this offering circular. In the ordinary course of business, affiliates of the Partnership and the Managing General Partner may from time to time be engaged in routine or material litigation. Further information regarding any legal proceedings that any such affiliates are involved in will be provided upon request.

CONFLICTS OF INTEREST

Our affiliates and we have interests that differ in certain respects from those of the Partnership and the investor partners. Prospective investor partners should recognize that relationships and transactions of the kinds described below involve inherent conflicts between the interests the Partnership, us and our affiliates, and that the risk exists that these conflicts will not always be resolved in a manner that favors the Partnership.

Property Transactions – Acquisitions from Our Affiliates and Us. The partnership agreement permits sales of properties to the Partnership by our affiliates and us. The Partnership’s cost will be the fair market value of the properties as reasonably determined by us. Though it is anticipated that third party opinions will be considered, no formal independent third-party valuation of the properties to be acquired by the Partnership from any affiliate of EPCO has been conducted, nor do we anticipate commissioning such a formal valuation. As such, there are conflicts of interest associated with our determination of fair market value since such costs will not be determined by arm’s-length negotiation, and the cost to the Partnership may not necessarily reflect the value that would be assigned to such properties if a third party appraisal were to be conducted.

If we determine that less than all of our or our affiliates’ interest in a property or Prospect should be acquired by the Partnership, either our affiliates or we may retain our proportionate interest in the property or Prospect or we may transfer such interest to third parties. Since the Partnership will not have expended any funds with respect to the interest transferred by our affiliate, or us, any profit recognized from the transfers will be solely for our or our affiliates’ account.

Transactions between the Partnership and Operator. One of our affiliates may act as an operator for wells acquired or drilled by the Partnership. As a result, we may be confronted with a continuing conflict of interest with respect to the exercise and enforcement of the rights of the Partnership under operating agreements.

Prior and Future Programs Sponsored/Managed by Our Affiliates. Joe Vaughan and David Vaughan may organize and manage oil and natural gas programs in the future that will have substantially the same investment objectives as the Partnership. Furthermore, our EPCO currently operates and oil and natural gas property in the Polar Bear Field. We will decide whether a property will be retained or acquired for the account of the Partnership or for other programs that our affiliates may manage. As a result, the Partnership will compete with these other programs for suitable properties, equipment, contractors and personnel. To resolve conflicts, we will initially examine the funds available to the Partnership and the time limitations on the investment of funds to determine whether the Partnership or another program should acquire a potential property.

Fiduciary Responsibility of the Principals of the Managing General Partner. Our principals serve as principals and as fiduciaries and have a duty to exercise good faith and to deal fairly with the limited and additional general partners in handling the affairs of the Partnership. Our principals will owe such a duty to other partnerships our affiliates may currently manage and manage in the future. Because our principals must deal fairly with the investor partners in affiliated programs, if conflicts between the interest of the Partnership and these other programs do arise, they may not in every instance be resolved to the maximum advantage of the Partnership, and our principals’ actions could fall short of the full exercise of their fiduciary duty to the Partnership. If a breach of fiduciary duty occurs, a limited partner would be entitled to an accounting and to recover any economic losses caused by the breach only after either proving a breach in court or reaching a settlement with us.

Property Transactions – Farmouts or Sales. We expect that the Partnership will farmout few, if any of its leases or property interests. Because we may farmout or sell such properties to our affiliates, the decision to make farmouts or sales and the terms thereof involve conflicts of interest. A farmout or sale may permit us to achieve cost savings and reduce our risks. Further, in the event of a farmout or sale to an affiliate, we or our affiliates will represent both related entities.

Managing General Partner’s Interest. Although we believe that our interest in Partnership profits, losses, and cash distributions is equitable (see “Participation in Distributions, Profits and Losses”), our interest was not determined by arm’s-length negotiation.

Receipt of Compensation Regardless of Profitability. We are entitled to receive the Management Fee and reimbursement for certain costs from the Partnership, regardless of whether the Partnership operates at a profit or loss. See “Compensation to the Managing General Partner.” These fees and reimbursements will decrease the investor partners’ share of any cash flow generated by operations of the Partnership or increase losses if operations should prove unprofitable.

Time and Services of Common Management. Our officers and manager are also officers, directors or employees of our affiliates. As a result, they do not intend to devote their entire time to the Partnership. Management is required to devote to the business and affairs of the Partnership so much time as is, in their judgment, necessary to conduct such business and affairs in the best interest of the Partnership.

Legal Representation. Counsel to the Partnership and us are the same in connection with the organization and formation of the Partnership. The Partnership has not engaged its own counsel. The Managing General Partner has not engaged independent counsel to represent it in this offering.

Other Relationships. We and our affiliates will have relationships on an ongoing basis with companies engaged in the oil and natural gas industry, including operators, petroleum engineers, consultants and financial institutions. These relationships could influence us to take actions, or forbear from taking actions, which we might not take or forbear from taking in the absence of these relationships.

FIDUCIARY RESPONSIBILITY OF THE MANAGING GENERAL PARTNER

Fiduciary Duty. We are accountable to the Partnership as a fiduciary and consequently must exercise utmost good faith and integrity in handling Partnership affairs. In this regard, we are required to supervise and direct the activities of the Partnership prudently and with that degree of care, including acting on an informed basis, which an ordinarily prudent person in a like position would use under similar circumstances. Moreover, we have a responsibility for the safekeeping and use of all funds and assets of the Partnership, whether or not in our control, and may not employ or permit another to employ such funds or assets in any manner except for the exclusive benefit of the Partnership.

Generally, courts have held that a partner may institute legal action on behalf of himself and all other similarly situated partners (a class action) to recover damages for a breach by a managing general partner of its fiduciary duty, or on behalf of the partnership (a partnership derivative action) to recover damages from third parties. In addition, partners may have the right, subject to procedural and jurisdictional requirements, to bring partnership class actions in federal courts to enforce their rights under the federal securities laws. Further, partners who have suffered losses in connection with the purchase or sale of their interests in a partnership may be able to recover such losses from a managing general partner where the losses result from a violation by the managing general partner of the antifraud provisions of the federal securities laws. The burden of proving such a breach, and all or a portion of the expense of such lawsuit, would have to be borne by the partner bringing such action. In the event of a lawsuit for a breach of its fiduciary duty to the Partnership /or the partners, depending upon the particular circumstances involved, we might be able to raise various defenses to the lawsuit, including statute of limitations, estoppel, laches, and doctrines such as the “unclean hands” doctrine.

Investor partners who have questions concerning our responsibilities should consult their own legal counsel.

Indemnification. The partnership agreement provides for our indemnification against liability for losses arising from our action or inaction if such indemnification is permitted under the TBOC. Subject to compliance with the requirements of the TBOC, indemnification is generally permitted if: (a) we acted in good faith and reasonably believed that our conduct was in the best interests of the Partnership, or (b) we were not acting in our official capacity on behalf of the Partnership and our conduct was at least not opposed to the Partnership’s best interests, and (c) in the case of any criminal proceeding, we had no reason to believe our course of conduct was unlawful.

A successful claim for indemnification would deplete Partnership assets by the amount paid. As a result of such indemnification provisions, a purchaser of Units may have a more limited right of legal action than he would have if such provision were not included in the partnership agreement. To the extent that the indemnification provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the Commission, such indemnification is against public policy as expressed in the Securities Act, and is, therefore, unenforceable.

TAX CONSIDERATIONS

EACH PROSPECTIVE INVESTOR PARTNER SHOULD SEEK ADVICE BASED ON THE TAXPAYER’S PARTICULAR CIRCUMSTANCES FROM AN INDEPENDENT TAX ADVISER.

The full implications of federal, state and local laws that may affect the tax consequences of participating in the Partnership are too complex and numerous to describe in this offering circular. Therefore, each potential investor partner should satisfy himself as to the federal and state income and other tax consequences of participating in the Partnership by obtaining advice from their own tax counsel.

FEDERAL INCOME TAX CONSEQUENCES FROM PARTICIPATION IN THE PARTNERSHIP AS A GENERAL PARTNER MAY DIFFER MATERIALLY FROM THOSE FROM PARTICIPATION AS A LIMITED PARTNER.

FEDERAL INCOME TAX CONSEQUENCES FROM PARTICIPATION IN THE PARTNERSHIP MAY DIFFER MATERIALLY DEPENDING ON THE TIME OF INVESTMENT RELATIVE TO WHEN THE PARTNERSHIP UNDERTAKES DRILLING OF A WELL.

No assurance can be given that legislative or administrative changes or court decisions may not be forthcoming which would significantly modify the statements expressed herein. Any such changes may or may not be retroactive with respect to transactions prior to the dates of such changes.

This discussion summarizes the material federal income tax considerations associated with investments in the Partnership. It is based on the Internal Revenue Code of 1986, as amended (the “Code”), Treasury Regulations, published revenue rulings and procedures of the Internal Revenue Service (“IRS”), reports of congressional committees and judicial decisions, all as in effect on the date of this offering circular. Any of these authorities could be changed at any time, possibly on a retroactive basis, and any such change could affect the applicability of this discussion.

THIS DISCUSSION DOES NOT ATTEMPT TO PRESENT A DETAILED EXPLANATION OF THE FEDERAL INCOME TAX TREATMENT OF THE PARTNERSHIP AND IS DIRECTED PRIMARILY TO AN INVESTOR PARTNER WHO IS CURRENTLY AN INDIVIDUAL AND A CITIZEN OF THE UNITED STATES NOT RESIDING ABROAD. ADDITIONAL CONSIDERATIONS NOT ADDRESSED IN THIS DISCUSSION MAY APPLY TO AN INVESTOR PARTNER THAT IS A CORPORATION, ESTATE, PARTNERSHIP, TAX-EXEMPT ENTITY, TRUST OR INDIVIDUAL NOT A CITIZEN OF THE UNITED STATES RESIDING WITHIN ITS BORDERS. MOREOVER, THIS DISCUSSION ASSUMES THAT EACH PARTNER PURCHASES HIS UNITS TO MAKE A PROFIT IN THE PARTNERSHIP, ASIDE FROM ANY TAX BENEFITS THE PARTNER MIGHT REALIZE. COUNSEL TO THE PARTNERSHIP HAS RENDERED NO OPINION AS TO THE ACTUAL OR INTENDED TAX CONSEQUENCES OF THE PARTICIPATION FOR ANY INVESTOR PARTNER.

Additional facts or circumstances applicable to any particular partner may give rise to federal income tax consequences not addressed in this discussion. Investment in the Partnership may also have state and local tax consequences, which are also not addressed in this discussion. State and local taxes could include ad valorem taxes, estate taxes, income taxes, inheritance taxes, production taxes, sales taxes and severance taxes. Accordingly, each investor partner should consult his tax adviser prior to investing in the Partnership.

The federal income tax consequences of an investment in the Partnership, and the ramifications of those consequences to the Partners, will, in some instances, depend upon determinations of fact as well as interpretations of unclear provisions of federal income tax law. When making these determinations and interpretations, Universe Energy, LLC (“Managing General Partner”), a Texas limited liability company, as the Managing General Partner of the Partnership, intends to act in the best interest of the Partnership. Universe Energy, LLC, as the Managing General Partner of the Partnership, intends to consult, when appropriate, legal counsel or other professional tax advisers on these types of matters. Managing General Partner has not requested any rulings from the IRS concerning the Partnership or the federal income tax consequence of investing in the Partnership.

The Partnership has not requested, nor will it request, a ruling from the IRS with respect to any of the federal tax issues discussed below, and there is no assurance that favorable rulings would be issued if requested.

However, it should be noted that there is uncertainty concerning various tax aspects of partnerships generally, and of the tax consequences of an investment in the Partnership in particular. This results, at least in part, from uncertainties as to the application of provisions in the Code, as to many of which final or even proposed interpretive Treasury Regulations have not been issued. In addition, many of the provisions of the Code are complex, unclear or both, while still others leave to the Treasury Department, through the issuance of Treasury Regulations, the implementation of Congressional intent. Furthermore, the resolution of certain material tax issues is largely dependent upon questions of fact upon which counsel cannot opine.

Moreover, although the Partnership will be guided by professional tax advisers, there is uncertainty concerning various tax aspects of oil and gas partnerships. Further, the existence and amount of particular deductions anticipated to be taken by the Partnership may depend upon various determinations (including the characterization of certain expenses) which are subject to potential controversy on factual or other grounds.

There can be no assurance, therefore, that some of the deductions claimed by the Partnership or the allocation of items of income, losses and credits among the Partners, may not be challenged by the IRS. Final disallowance of such deductions or reallocation of such items would adversely affect the Partners.

The IRS has announced that it is paying increased attention to the proper application of the tax laws to partnerships. An audit of the Partnership’s information returns may precipitate an audit of the individual income tax returns of the Partners. Prospective investor partners should also be aware that, if the IRS proposes to adjust any items of income, gain, deduction, loss or credit reported on a partnership information return, corresponding adjustments could be proposed, depending on elections made by the Managing General Partner in its capacity as the Partnership Representative, with respect to the individual income tax returns of the Partners. Further, any such audit might result in the IRS making adjustments to items of non-partnership income or loss. Moreover, even if the IRS is unsuccessful in its challenge, the partners should recognize that they and/or the Partnership might incur substantial legal and accounting costs in defending a challenge by the IRS.

The Partnership and/or the partners may be subject to taxes other than federal income taxes, such as foreign income taxes, net investment income taxes, self-employment taxes, severance taxes, state and local taxes and estate or inheritance taxes, which may be imposed by various jurisdictions.

It is not feasible to present in this offering circular a detailed explanation of partnership tax treatment or the resulting tax consequences to investor partners. Each prospective partner is strongly urged to consult his own tax adviser, attorney or accountant with specific reference to his own tax situation in order to be satisfied as to the tax consequences of an investment in the Partnership.

The discussion below is a general description of some of the federal income tax aspects of participation in the Partnership described herein. This summary, while not exhaustive, includes a discussion of the material tax issues involving a reasonable possibility of challenge by the IRS. The discussion is directed primarily toward individual taxpayers who are citizens of the United States. PERSONS WHO ARE NOT UNITED STATES CITIZENS, AS WELL AS TAX-EXEMPT ENTITIES, CORPORATE ENTITIES IN GENERAL AND CORPORATE ENTITIES THAT ARE SUBJECT TO SPECIALIZED RULES (e.g., S CORPORATIONS OR INSURANCE COMPANIES), AND TRUSTS ARE CAUTIONED TO CONSULT THEIR TAX ADVISERS BEFORE PARTICIPATING IN THE PARTNERSHIP.

Some of the federal income tax aspects applicable to the Partnership are unsettled and not free from doubt. Moreover, in determining the deductibility of certain expenditures made by the Partnership, there are many factual and legal questions involved, including, but not limited to, the proper characterization of income and expenses, the reasonableness of amounts involved, the purpose of the expenditures and the period or periods to which the expenditures are properly attributable. Prospective partners should not read this summary as a prediction of a favorable outcome of the tax issues concerning the Partnership which no favorable prediction is made.

The material tax benefits of participating in the Partnership as a general partner will be the deductions attributable to intangible drilling and developments costs (“Intangible Costs”), accelerated cost recovery on equipment and other tangible property and, if production is achieved, depletion to the extent that the Partnership ultimately engages in drilling and development activities. Counsel to the Partnership will express no opinion as to the amount of costs that are properly treated as Intangible Costs. PARTNERS WHO INVEST IN THE PARTNERSHIP AFTER COMMENCEMENT OF DRILLING OPERATIONS WILL NOT BE ELIGIBLE TO EXPENSE ALL OR A PORTION OF INTANGIBLE DRILLING COSTS. There can be no assurances that some of the deductions taken by the Partnership will not be challenged and disallowed in whole or in part or permitted as deductions only in a subsequent taxable year of the Partnership.

Investor partners who invest as limited partners will be subject to the passive activity loss rules of the Code and may not be able to immediately deduct Intangible Costs and losses from Partnership operations depending upon their individual tax situations.

Some income and gains from the Partnership may be classified as portfolio income and therefore unable to be offset as passive losses. All Partners, whether general partners or limited partners, will be subject to the limitation on deduction of excess business losses enacted as part of the Tax Cuts and Jobs Act., as modified by the Coronavirus Aid, Relief and Economic Security (CARES) Act.

Prospective partners should be aware that the Partnership might initially report tax losses from operations primarily resulting from the payment and deduction of Intangible Costs. As discussed below, the partners could thereafter recognize substantial taxable income if the Partnership drills a producing well. Intangible Costs and depletion, to the extent they reduce the basis of the property, are subject to recapture at ordinary income tax rates on the sale or disposition of a partnership interest by a partner in the Partnership or on the sale of disposition of the prospect by the Partnership. To the extent allowed, the deductions afforded in the early years of the Partnership could operate to defer to later years, but not eliminate, a general partner’s overall federal income tax liability. Any gain from the sale or disposition of a partner interest will be taxed at ordinary rates to the extent attributable to unrealized receivables (which term includes recapture of depreciation, depletion and Intangible Costs). Therefore, the tax benefit for any particular prospective partner may derive from participating in the Partnership will depend, in part, on the value of such a tax deferral to the partner and whether the partner is a general partner or a limited partner.

While the Partnership must file federal income tax returns, the Partnership is not generally required to pay any federal income tax. However, an audit of the Partnership by the IRS could result in tax liability imposed at the Partnership level, depending on elections made by the Managing General Partner in its capacity as the Partnership Representative. Each partner reports on his individual federal income tax return his distributive share of income, gains, losses, deductions and credit of the Partnership, irrespective of any actual cash distributions made to such partner during his taxable year. Thus, both general partners and limited partners may incur tax liability without receiving distributions of cash to pay the tax liability. The State of Texas levies franchise (gross margin) tax on the income of limited partnerships that do not qualify as passive entities. Other state taxes are levied on oil and gas production.

Changes in the Tax Law

The Tax Cuts and Jobs Act (the “TCJA”) was enacted December 22, 2017. The TCJA makes major changes to the federal income tax laws and includes provisions that may affect a potential investor partner in the Partnership. Among other things, for tax years beginning after December 31, 2017, and ending before January 1, 2026, the TCJA:

The TCJA makes the following permanent changes, among others:

The Biden administration has proposed various changes to the Code that alone or in combination, if enacted, could have a material adverse effect on oil and gas entities, the Partnership and/or individual prospective investor partners in general and/or limited partnership units. Among those proposals are the following:

Various Senators and members of Congress have also made additional proposals that, if enacted, could have a material adverse effect on the Partnership and/or an investment in the Partnership. Among those proposals are elimination of the ability to immediately expense intangible drilling costs and elimination of percentage depletion. Enactment of either or both of these proposals could have a material adverse effect on an investment in the Partnership.

On July 13, 2021, Senate Democrats announced a broad agreement for a $3.5 trillion spending deal to fund various infrastructure proposals. However, tax provisions to pay for the bill are still being negotiated.

The Managing General Partner cannot predict which, if any, of the tax proposals would ultimately be enacted into law.

EACH PROSPECTIVE INVESTOR PARTNER SHOULD SATISFY HIMSELF AS TO THE INCOME AND OTHER TAX CONSEQUENCES OF INVESTING IN THE PARTNERSHIP BY OBTAINING ADVICE FROM HIS OWN TAX ADVISER.

There can be no assurance that the current federal income tax treatment accorded an investment in the Partnership will not be modified or eliminated by legislative, administrative, or judicial action at any time. Any changes may, or may not, be retroactive with respect to transactions prior to the effective date thereof. Each prospective partner should seek and must rely on the advice of his own tax adviser with respect to the possible impact on his investment of any proposed tax legislation or administrative or judicial action.

It is not practical to comment on all the federal, state, and local income tax laws that may affect the tax consequences of an investment in the Partnership. However, each of the federal tax issues that counsel to the Partnership believes to be material is discussed below. There can be no assurance that the federal income tax laws affecting the Partnership and its intended operations and activities will not be changed retroactively or prospectively through new legislation by Congress, by Treasury Regulations, and/or by court decisions, any of which could adversely affect the Partnership and the partners.

EACH PROSPECTIVE INVESTOR PARTNER SHOULD SATISFY HIMSELF AS TO THE INCOME AND OTHER TAX CONSEQUENCES OF INVESTING IN THE PARTNERSHIP AS A GENERAL PARTNER OR AS A LIMITED PARTNER BY OBTAINING ADVICE FROM HIS OWN TAX ADVISER.

Anti-Abuse Regulations

The IRS has adopted Treasury Regulation Section 1.701-2 to prohibit abuses of the partnership provisions of the Code found in Subchapter K. This Treasury Regulation is generally effective to transactions involving a partnership on or after May 12, 1994. Special rules giving the IRS power to treat a partnership as an aggregate of its partners are effective for transactions involving a partnership that occurs on or after December 29, 1994.

Under Reg. Sec. 1.701-2, if a partnership is formed or availed of in connection with a transaction, a principal purpose of which is to reduce substantially the present value of the partners' aggregate federal tax liability in a manner inconsistent with the intent of Subchapter K of the Code, the IRS can recast the transaction. In such a case, the IRS can recast the transaction for federal tax purposes, in light of the applicable statutory and regulatory provisions and the pertinent facts and circumstances.

For example, the IRS can determine that (1) the purported partnership should be disregarded, in whole or in part, and the partnership's assets and activities should be considered, in whole or in part, to be owned and conducted, respectively, by one or more of its purported partners, (2) one or more of the purported partners of the partnership should not be treated as a partner, (3) the methods of accounting used by the partnership or a partner should be revised to reflect clearly the partnership's or the partner’s income, (4) the allocations of the partnership's items of income, gain, loss, deduction, or credit should be reallocated, or (5) the intended tax treatment should otherwise be adjusted or modified. The IRS is also given the power under the Treasury Regulation to treat a partnership as an aggregate of its partners, in whole or in part, as appropriate to carry out the purpose of any Code or Treasury Regulation provision.

Reg. Sec. 1.701-2 lists the following factors as illustrative, but not necessarily establishing, use for a partnership inconsistent with the intent of Subchapter K:

Classification of the Partnership for Tax Purposes.

Tax Status of the Partnership. The Partnership has not requested, and does not intend to request, a ruling from the IRS that it will be treated as a partnership for federal income tax purposes. Such treatment for federal income tax purposes solely depends on elections that the Partnership does or does not file.

Under the “check the box” Treasury Regulations, which became effective January 1, 1997, the Partnership should be treated as a partnership for federal income tax purposes because (i) the Partnership will be engaged in a trade or business and, therefore, pursuant to Treasury Regulation §301.7701-l(a)(2), it should be treated as a separate entity; (ii) pursuant to Treasury Regulation §301.7701-2(a), the Partnership should be treated as a business entity because it is not properly classified as a trust under Treasury Regulation §301.7701-2(b); (iii) the Partnership is a domestic, unincorporated entity with at least two members; and (iv) the Partnership will not elect to be classified as an association) and, therefore, should be treated as a partnership under the “default rule” of the Treasury Regulations.

If the Partnership were classified as an association for any taxable year, the Partnership would be taxed as a corporation, the taxable income of the Partnership for such year would be subject to federal income tax at corporate tax rates, the partners would be treated as shareholders and distributions by the Partnership, if and when made, would be taxable to the partners as dividends or otherwise treated as corporate distributions. In such event, there would be no flow through of items of Partnership income, deduction, gain or loss to the Partner, with the result that most of the tax benefits mentioned below would not be available to the partners.

Publicly Traded Partnership Rules. Section 7704 treats certain “publicly traded partnerships” as corporations for federal income tax purposes. Section 7704 defines a publicly traded partnership as a partnership in which he interests are traded on an established securities market or are readily tradable on a secondary market or the substantial equivalent of a secondary market.

Treasury Regulations have been issued that establish a safe harbor exception to the application of Section 7704. Under the Treasury Regulations, interests in a partnership are not readily tradable on a secondary market or the substantial equivalent thereof if (1) all interests in the partnership were issued in transactions not required to be registered under the 1933 Act and (2) the partnership does not have more than 100 partners at any time during the taxable year of the partnership. Reg. Sec. 1.7704-1(h)(1). The Treasury Regulations contain anti-avoidance rules to be applied in determining the number of partners in the partnership. Under these anti-avoidance rules, a beneficial owner owning an interest in a partnership, grantor trust, or S corporation that owns, directly or through other pass-through entities, an interest in the partnership is treated as a partner in the partnership only if (1) substantially all of the value of the beneficial owner’s interest in the flow-through entity is attributable to the flow-through entity’s direct or indirect interest in the partnership and (2) a principal purpose of the use of the tiered arrangement is to permit the partnership to satisfy the 100-partner limitation described above. Reg. Sec. 1.7704-1(h)(3). The Partnership may have more than 100 partners so the ability to satisfy this safe harbor is uncertain.

In any event, Section 7704 is specifically inapplicable to a partnership for any year if at least 90% of the partnership gross income for such year and all preceding years consists of, among other things, interest or income from the exploration, development, production, processing, refining, transportation, or marketing of oil and gas and gains from the sale of assets used to generate the income. Sections 7704(c)(2) and 7704(d)(1)(E) and (F). The Managing General Partner believes that the Partnership will satisfy this test each year on an annual basis. Failure to meet this test and classification of the Partnership as a corporation for federal income tax purposes could have a material adverse effect on the Partnership and its investor partners.

Farmout and Farmin Agreements. The partnership agreement authorizes the Partnership to enter into a Farmout under certain circumstances, and the Partnership intends to do so. A Farmout allows the holder of an oil and gas working interest (“Farmor”) to shift the initial well’s dry hole risk to another party through a sharing arrangement. In a typical transaction the Farmor might assign all (or a portion) of its working interest in a drill site to the assignee (“Farmee”) in exchange for the Farmee’s agreement to bear all costs of the obligation well on the drill site. Such agreement generally also provides that (i) the Farmee earns an interest in the Farmor’s additional acreage surrounding the drill site, (ii) the Farmee is entitled to payout on the obligation well, and (iii) after payout, a portion of the drill site working interest reverts to the Farmor.

Historically, for federal income tax purposes, the Farmee has deducted 100% of the Intangible Costs incurred in drilling the obligation well and has treated 100% of the capital expenses subject to depreciation. The IRS has taken the position in Revenue Ruling 77-176, 1977-1 C.B. 77, that although the Farmee is entitled to deduct the Intangible Costs actually paid or incurred in drilling and completing the obligation well, the transferred portion of the working interest in the Farmor’s additional acreage surrounding the drill site constitutes compensation in the form of property to the Farmee for undertaking the development project on the drill site. Consequently, the fair market value of such working interest determined as of the date of its transfer to the Farmee, is includable in the Farmee’s gross income in the year the well is completed or when the working interest in an additional acreage is transferred to the Farmee, whichever is earlier. With respect to the fraction of the working interest in the acreage exclusive of the drill site transferred by the Farmor to the Farmee, the Farmor is to be treated as having sold such interest for its fair market value on the date of transfer and having paid the cash proceeds to the Farmee as additional compensation to the Farmee for undertaking the development projects on the drill site. This treatment may result in taxable income to the Farmor, a factor generally not present under prior tax treatment of these types of transactions.

If the Partnership enters into a Farmout, the Managing General Partner will attempt to minimize the effect of Revenue Ruling 77-176 in negotiating any farmout or farmin transactions on behalf of the Partnership. However, to the extent any such transaction produces taxable income under the ruling, the Partnership’s tax liability attributable to such transaction may exceed cash distributed from the Partnership. In addition, the fair market value of such property is a factual question and may be adjusted by the IRS to produce additional tax liabilities for the Partnership.

Classification of Relationship with Other Working Interest Holders

Pursuant to any operating agreement that might be executed between the Partnership and the other holders of a working interest in a Prospect, the working interest holders would generally share costs and profits from the Prospect wells. See “TAX CONSIDERATIONS – Intangible Costs.” Under these circumstances, the working interest holders could be deemed to have created a partnership for federal income tax purposes even though no partnership exists between them under Texas law.

Section 761(a) permits the Partnership and the other working interest owners in a Prospect to exclude their arrangement from treatment as a partnership for federal income tax purposes. The Managing General Partner intends to include an agreement between the working interest holders to exclude themselves from treatment as a partnership under the Code in any operating agreement. The accountants for the Partnership will in such case file the appropriate election with the IRS.

Intangible Costs: Carried Interest. Reg. Sec. 1.612-4(a) provides that the Partnership may deduct as expenses the intangible drilling costs paid or incurred by it only to the extent the costs are attributable to its share of the total of all operating mineral interests in the well. To the extent the costs are attributable to the fraction of the total operating mineral interests held by others, they must be capitalized.

Under this concept, the IRS interprets the limitations set out in the Treasury Regulations to mean that, if a taxpayer contributes a disproportionate amount to the development of a property, in exchange for an interest in the property, he may deduct only that proportion of the intangible costs that equals his share of working interest income during the complete payout period

Only the intangible drilling costs allocable to the working interests held by the Partnership (and not any carried working interest) will be subject to deduction by the Partners, subject, however, to additional limitations in the passive activity loss rules discussed below

Intangible Costs. The Partnership intends to engage in the drilling and completion of one or more Prospect wells.

The Managing General Partner expects that the Partnership will initially allocate 99% of intangible drilling and development costs (“Intangible Costs”), prior to return of the investor partners’ capital measured as a group, to all investor partners, and 1% will be allocated to the Managing General Partner prior to return of the investor partners’ capital in the same manner as other allocable items under the partnership agreement. That percentage of allocation may change from time to time based on income allocations in the partnership agreement to the extent that the Partnership has income and gains from other sources and/or achieves return of investor partners’ capital. Allocations after the first point at which there is a return of current investors’ capital measured as a group will generally be 79% to the investor partners as a group and 21% to the Managing General Partner. Therefore, after the Partnership first achieves payout, allocations of Intangible Costs after the return of the investor partners’ capital will generally be 79% to the investor partners as a group and 21% to the Managing General Partner.

The Partnership may, but is not required to, execute one or more turnkey contracts that specifies a turnkey drilling price with the Managing General Partner or an affiliate of the Managing General Partner with respect to the Partnership’s share of the cost of drilling one or more wells on one or more of the Prospects as discussed in the offering circular.

Assuming proper elections by the Partnership, each General Partner will be entitled to deduct his share of the Intangible Costs that have been properly allocated to the general partners under the partnership agreement assuming such costs are properly classified as Intangible Costs and are not non-deductible capital costs or some other costs that are not currently deductible. Intangible Costs allocated to limited partners may not be immediately deductible under the economic performance and/or passive activity loss rules. The Managing General Partner intends to cause the Partnership to elect to deduct those expenses or costs that may be deducted pursuant to Code Section 263(c) and the Treasury Regulations issued, or to be issued, relating to the deduction of Intangible Costs.

It is possible that the costs allocable to drilling, testing and completing a well under a turnkey drilling contract will exceed the actual cost thereof and may exceed rates charged by third parties for similar wells in the locality. Although the Tax Court recognized in Brountas v. Commissioner 73 T.C. 491 (1979), that a markup over estimated cost is regularly charged by operators or drilling contractors for certain turnkey contracts, there is a risk that a portion of the costs paid by the Partnership and treated as deductible Intangible Costs could be reclassified as acreage acquisition costs, management fees, tangible costs or some other costs that are not currently deductible. If any such position of the IRS were sustained, the deductions attributable to that portion of the costs could be disallowed, reduced or delayed, and the tax liability of the partners could be increased. The allocation of the costs between deductible Intangible Costs, management fees, deductible other costs, non-deductible tangible costs and other non-deductible capital costs and the reasonableness thereof are factual issues and to a certain extent predicated upon future events. For that reason, counsel to the Partnership cannot predict the outcome of a challenge with regard to this matter.

There is a risk that a portion of the costs paid by the Partnership and treated as deductible Intangible Costs could be reclassified as acreage acquisition costs, management fees, tangible costs or some other costs that are not currently deductible. If any such position of the IRS were sustained, the deductions attributable to that portion of the costs could be disallowed, reduced or delayed, and the tax liability of the partners could be increased. The allocation of the costs between deductible Intangible Costs, management fees, deductible other costs, non-deductible tangible costs and other non-deductible capital costs and the reasonableness thereof are factual issues and to a certain extent predicated upon future events. For that reason, counsel to the Partnership cannot predict the outcome of a challenge regarding this matter.

This election to expense Intangible Costs will only apply to expenses incurred incident to and necessary for the drilling of wells and the preparation of wells for production of oil and gas. For purposes of this election to expense, the Third Circuit Court of Appeals and the IRS have defined a “well” as a shaft drilled in search of hydrocarbons, which is designed and drilled to be capable, on encountering hydrocarbons and on appropriate completion of the shaft by the operator, of conducting or aiding in the conduction of hydrocarbons to the surface. This definition of “well” excludes shafts, such as core drilling, that because of their design or manner in which they are drilled are incapable of conducting or aiding in the conduction of hydrocarbons to the surface. Such shafts are capable of solely yielding geological information. However, if an appropriately drilled shaft is drilled in search of hydrocarbons, it is a well regardless of whether there is an intent to produce hydrocarbons. See Sun Co. v. Commissioner, 677 F.2d 294 (3d Cir. 1982); Rev. Rul. 88-10, 1988-1 C.B. 112. The Managing General Partner believes that the Partnership intends only to drill shafts that meet this definition of “well” and that will be eligible for the election to expense. However, the partners will not be able to expense the costs of any shaft drilled by the Partnership that does not satisfy this definition.

The Treasury Regulations under the 1939 Code granting the option to expense intangibles, and the final regulations promulgated under the 1954 Code, require that the drilling be “undertaken” in order to expense intangibles. The interpretation of the word “undertaken” in Platt v. Commissioner, 18 T.C. 1229 (1952), aff'd, 207 F.2d 697 (7th Cir. 1953), makes the time at which the turnkey contracts to be executed by the Partnership critical. In the Platt case, the taxpayer acquired an interest in a lease on which a well was drilled to 11,200 feet. As part of the consideration for the assignee's payments to him, the assignor agreed to drill the well an additional 1,500 feet. At a later date, the taxpayer paid an additional sum, for which he did not receive any additional interest, but the assignor pledged to use such money in deepening the well. The last payment was deducted by the taxpayer, and the IRS did not question that item. However, the taxpayer also sought to deduct the entire cost for his interest on the basis that it was intangible drilling costs and, therefore, that the amount paid exceeded the taxpayer's proportionate cost of drilling to the 12,700-foot level. The court denied the deduction of any part of this amount, on the basis that the taxpayer had not undertaken the drilling of the well and that the assignor was the operator of the property and that it was he who had undertaken its development.

It is not entirely clear whether in reaching this conclusion the court considered the fact that the well undertaken by the assignor had been started before the assignee acquired his interest, or that the assignor was primarily responsible for the drilling. Some commentators believe that the term “undertaken” might refer to the assumption of the financial burden of development before development costs have been incurred. If this test were applied to the facts in the Platt case, it is clear that no portion of the taxpayer's costs applicable to the leasehold or the first 11,200 feet, which had been drilled before the assignment, would qualify as intangibles because the costs had been incurred before the taxpayer acquired his interest. The taxpayer could not, as to those costs, undertake the development of the well but could only assume or satisfy another's financial obligations. As to the cost of drilling the additional 1,500 feet contemplated in the original assignments, the taxpayer did not undertake the primary obligation of the costs but did agree to pay such costs by providing funds to the assignor to be used for that purpose. As to these costs, the taxpayer should be considered to have undertaken the development because the taxpayer assumed the financial responsibility before the costs had been incurred.

PROSPECTIVE INVESTOR PARTNERS WHO INVEST AFTER DRILLING OPERATIONS COMMENCE MAY NOT BE ELIGIBLE TO EXPENSE ALL OR A PORTION OF INTANGIBLE DRILLING COSTS. THIS MAY REDUCE CURRENT TAX BENEFITS TO THEM FROM AN INVESTMENT IN THE PARTNERSHIP.

If an oil or gas property of the Partnership or an interest in the Partnership is sold at a gain, amounts deducted for Intangible Costs must be recaptured on such disposition. Therefore, gain would be ordinary income to the extent Intangible Costs have been deducted if, but for the deduction, they would have been reflected in the adjusted basis of the property.

Moreover, integrated producers must capitalize 30% of otherwise deductible Intangible Costs. This 30% amount may be amortized over a 60-month period and the remaining 70% can be deducted in the year they are incurred or amortized over 60 months.

Reg. 1.461-1(a)(1) allows taxpayers using the cash method of accounting to deduct allowable expenses in the year that they are paid. This generally includes Intangible Costs that meet the guidelines discussed above. It is important to note that special rules apply to tax shelters, which are discussed below.

Code Section 461(i) provides special rules for the year in which a tax shelter may claim deductions. Here is how Code Section 461(i)(3) defines a tax shelter (any one of the three):

If the Partnership is classified as a tax shelter under the foregoing rules, the cash method of accounting would not be available to it, and the Partnership would be subject to economic performance rules of accrual accounting for the timing of income and deductions. This limitation may apply to the Partnership and require use of accrual method of accounting.

Although the issue is not free from doubt, the Managing General Partner believes that the Partnership may be required to use the accrual method of accounting because of the filing requirements under Regulation A of the federal securities laws. Unlike an offering under Regulation D of the federal securities laws, the offering of interests in the Partnership will be reviewed by the staff of the SEC and an audited balance sheet of the Managing General Partner of the Partnership must be filed with the SEC.

Additionally, more than 35% of the Partnership interests may be held by limited partners at some point in time and losses including Intangible Costs may be allocated to them causing a loss allocation in one or more years and causing the Partnership to fall within the Code Section 1256(e)(3)(B) definition of a syndicate.

In order to avoid doubt and the accounting costs involved if the Partnership were required to convert from the cash method to the accrual method, the Managing General Partner intends to cause the Partnership to use the accrual method of accounting.

Under Section 461(i), in the case of a tax shelter, economic performance with respect to amounts paid during the taxable year for drilling an oil or gas well shall be treated as having occurred within a taxable year if drilling of the well commences before the close of the 90th day after the close of the taxable year. Also, in the case of a tax shelter which is a partnership, in applying section 704(d) to a deduction or loss for any taxable year attributable to an item which is deductible by reason of Section 461(i)(2)(A), the term “cash basis” shall be substituted for the term “adjusted basis”, thereby limiting losses that can be claimed to cash basis in the interest. This limitation should not affect the partners as the Managing General Partner does not currently plan to cause the Partnership to incur debt.

Purchase of Existing Producing Wells. The cost associated with the purchase by the Partnership of existing producing wells must be capitalized. No Intangible Costs arise from the purchase of existing production.

The Managing General Partner expects that the Partnership will engage in the purchase of existing producing wells to some extent such that the partners will be allocated no Intangible Costs associated with the cost of such purchases.

Investment Expenses. The Partnership may engage in various activities that do not rise to the level of a trade or business such as acquisition of property for investment. As a result of the TCJA, for individuals, expenses attributable to the investment activities of the Partnership (as opposed to its activities that represent a trade or business for federal income tax purposes) are disallowed as a deduction. Such a Partner’s allocable share of such expenses will reduce his capital account and adjusted tax basis in his Interest even though the expense is not deductible. There can be no assurance that the IRS will not claim that some expenses treated by the Partnership as trade or business expenses should be treated as investment expenses not deductible by some Partners.

Redrilling and Workover Costs in General. The Partnership may pay various costs to work over various wells it acquires or to engage in related workover activities.

Some workover costs to be incurred could be, for example, pulling out tubing, washing out the inside of casing and dislodging accumulated silt and sand. These costs are operating in nature and should be expensed.

However, the cost of deepening a well is a cost of preparing for production and is treated as an Intangible Cost as are associated completion costs in connection with the deepening. See “TAX CONSIDERATIONS – Intangible Costs.”

The cost of working over saltwater disposal wells must be capitalized and depreciated as lease and well equipment because the saltwater disposal well is related to operations and not to the drilling of an oil or gas well or preparing an oil or gas well for production.

Where equipment, facilities or structures are not incident to or necessary for the drilling of oil or gas wells, the installation must be capitalized and depreciated. Some examples are storage, treatment or production facilities or tanks, pumping equipment, flow lines, separators, treating tanks and saltwater disposal equipment. Installation costs for these types of structures would not be Intangible Costs and should instead be capitalized and depreciated. See “TAX CONSIDERATIONS – Depreciation and Tax Considerations – Expensing.”

With respect to all of the foregoing costs, however, the Partnership will only be able to deduct its share of such costs (whether as Intangible Costs or through depreciation) and not the share attributable to any carried working interest. See “TAX CONSIDERATIONS – Intangible Costs and Depreciation: Carried Interest.”

Deduction for Pass-Through Trade or Business Income. The TCJA added Code Section 199A which generally provides a deduction for the owners of pass-through entities engaged in a trade or business. Code Section 199A does not apply to investment activities that do not rise to the level of a trade or business. For taxable years beginning after December 31, 2017, and before January 1, 2026, an individual taxpayer generally may deduct up to 20 percent of “qualified business income” from a partnership, S corporation, or sole proprietorship, as well as 20 percent of aggregate qualified REIT dividends, qualified cooperative dividends, and qualified publicly traded partnership income.

A limitation is phased in above a threshold amount of taxable income of the individual ($315,000 married filing jointly; $157,500 single). For businesses that are not specified service businesses, the limitation is based on the greater of (i) 50% of W–2 wages paid with respect to a trade or business or (ii) the sum of 25% of the W–2 wages paid with respect to the qualified trade or business, plus 2.5% of the unadjusted basis immediately after acquisition of all qualified property.

The deduction is not available with respect to income from investment such as capital gains and losses, interest and dividends even if that income is generated by a pass-through entity engaged in a trade or business. Thus, to the extent that activities of the Partnership are not part of a trade or business and relate to the acquisition of assets for investment, income from those investments will not qualify for inclusion in the calculation of the Code Section 199A deduction.

There are additional limitations that limit the deduction generally to the taxable income of the taxpayer in excess of net capital gains.

There are numerous complex rules governing the computation and eligibility for the deduction and the Treasury Department is expected to issue Treasury Regulations.

For any taxpayer claiming the Section 199A deduction, the definition of “substantial understatement” for purposes of the Section 6662 penalty is modified to reduce the threshold for imposition of the penalty to the greater of 5% (rather than 10%) of the tax required to be shown on the return or $5,000.

Business Interest Limitation. As added by the TCJA, Code Section 163(j) of the Code disallows the deduction for net business interest expense of any taxpayer in excess of the sum of the following for the taxable year: (a) business interest income, (b) 30 percent of “adjusted taxable income,” and (c) floor plan financing interest. The section 163(j) limitation is applied after other interest disallowance, deferral, capitalization or other limitation provisions. Therefore, original issue discount (OID) deferral rules, any capitalization requirements, related-party rules among others must first be applied prior to calculating the 30 percent limit. Adjusted business income is the taxable income of the taxpayer computed without regard to (for years beginning before January 1, 2022): items of income or loss not allocable to the trade or business; any business interest or business interest income; any net operating loss under section 172; any deduction for certain pass-through income under section 199A and any deduction for depreciation, amortization or depletion.

Partnerships are subject to the business interest limitation rules (with some modifications). If a partnership has enough taxable income to deduct its business interest, a partnership can pass its “excess taxable income” to its partners. If the partnership is unable to deduct business interest by virtue of exceeding the business interest income limitation, the partners will be allocated such excess business interest in the same manner as non-separately stated taxable income or loss of the partnership. If any excess business interest is allocated to a partner, it will be treated as paid or accrued by the partner in the next year in which the partner is allocated excess taxable income. Until that time, the partner will not be able to deduct the interest expense allocation even though it has reduced their basis in the partnership. If a partner is allocated any excess business interest, its basis in the partnership interest will be decreased (but not below zero) by the amount of such excess business interest. This will result in a timing mismatch of when the deduction is taken and when the reduction in basis will be deemed to occur.

The new limitation does not apply to certain small businesses, i.e., any taxpayer (other than a tax shelter) that meets the gross receipts test of section 448(c). In other words, businesses with average annual gross receipts of $25 million or less are exempt from this 30 percent limit. However, this exception does not apply to tax shelters. Under Code Section 448(c), a “tax shelter” includes, among other things, a syndicate, any enterprise (other than a C corporation) if at any time interests in such enterprise have been offered for sale in any offering required to be registered with any Federal or State agency having the authority to regulate the offering of securities for sale and includes a partnership if a significant purpose of such partnership is the avoidance or evasion of federal income tax . The Partnership may at some point be treated as a tax shelter for purposes of these rules. See “TAX CONSIDERATIONS – Intangible Costs.”

The Managing General Partner does not currently intend to cause the Partnership to incur debt.

Depletion. Code Section 611 allows as a deduction against income received from the oil or gas produced each year a reasonable allowance for depletion. The depletion deduction is the greater of percentage depletion at the applicable rate, if available, or cost depletion. Cost depletion allows the recovery of capitalized costs (such as bonus, other lease acquisition costs, exploratory charges, legal fees and certain other capitalized, non-depreciable costs) of a producing property over its life by an annual deduction computed on the basis of the actual oil and gas sold each year in relation to estimated recoverable oil and gas. Percentage depletion, if applicable, is an annual statutory allowance equal to a percentage of the gross income from the depletable property (but in no event exceeding 100% of the taxable income from the property before allowance for depletion) computed without regard to the costs associated with the property. Deductions resulting from percentage depletion can therefore exceed total costs associated with acquisition of the property. However, on the sale of the property, the portion of the gain that represents Intangible Costs and depletion that reduced the basis of the property will be recaptured as ordinary income. The availability of percentage depletion, under the provisions of Code Section 613A, is now largely dependent on the personal tax situation of each individual Partner. ACCORDINGLY, EACH PROSPECTIVE INVESTOR PARTNER IN THE PARTNERSHIP SHOULD CONSULT WITH HIS PERSONAL TAX ADVISER CONCERNING THE AVAILABILITY TO HIM OF PERCENTAGE DEPLETION.

Except for certain natural gas production, percentage depletion is generally available to “independent producers” with respect to the first 1,000 barrels per day of a taxpayer’s domestic oil production or the first 6,000,000 cubic feet per day of a taxpayer’s domestic gas production. The applicable rate of percentage depletion on oil and gas production is 15% (subject to possible upward adjustment of no more than 10%) of gross income, not to exceed 65% of the taxpayer’s taxable income for the year, without regard to certain deductions and subject to carry-over of the unused portion of the deduction. After 1999 the depletion rate may change but not below a minimum rate of 15%, and the amount of depletion which may be claimed for a property will be limited to 100% of the taxable income (excluding depletion) from that property. For a trust, the 65% limitation is computed without a deduction for distributions to beneficiaries during the taxable year.

Excluded from being an “independent producer” is a taxpayer who, directly or through related parties, (a) refines more than 75,000 barrels of oil (or equivalent of gas); or (b) is involved in the retail marketing of oil or gas or any product therefrom in excess of $5,000,000 per year in the aggregate. The 75,000-barrel limitation is based on the average, rather than the actual, daily refinery results for the year.

The Partnership will not compute the depletion allowance. Instead, the partner must separately compute his own depletion allowance with respect to this allocable share of the Partnership property and reduce the adjusted basis of his Partnership interest (but not below zero) by the amount of such depletion deduction to the extent such deduction does not exceed the basis allocated to that partner of the Partnership oil and gas property with respect to which the deduction is claimed. Each potential partner is urged to consult his tax counsel with respect to the availability to him of the percentage depletion allowance. Many uncertainties exist with respect to the interpretation of these provisions of the Code.

Depreciation. The cost of casing, tubing, tanks, flowing units and other types of tangible property and equipment cannot be deducted currently, but must be capitalized and depreciated or amortized pursuant to applicable provisions of the Code. Under the modified accelerated cost recovery system (“MACRS”) it is likely the cost of most of the tangible personal property to be acquired by the Partnership will be depreciated over either a five-year recovery period (available for property with a class life of more than four years but less than 10 years) or a seven-year recovery period (available for property that has a class life of 10 or more years but less than 16 years). This property would be depreciated on the 200% declining balance method switching to the straight-line method for the first taxable year the straight-line method would yield a larger allowance. It is likely that the Partnership will have an initial taxable year of less than 12 months. In the case of a taxable year of less than 12 months, property is to be treated as being placed in service for half the number of months in such taxable year. See Conference Report to Accompany HR 3838, Rep. No. 99-841, 99th Cong., 2d Sess. at II-46 (September 16, 1986) (Statement of the Managers). Consequently, first year depreciation will be computed as if the property was placed in the service at the midpoint of the taxable year.

The Partnership cannot claim depreciation to the extent of any carried working interest.

Expensing. Prior to the TCJA, taxpayers were generally allowed to claim additional depreciation (i.e., bonus depreciation) under Code Section 168(k) in the year in which qualified property (as described later) is placed in service in a trade or business through 2019 (with an additional year to place the property in service for qualified property with a longer production period). Bonus depreciation generally equals 50% of the cost of the property placed in service in 2017 and phases down to 40% in 2018 and 30% in 2019.

Prior to the TCJA, qualified property was defined as tangible property with a recovery period of 20 years or less under the modified accelerated cost recovery system (MACRS), as well as certain other property. To be eligible for bonus depreciation, the original use of the property had to begin with the taxpayer (i.e., used property does not qualify). Additionally, taxpayers had the option of making an annual election to not claim bonus depreciation with respect to qualified property under Code Section 168(k)(7). Alternatively, taxpayers may elect under Code Section 168(k)(4) to accelerate alternative minimum tax (“AMT”) credits (as refundable credits) in lieu of claiming bonus depreciation with respect to qualified property. Such election comes with the added requirement to depreciate that qualified property using a straight-line recovery method.

Under the TCJA, the additional first year depreciation deduction is extended through 2026 (2027 for longer production period property). The provision allows taxpayers to claim 100% bonus depreciation with respect to qualified property acquired and placed in service after September 27, 2017, and before January 1, 2023 (January 1, 2024, for certain qualified property with a longer production period). The expensing provisions in the also expand the current law definition of qualified property by repealing the requirement that the original use of the property begin with the taxpayer; instead, property would generally be eligible for 100% bonus depreciation if it is the taxpayer's first use of such property (provided that such “used” property is not acquired from a related party or in a carryover basis transaction).

Oil and gas businesses that are in a loss position and that would not otherwise benefit from immediate expensing would have the flexibility to elect not to apply the provisions of Section 168(k) and, instead, utilize the depreciation provisions as set forth in Section 168 generally or make Section 168 elections to “slow down” depreciation (e.g., annual election to use the alternative depreciation system).

Trades or businesses that elect to use the new expensing rules will generally be subject to limitations on deduction of business interest expense unless their average annual gross receipts over the proceeding 3- year period do not exceed $25 million. See “TAX CONSIDERATIONS – Intangible Costs.”

Separately, Code Section 179 generally allows a taxpayer an election to expense, rather than capitalize and depreciate, its investment in Code Section 1245 tangible depreciable property and certain computer software that is purchased in the tax year for use in the active conduct of a trade or business. Under the TCJA, Section 179 expensing increases to $1 million for “qualified property” (i.e., tangible personal property used in a trade or business) placed in service in tax years beginning after 2017, with a phase-out beginning at $2.5 million.

Gain on sale of equipment that has been expensed will be recast as ordinary income to the extent of the expensing or depreciation of such equipment. 

Finally, any depreciation allowable on such tangible property and equipment (including amounts expensed) may also be subject to recapture as ordinary income on transfer of the property or a partnership interest.

The Partnership cannot expense equipment to the extent of any carried working interest.

Amortization of Geological and Geophysical Expenditures. Effective for amounts paid or incurred in tax years beginning after August 8, 2005, under the Energy Tax Incentive Act of 2005, any geological and geophysical expenses paid or incurred in connection with the exploration for, or development of, oil or gas within the United States are generally allowed as a deduction ratably over the 24-month period beginning on the date that such expense was deemed paid or incurred. No other depreciation or amortization method is permissible for such payments. Any payment paid or incurred during the taxable year is treated as paid or incurred in the mid-point of the taxable year.

If any property with respect to which geological and geophysical expenses are paid or incurred is retired or abandoned during the amortization period, no deduction is allowed on account of retirement or abandonment, and the amortization deduction continues with respect to the payment.

Geological and geophysical costs are not subject to capitalization under the uniform capitalization (UNICAP) rules of Section 263A.

Leasehold Cost and Abandonment. The cost of acquiring oil and gas lease interests, or other similar oil and gas property interests, is a capital expenditure that may not be deducted in the year paid or incurred. However, if a lease is proved to be worthless by drilling or abandonment, the cost of that lease constitutes a loss and is deductible for federal income tax purposes. The federal income tax deduction for the loss, however, must be taken by the Partners, individually, rather than by the Partnership and allocated to the Partners. The deduction for such loss is taken in the year in which the lease becomes worthless or is abandoned.

Prepaid Expenses. If an expenditure results in the creation of an asset having a useful life which extends substantially beyond the close of the taxable year, such an expenditure may not be deductible, or may be deductible only in part, for the taxable year in which made. Such a prepaid expense may arise from services to be performed in multiple future tax years.

In general, prepaid expenses must be capitalized and are not deductible currently. A taxpayer can deduct a prepaid future expense in the current year if the expense is for a right or benefit that extends no longer than the earlier of 12 months or until the end of the tax year after the tax year in which the taxpayer made the payment. The 12-month exception does not override the economic performance requirement applicable to accrual method taxpayers. To use the 12-month rule, a taxpayer must apply it when first starting business. Otherwise, the taxpayer must get IRS approval which is granted automatically by filing an Application for Change in Accounting Method, with the tax return for the year the taxpayer wants to make the change.

The Managing General Partner believes that the Management Fee paid to it will be subject in part to the limitation on deduction of prepaid expenses and the limitation on deduction of organization and syndication costs. See Tax Considerations—Organization and Syndication Costs

Reg. Sec. 1.709-2(b) provides that “syndication expenses” are expenses connected with the issuing and marketing of interests in a partnership. These expenses include registration fees, legal fees of the issuer (the Partnership) for securities advice and for advice pertaining to the adequacy of tax disclosures in the offering materials for securities law purposes, accounting fees for preparation of representations to be included in the offering materials, printing costs of the offering materials, and other selling and promotional material. These expenses are not subject to the election under Section 709(b). Therefore, neither the Partnership nor any of the partners can deduct or amortize amounts paid or incurred in the promotion and sale of the interests and those expenditures must be capitalized. Reg. Sec. 1.709-2(b) and Rev. Rul. 88-4, 1988-1 C.B. 264. Nevertheless, the capital accounts of the partners are reduced by their allocable shares of such syndication costs. The Management Fee to be paid to the Managing General Partner requires it to pay brokerage commissions which are syndication costs and be reimbursed by the Partnership. Therefore, a part of the Management Fee should never be deductible by the Partnership or the Managing General Partner under the rule applicable to syndication costs

Deductibility of Payments to the Managing General Partner. If a turnkey contract with the Managing General Partner or an affiliate be executed for the drilling, testing and completion of a well, the Partnership will pay a turnkey price for the drilling, testing and completion of the well. See “TAX CONSIDERATIONS – Intangible Costs.”

The Partnership may purchase Prospects, land or working interests from the Managing General Partner. Purchases of Prospects, land or working interests from the Managing General Partner must be capitalized. These purchases have not been negotiated at arms-length. There is a substantial risk that any portion of purchase price payment could be reclassified in whole or in part as a syndication fee, an organization expense, a payment for services to be performed over the life of the Partnership, a prepaid expense, an investment expense or for some other cost that is not currently deductible and/or may not become deductible. If any such position of the IRS were sustained, associated deductions attributable to the purchased property would be disallowed, reduced, or delayed, and the tax liability of the partners could be increased. See TAX CONSIDERATIONS – Leasehold Cost and Abandonment.

The Partnership will also pay the excess over reimbursement to the Managing General Partner for all offering and organizational costs, including commissions and other syndication costs in consideration of the supervision and management of the Partnership by the Managing General Partner. Under Section 162(a), a deduction is allowed for all ordinary and necessary expenses paid or incurred during the taxable year in carrying on a trade or business. “Ordinary,” in this context, means normal, usual or customary. Deputy v. Dupont, 308 U.S. 488, 495-6 (1940). An expense may be “ordinary” even though it is infrequent. However, it must be of common occurrence in the type of business involved. Welch v. Helvering, 290 U.S. 111 (1933). “Necessary” means that the expense itself is appropriate and helpful to the purpose for which it was made. Commissioner v. Heininger, 320 U.S. 467 (1944). An expense that is unreasonable in amount is not a necessary expense. The same rules apply to the deduction of expenses whether they are paid to the Managing General Partner of a partnership, its affiliates, or to third parties. However, in the case of fees paid to partners and their affiliates, the IRS and the courts have generally given added scrutiny to the question of whether they are ordinary and necessary.

Compensation paid to a partner for services rendered to his partnership can be paid to him in his capacity as a partner or in his capacity as a person who is not a partner. If it is determined that a partner is performing services as an outsider, then the Partnership is treated as an unrelated entity for all purposes. Section 707(a). For example, the IRS ruled that investment management services performed (in exchange for a percentage of the Partnership’s daily gross income as provided for in the partnership agreement) by a general partner, a corporate investment adviser, were performed, in substance, in the capacity of a person who is to a general partner. The partner performed similar services for others as part of its regular business. The payments were taxable income to the partner as compensation for services and the fees were deductible by the Partnership as business expenses. See Revenue Ruling 81-301, 1981-2, C. B. 144.

If it is determined that a partner is performing services in the capacity of a partner, it must be determined whether the compensation is a guaranteed payment under Section 707(c) or a distributive share of partnership income under Section 704.

Under Section 707(c), “guaranteed payments” made to a partner for services or for the use of capital may, to the extent determined without regard to the income of the Partnership, be deductible if the payments satisfy the requirements of Section 162(a) and are not capital expenditures within the meaning of Section 263. Reg. Sec. 1.707-1(c), Cagle v. Commissioner, 539 F.2d 409 (5^th Cir. 1976) and Kimmelmann v. Commissioner, 72 T.C. 294 (1979).

The Managing General Partner does not intend to treat all compensation, including the Management Fee, paid to it as fully and currently deductible. Allocation of such fees between deductible ordinary and necessary business expenses, investment expenses, organizational expenses, syndication costs, prepaid expenses and other costs required to be capitalized, if any, and the reasonableness thereof, are inherently factual and, to a certain extent, predicated upon future events. For that reason, counsel to the Partnership cannot predict the outcome of a challenge with regard to these matters.

There can be no assurance that the IRS will not attempt to disallow, in whole or in part, a deduction for fees that the Partnership determines are properly deductible and that, if litigated, any such position by the IRS would not be sustained by the courts, at least as to a portion of such fees. There is a substantial risk that any portion of the Management Fee treated as a deductible payment could be reclassified in whole or in part as a syndication fee, an organization expense, a lease acquisition cost, a payment for services to be performed over the life of the Partnership, a prepaid expense, an investment expense or for some other cost that is not currently deductible. If any such position of the IRS were sustained, the deductions attributable to the payment of the Management Fee would be disallowed, reduced, or delayed, and the tax liability of the partners could be increased.

Tax Basis in Partnership Interest. The tax basis of a partner in its Partnership interest is important for several reasons including, but not limited to, determining: (1) the current deductibility of a partner’s distributive share of Partnership losses; (2) income tax consequences of distributions; and (3) gain or loss on the sale of the Partnership interest. A partner’s adjusted basis in its interest in the Partnership will be its capital contribution to the Partnership increased by: (a) its distributive share of Partnership income and gain (including tax-exempt income); and (b) its share of liabilities of the Partnership for federal income tax purposes; and decreased (but not below zero) by: (i) distributions from the Partnership to the partner; (ii) its distributive share of Partnership losses; (iii) its share of any reduction in the Partnership’s liabilities to the extent such liability was included in its basis; (iv) its share of non-deductible expenses of the Partnership that are not properly chargeable to a capital account; and (v) the amount of the partner’s deduction for depletion attributable to Partnership oil or gas property to the extent such deduction does not exceed the basis of such property allocated to that Partner. Any debt incurred by the Partnership will increase the tax basis of general partners in their Partnership Interest, but not the basis of limited partners. A decrease in a partner’s share of liabilities is treated as a distribution of money under Code Section 752(b) and may cause a partner to recognize gain on a deemed distribution in excess of basis. For example, this could occur if the Partnership incurred debt and a general partner converted his units to limited partner units thereby reducing his share of Partnership liabilities.

Code Section 613A(c)(7)(D) requires the individual Partner, rather than the Partnership, to compute depletion and gain or loss on the sale, exchange or abandonment of oil or gas property. A literal reading of Code Section 705 (which governs the determination of a partner’s basis in his Partnership interest) would preclude a partner from increasing the basis of his Partnership interest for gain recognized on the sale of partnership oil and gas property because such gain is no longer a Partnership item. Treasury Regulations issued under Code Section 705, however, provide for an adjustment to the basis of a partner’s interest for gain recognized on the Partnership’s disposition of oil or gas property.

For a tax shelter, Section 704(d) limits losses of a partner to the cash basis of a partner in his interest rather than the adjusted basis. See “TAX CONSIDERATIONS – Intangible Costs.” Some general partners may be allocated expenses and losses that cannot be immediately deducted because of loss limitations under the tax basis rules, the at-risk rules or other limitations.

Treatment of Cash Distributions from the Partnership. A partner generally will not recognize gain or loss for federal income tax purposes when he receives a cash distribution from the Partnership in respect of and not in liquidation of his Partnership interest so long as it is not in exchange for his interest in “unrealized receivables” (which include, among other things, potential recapture of depletion, Intangible Costs and MACRS deductions) or “inventory items” that have substantially appreciated in value. A partner will recognize gain on cash distributions (including any reduction in Partnership indebtedness for which no partner is personally liable) that exceed the adjusted basis in his Partnership interest immediately prior to such distribution. See also “At Risk Recapture of Losses” below.

Sales of Property Used in Trade or Business. Under the Code, if property used in a trade or business, including a working interest in oil or gas property, is sold and if the seller is not a dealer in such property, gain on such property held more than one year will be a “Section 1231 gain,” subject however to recapture of MACRS, depletion and Intangible Costs (which recapture is taxed as ordinary income). Section 1231 gain passes through to the partners and each partner must combine his share of the Partnership’s Section 1231 gain with his personal Section 1231 gains and losses. Except as otherwise provided in the rules relating to non-recaptured net Section 1231 losses, the excess of Section 1231 gains over Section 1231 losses constitutes long-term capital gain. However, net Section 1231 gain will be ordinary income to the extent it does not exceed the “non-recaptured net Section 1231 losses.” Non-recaptured net Section 1231 losses will include all net Section 1231 losses claimed of the five most recent preceding taxable years to the extent they have not previously been recaptured (i.e., converted into ordinary income).

Section 1231 gains and losses characterized as capital gains and losses are combined with all the taxpayer’s other capital gains and losses. A non-corporate taxpayer’s net capital gain (i.e., the excess of net long-term capital gain over net short-term capital loss) is generally currently subject to income tax at a maximum income tax rate of 20%. However, additional taxes such as the net investment income tax may apply to certain taxpayers. A non-corporate taxpayer may deduct losses from sales or exchanges of capital assets to the extent of his gains from such sales or exchanges plus the lesser of (i) $3,000 or (ii) the excess of such losses over such gains.

Sales of Property Held for Investment. Code Section 1231 does not apply to property held for investment. Gains and losses from property held for investment are generally taxed at capital gains rates, subject to any recapture being taxed at ordinary income tax rates. A non-corporate taxpayer’s net capital gain (i.e., the excess of net long-term capital gain over net short-term capital loss) is generally currently subject to income tax at a maximum income tax rate of 20%. However, additional taxes such as the net investment income tax may apply to certain taxpayers. A non-corporate taxpayer may deduct losses from sales or exchanges of capital assets to the extent of his gains from such sales or exchanges plus the lesser of (i) $3,000 or (ii) the excess of such losses over such gains.

Sales of Interest in the Partnership. If a partner sells his interest in the Partnership pursuant to the provisions of the partnership agreement, he will recognize taxable gain or loss on the sale measured by the difference between the amount realized by him on such sale and his adjusted tax basis in his Partnership interest. The amount realized by such partner will include his allocable share of Partnership debt, if any, as well as the amounts paid to him as a result of the sale. If the Partnership interest has been held by the selling partner for more than one year, the realized and recognized gain or loss on the sale will be taxed as long-term capital gain or loss, except to the extent the sale price is attributable to unrealized receivables (which includes MACRS, depletion and Intangible Cost recapture) or appreciation in inventory. The portion of the sale price attributable to those items will be taxed to the selling partner as ordinary income.

Liquidation of the Partnership. On expiration of its term or as otherwise provided in the partnership agreement, the Partnership will dissolve and, if not reconstituted, after payment of its liabilities, distribute its property or proceeds from the sale of its property to the partners in complete liquidation. The Partnership will not recognize gain or loss as a result of the liquidating distribution. Each partner will recognize gain or loss as a result of the Partnership’s sale of its assets. Assuming each item of Partnership property is distributed to the partner on a pro rata basis, each partner will recognize gain to the extent any money distributed exceeds the adjusted basis of such partner’s interest in the Partnership immediately before the distribution. A partner will recognize loss on the liquidating distribution if no property other than cash, unrealized receivables (which include MACRS, depletion and Intangible Cost recapture) and inventory are distributed to a Partner, only to the extent the adjusted basis of such partner’s interest in the Partnership exceeds the sum of the cash, the basis of unrealized receivables (which includes MACRS, depletion and Intangible Cost recapture) and the basis of inventory distributed. The basis of property distributed to each partner (other than cash) will be an amount equal to the adjusted basis of such partner’s interest in the Partnership reduced by the amount of cash distributed to him. The tax consequences of the liquidation of a Partnership described herein reflect only the general rules for such a liquidating distribution. On actual liquidation of the Partnership, various exceptions to these rules may alter the tax consequences described above

Activities Engaged in for Profit. Code Section 183 provides that if an activity is not “engaged in for profit” the only amounts deductible with respect to that activity are: (1) those expenses that would be deductible whether or not incurred in connection with an activity engaged in for profit, (e.g., certain interest and taxes); and (2) those expenses otherwise deductible had the activity been engaged in for profit, but only to the extent of the income from the activity. If it is determined the Partnership or a partner is not engaged in an activity for profit, a substantial portion of the deductions arising from t Partnership operations could be disallowed. The issue of whether an activity is engaged in for profit is primarily a question of fact. The resolution of this issue may be based in part on the intent of the partners, as evidenced by objective factors. THEREFORE, NO ONE SHOULD PARTICIPATE IN THE PARTNERSHIP UNLESS THEIR OBJECTIVE IS TO SECURE AN ECONOMIC PROFIT SEPARATE AND APART FROM ANY TAX BENEFITS THAT MAY FLOW FROM THE PARTNERSHIP. Because of the factual nature of this issue, counsel to the Partnership cannot predict the outcome of a challenge under Code Section 183.

Allocations. Under Code Section 704, allocations of all Partnership items of income, gain, loss, deduction and credit must have “substantial economic effect” to be recognized for federal income tax purposes. Otherwise, the allocations must be in accord with the “partners’ interests in the partnership”. Treasury Regulations issued under Code Section 704(b) provide that an allocation will have substantial economic effect if it satisfies a two-part test. First, the allocation must have economic effect; second, the economic effect must be substantial.

With respect to the second test, the Treasury Regulations provide that generally the economic effect of an allocation is substantial if there is a reasonable possibility that the allocation (or allocations) will affect substantially the dollar amounts to be received by the partners from the Partnership, independent of tax consequences. However, the Treasury Regulations provide that the economic effect of an allocation (or allocations) is not substantial if at the time the allocation becomes part of the partnership agreement: (i) the after-tax economic consequences of at least one partner may, in present value terms, be enhanced compared to such consequences if the allocation (or allocations) were not contained in the partnership agreement; and (ii) if there is a strong likelihood that the after tax economic consequences of no partner will, in present value terms, be substantially diminished compared to such consequences if the allocation (or allocations) were not contained in the partnership agreement.

According to the Treasury Regulations, an allocation will have economic effect if the partner to whom the allocation is made receives economic benefit or bears the economic burden or risk associated with the allocation. The Treasury Regulations state that, in general, an allocation will have economic effect if throughout the term of the Partnership, the partnership agreement:

If a partnership agreement contains a qualified income offset instead of a deficit restoration clause, the allocation will have economic effect only to the extent it does not create or increase a deficit capital account balance. In each case, capital account balances must be determined after taking into account all adjustments for the Partnership taxable year in which the liquidation occurs (other than the adjustments made pursuant to (ii) or (iii) above).

Under the partnership agreement, each general partner is jointly and severally liable for all debts of the Partnership and has an unconditional obligation to restore its negative capital account, if any, upon liquidation. Each limited partner is not jointly and severally liable for all debts of the Partnership and, except for possible repayment of certain prior distributions under Texas law, has no unconditional obligation to restore its negative capital account, if any, upon liquidation. Each limited partner is subject to a qualified income offset provision in the partnership agreement. Accordingly, the allocations in the partnership agreement should satisfy the alternative test for economic effect under Treasury Regulations because liquidating distributions are made according to positive capital account balances, capital accounts are to be maintained in accordance with Code Section 704(b) and each partner is subject to either an unlimited deficit restoration obligation upon liquidation or is subject to a qualified income offset provision in the partnership agreement.

The partnership agreement requires Revaluations of Partnership property to account for changes in value that can occur when partners are admitted at various times to comply with the substantial economic effect rules of Code Section 704(b). This Revaluation will be performed using the traditional method unless another method is selected by the Managing General Partner. Various uncertainties exist in performing Revaluations with respect to depletable property to comply with the substantial economic effect rules of Code Section 704(b). There is a risk that the IRS could challenge a Revaluation or the methodology used. Various partners of the same class may receive differing allocations from time to time because of the time that each is admitted.

The Treasury Regulations set forth special rules regarding allocations with respect to oil or gas property and corresponding adjustments to capital accounts. Code Section 613A(c)(7)(D) provides for the allocation of partnership depletable basis to the partners as of the date the Partnership acquired the property, so that each partner may separately determine his depletion deduction with respect to the property and gain or loss on the disposition of such property. Consequently, these items are not partnership items and would not be reflected in the Partners’ capital accounts. The Treasury Regulations set forth rules for determining “simulated” depletion and gain or loss on the sale of partnership oil or gas properties for purposes of adjusting the partners’ capital accounts. The partnership agreement provides for the calculation of these “simulated” amounts and allocates them in the same proportions the partners were allocated adjusted basis with respect to Partnership oil and gas property. The application of these rules on liquidation of the Partnership appears to be in conflict with the general rule that liquidating distributions must be made on the basis of capital account balances. In an attempt to comply with all of the rules set forth in the Treasury Regulations, the partnership agreement provides for the distribution of oil or gas property in kind or of the cash realized from the sale thereof to the partners in the same proportions the investor partners were allocated basis in such depletable property.

Code Section 613A(c)(7)(D) provides that a partnership must allocate to each partner as of the date of acquisition of an oil or gas property his proportionate share of the adjusted basis of the property as determined in accordance with their interest in capital or income. Code Section 613A(c)(7)(D) and the proposed Treasury Regulations issued thereunder provide that a partner’s proportionate share of the adjusted basis of partnership property shall be determined in accordance with his interest in partnership capital. However, a partner’s share of the adjusted basis of partnership property may be determined in accordance with his interest in the Partnership if the partnership agreement so provides, unless either:

Under the Treasury Regulations issued pursuant to Code Section 704(b), allocations of Partnership basis of oil or gas properties will be recognized as being in accordance with the partners’ interests in Partnership capital under Code Section 613(A)(c)(7)(D) provided.

Otherwise, such adjusted basis must be allocated among the partners pursuant to Code Section 613A(c)(7)(D) in accordance with the Partners’ actual interests in Partnership capital or income.

For a tax shelter, Section 704(d) limits losses of a partner to the cash basis of a partner in his interest rather than the adjusted basis. See “TAX CONSIDERATIONS – Intangible Costs.”

Allocations: Varying Interests. When the Partnership admits a new partner(s) based upon the new partner’s contribution of capital, a shift in the Partner’s interest will occur. This shift in interest creates issues regarding the closing of the Partnership’s taxable year, the allocation of partnership items between the transferor and transferee, and retroactively allocating items to the incoming or “new” partner. The closing of the partnership taxable year is governed by Code Sections 706(c), and Code Section 706(d), the varying interest rule, governs the allocation of each partner’s distributive share. The substantial economic effect rule under Code Section 704(b) can also impact the allocation of a partner’s distributive share. See “TAX CONSIDERATIONS – Allocations.”

Under Code Section 706(c)(1), except upon the termination of the Partnership, the Partnership’s taxable year does not close upon the death or entry of a partner, the sale or exchange of a partner’s units or the liquidation of a partner’s interest. However, under Code Section 706(c)(2), the taxable year of the Partnership does close with respect to a partner whose entire interest in the Partnership terminates due to death, liquidation or another reason.

When partners interest in the partnership change during a taxable year, the partner’s distributive share of partnership income, gain, loss or deduction are determined by taking into account the partner’s varying interest in the partnership during the taxable year. Code Section706(d) applies to changes amongst partner’s interest during the taxable year. These changes include sales, partial sales, gifts and reductions in the partner’s interest. Under the Code, cash basis partnerships are also forbidden from deferring certain payments for deductible items until the end of the year.

The Partnership will use an interim closing of the books method with conventions as selected by the Managing General Partner to account for the allocations among Partners. Various partners of the same class may receive differing allocations from time to time because of the time that each is admitted.

Election to Adjust Tax Basis of Partnership Property. As a result of the tax accounting complexities inherent in, and the substantial expense that would be attendant to, making the election to adjust the tax basis of the Partnership’s property provided by Code Sections 734, 743, and 754, the Managing General Partner does not presently intend to make such election on behalf of the Partnership. The absence of any such effective election and of the power to compel the making of such an election may, in many circumstances, result in a reduction in value of a partner’s interest to any potential transferee and may be considered an additional impediment to the transferability of Partnership interests.

Notwithstanding the lack of any 754 election by the Partnership, the basis adjustment rules under Section 743 are mandatory in the case of the transfer of a Partnership interest with respect to which there is a substantial built-in loss. For this purpose, a substantial built-in loss exists if the Partnership’s adjusted basis in its property exceeds by more than $250,000.00 the fair market value of the Partnership property.

Repayment of Certain Loans. Each partner will be subject to federal income tax on his distributive share of the net taxable income of the Partnership, whether or not such income is actually distributed to him. Advances against production received by the Partnership (such as a loan or an advance secured by a specific share of future production), if any, will be treated as loans to the Partnership and will not be recognized as income by the Partnership on receipt. Proceeds from production used to pay such advances or other loans will be ordinary income, subject to depletion, to the Partnership in the year the production is realized. The principal portion of repayments will not be deductible by the Partnership, but the Partnership may be entitled to a deduction of interest, if any, paid on the advances or loans. See “TAX CONSIDERATIONS – Limitations on Deductibility of Interest.” During repayment of such advances or loans, the taxable income of the partners from the property subject to the advance of loan may be greater that the net cash proceeds therefrom distributed to them. Therefore, taxes will be payable on revenues used to repay the principal amount of the advance or loan, as well as on remaining Partnership revenues available for distribution, whether or not actually distributed.

At-Risk Limitation on Deductions for Expenses. The “at-risk” limitation provision of Code Section 465 restricts the amount of loss a partner can deduct in connection with activities conducted in “exploring for or exploiting oil and gas resources.” Under this rule, all non-corporate taxpayers and certain corporate taxpayers that sustain a loss in connection with oil and gas activities may deduct such loss only to the extent of the amount “at risk” in such activities at the end of a taxable year. This limitation applies to each activity engaged in and not on an aggregate basis for all activities. For the purpose of initially computing the amount of such limitation, the amount “at risk” for each taxpayer is limited to: (1) the amount of money contributed to the activity, (2) the adjusted basis of other property contributed to the activity, and (3) any amount borrowed with respect to the activity for which the taxpayer is personally liable for repayment or with respect to which he has pledged property (other than property used in the activity) as security for the repayment of the amount borrowed from any person other than a person who has an interest in the activity or who is related party (as defined), limited however, to the net fair market value of his interest in such pledged property. “Loss” is defined as the excess of allowable deductions for a taxable year from an activity over the amount of income actually received or accrued by the taxpayer during such year from the activity.

The amount the taxpayer has “at risk” may not include the amount of any loss against which the taxpayer is protected through non-recourse financing, guarantees, stop loss agreements or other similar arrangements. The amount of any such loss disallowed in any taxable year shall be carried over to the first succeeding taxable year. Further, a taxpayer’s “at risk” amount in subsequent taxable years with respect to the activity involved shall be reduced by that portion of the loss allowable as a deduction.

Some general partners may be allocated expenses and losses that cannot be immediately deducted because of loss limitations under the tax basis rules, the at-risk rules or other limitations.

At-Risk Recapture of Losses. The “at-risk” rules also provide that a partner must recognize income to the extent his “at-risk” basis is reduced below zero (limited to loss amounts previously allowed to the partner over any amounts previously recaptured). Distributions to a Partner, changes in the amount of recourse indebtedness attributable to a partner (from conversion of a general partner interest to a limited partner interest or otherwise) or the commencement of guarantees or similar arrangements may reduce a partner’s amount “at-risk.” A partner may be allowed a deduction for the recaptured amounts included in taxable income if he increases his amount “at-risk” in a subsequent taxable year.

Limitations on Passive Activity Losses. The Code imposes limitations on taxpayers’ ability to deduct losses from passive activities against the taxpayer’s other income. In general, a taxpayer may not deduct losses from a passive activity against income from wages and salaries (or other so called “active” income) or against income from interest, dividends and royalties (“portfolio income”).

However, a taxpayer may deduct against such income losses from activities in which the taxpayer materially participates (subject to other limitations in the Code). The passive activity loss rules apply to individuals, estates, trusts, closely held C corporations (50% of the value which is owned by five or fewer individuals) and “personal service corporations.” An activity will be classified as “passive” if the activity is a rental activity or the conduct of a trade or business in which the taxpayer does not “materially participate.” A taxpayer materially participates in an activity if the taxpayer is involved in the operations of the activity on a regular, continuous and substantial basis. A taxpayer is not treated as materially participating in an activity if his interest in that activity is held as a limited partner in a limited partnership.

Amounts received for upfront land leases that energy companies pay to permit drilling on the land are rental income for federal income tax purposes, which means the payments will be ordinary income. However, because the land is non-depreciable property, under Regs. Secs. 1.469-2T(f)(3) and 2(f)(10), the income is treated as portfolio income rather than passive income for purposes of the passive activity loss rules. Such income will potentially subject higher-income taxpayers to the 3.8% net investment income tax.

The Partnership may also purchase royalty interests. Royalties, like land lease payments, are ordinary income, and they are not treated as passive income under Section 469; instead, they are portfolio income. Royalty income will potentially subject higher-income taxpayers to the 3.8% net investment income tax.

In computing a taxpayer’s passive activity loss limitation, the taxpayer must determine his aggregate deductions and losses from all passive activities for the taxable year and offset them against his aggregate income and gains from passive activities during the taxable year. Similarly, the taxpayer must aggregate all credits earned during the taxable year from passive activities and offset them against the tax liability allocable to all passive activities during the taxable year. Although a taxpayer is permitted to offset losses from one passive activity against income and gains from another passive activity, the taxpayer may not offset his losses from passive activities against his wages, salary, or other income derived from the active conduct of a business, nor against income from interest, dividends, or royalties not derived in the ordinary course of a trade or business, or against the gain from the sale of property producing such income.

Should a taxpayer have net losses from passive activities and net credits from passive activities, both net losses and credits may be carried forward indefinitely and deducted against any future net income and tax liability, respectively, from passive activities. Any unused losses are held in suspense until the taxpayer disposes of his entire interest in the passive activity in a taxable transaction to an unrelated person. On disposition of a passive activity, the taxpayer is generally permitted to deduct the suspended passive losses against the taxpayer’s other income or gain (after first offsetting them against gain recognized on the disposition and against net income for the taxable year from all passive activities). Suspended credits, however, must continue to be carried forward until used to offset tax on income from other passive activities. If the disposition is because of the taxpayer’s death, the suspended losses can only be used to the extent they exceed the amount by which the property’s basis is increased as a result of the taxpayer’s death.

Material participation, however, is not in all cases determinative as to whether an activity is a “passive activity.” Under the “working interest exception,” working interests in oil and gas properties are not treated as passive activities (regardless of whether the taxpayer materially participates) if the taxpayer owns the interest directly or through an entity that does not limit his liability with respect to the activity. Two elements must be met before a taxpayer qualifies for the working interest exception to the passive activity loss rules, so that losses will not be treated as losses from a passive activity. First, the property generating the losses must constitute a “working interest” as defined by the passive loss rules. Second, the interest must not be held through an entity that limits the liability of the taxpayer with regard to the activity.

With respect to the first part of the test, the passive loss Treasury Regulations indicate that a “working interest” does not include non-operating mineral interests such as royalty interests, production payments. Under the partnership agreement, the partners will receive periodic reports regarding drilling and completion and regarding the amount of oil extracted. The question of whether the partners own a “working interest” as defined by the passive loss rules is in part one of fact

The second part of the test requires that the “working interest” not be held directly or indirectly through an entity that limits the taxpayer’s liability with respect to the activity. Although the Partnership may obtain insurance to protect against various liabilities, to the extent the insurance coverage obtained by the Partnership fails to cover a particular risk or is insufficient to pay the entire amount of a particular claim or to the extent the insurer is financially insolvent or otherwise unable to pay a particular claim, the General Partners, but not the limited partners, will bear the ultimate liability for losses with respect to the Partnership. No provision of the partnership agreement will limit the liability of the general partners for restoration of a negative capital account of for the liabilities of the Partnership. In addition, the passive loss Treasury Regulations provide that the presence of insurance is not taken into account in determining whether the taxpayer holds a working interest through an entity that limits the taxpayer’s liability. Although it is possible that the IRS might take a contrary position and that, if litigated, a court might sustain such position, the Managing General Partner believes that if challenged, the Partnership interests in the Partnership held by the general partners would not be deemed substantially equivalent in their effect on liability to a limited partnership interest. Each prospective general partner should be aware, however, that even if the Partnership itself is not an entity that limits the liability of the general partner with respect to the activity, no person will be deemed to materially participate in the Partnership’s activities (and losses allocated to that individual will be deemed losses from a passive activity) if such person owns his individual interest in the Partnership through an entity, such as a limited partnership or a corporation, that limits the liability of that individual with respect to the Partnership.

To the extent the IRS were successful in contending either that the general partners do not own oil or gas working interests as defined in the passive loss rules or that the form in which the general partners own the Partnership property has an effect on the general partner’s liability similar to that of a limited partnership, such general partner’s share of any losses, generated by the Partnership would constitute passive losses, which such general partner could deduct only to the extent of such general partner’s passive income.

THE LIMITED PARTNERS IN THE PARTNERSHIP SHOULD BE SUBJECT TO THE PASSIVE ACTIVITY LOSS LIMITATIONS WITH RESPECT TO THE DRILLING AND COMPLETION ACTIVITIES AND OTHER TRADE OR BUSINESS ACTIVITIES OF THE PARTNERSHIP AS LIMITED PARTNERS WILL NOT SATISFY THE WORKING INTEREST EXCEPTION. A limited partner’s share of any trade or business losses, generated by the Partnership would constitute passive losses, which such limited partner could deduct only to the extent of such limited partner’s passive income

Conversion of General Partner Units into Limited Partner Units. An investor partner who is a general partner may from time to time elect to convert its general partner Units into limited partner Units after drilling activities have been completed as described more fully in the offering materials. SUCH A CONVERSION SHOULD ONLY BE MADE AFTER THE YEAR IN WHICH DRILLING ACTIVITIES ARE COMPLETED OR THE AFFECTED INVESTOR MAY BE UNABLE TO EXPENSE ALL OR PART OF THE INTANGIBLE COSTS ALLOCATED TO HIM BECAUSE OF THE PASSIVE ACTIVITY LOSS RULES OF THE CODE. See “TAX CONSIDERATIONS – Limitation on Passive Activity Losses.”

Moreover, if the Partnership were to incur debt and a part of that debt were to be allocated to the general partner who is converting, the conversion would cause a deemed distribution of money to the converting partner under Code Section 752(b). Such deemed distribution be taxable to the extent that it exceeded the converting partner’s then basis in his Partnership interest.

Excess Business Loss Limitation. The TCJA imposes a limitation on the ability of individual partners to claim trade or business losses. Under new Code Section 461(l), “excess business losses” are disallowed and carried forward to the next tax year as a net operating loss subject to TCJA’s new limits on the ability to utilize net operating losses. The excess business loss of an individual taxpayer is equal to the aggregate deductions of the taxpayer (including Intangible Costs) attributable to trades or businesses minus the sum of (i) aggregate income and gains of the taxpayer attributable to trades or businesses plus (ii) $250,000 for a single taxpayer ($500,000 for married taxpayers filing a joint return). The new limitation applies at the partner level after application of the passive activity loss rules. Thus, all deductions generated by the Partnership will be subject to this limitation at the partner level.

Under the TCJA, net operating losses may not generally be carried back to prior years and may only be used to offset 80% of the income of the taxpayer in each year to which the net operating loss is carried.

Under the CARES Act, the excess business loss limitation was repealed for tax years 2018, 2019, and 2020. Generally, The CARES Act allows a five-year carryback of any NOL generated in a taxable year beginning after December 31, 2017, and before January 1, 2021. Therefore, the CARES Act did not provide relief for the Partnership’s proposed operations in 2021 and future years with respect to the excess business loss limitation and/or the treatment of net operating losses.

Some general partners may be allocated expenses and losses that cannot be immediately deducted because of loss limitations under the tax basis rules, the at-risk rules, the excess business loss limitation or other limitations.

The AMT exemption amount for 2021 is $73,600 for singles and $114,600 for married couples filing jointly. In 2021, the 28 percent AMT rate applies to excess AMTI of $199,900 for all taxpayers ($99,950 for married couples filing separate returns). The TCJA indexes those amounts for inflation.

The TCJA also increases the amounts used under § 55(d)(3) to determine the phase-out of the exemption amount and indexes those amounts for inflation. The AMT exemption is reduced by 25% of the amount by which alternative minimum taxable income in 2021 exceeds $1,047,200 for married couples filing jointly ($523,600 for single taxpayers).

An individual is required to pay the alternative minimum tax only if the amount of such tax exceeds his regular tax.

Tax on Self-Employment Income. Individuals are required to pay a 2.9% Medicare tax on all income from self-employment, that is, from carrying on a trade or business as a sole proprietor or as a partner. The rate increases to 3.8% for certain high-income taxpayers. The Medicare tax is in addition to social security self-employment taxes of 12.4% for which the maximum earnings base in 2015 in $118,500. The tax is levied as part of the estimate tax liability of self-employed persons. The self-employment tax is imposed on “self-employment income,” which is based on “net earnings from self-employment.” Net earnings from self-employment include a general partner’s distributive share (whether or not distributed) of income or loss from any trade or business carried on by the Partnership. Ownership of a working interest in oil and gas wells directly or as a general partner in a partnership has been held to constitute a trade or business for purposes of the tax on self-employment income, Perry v. Commissioner, T.C. Memo 1994-215, 67 T.C.M. (CCH) 2966 (1994). A limited partner who only invests in the Partnership as a limited partner should not incur self-employment tax from any trade or business carried on by the Partnership under current law; however, such limited partner may incur net investment income tax on his distributive share of income (whether or not distributed) from such activities of the Partnership. See “TAX CONSIDERATIONS – Net Investment Income Tax.”

Net Investment Income Tax. A net investment income tax (“NIIT”) of 3.8% applies to certain taxpayers. The 3.8% NIIT is a surtax levied on the lesser of (i) Net Investment Income or (ii) the excess of Modified Adjusted Gross Income over the taxpayer’s threshold amount ($250,000 for joint returns; $200,000 for single returns; $125,000 for married filing separately) which is not indexed for inflation. A taxpayer’s modified adjusted gross income generally equals his adjusted gross income unless he has foreign earned income in which case it is necessary to add back Code Section 911 excluded income and expenses.

In general, investment income includes, but is not limited to, interest, capital gains, rental and royalty income, and businesses that are passive activities to the taxpayer (within the meaning of Code Section 469). To the extent that gains are not otherwise offset by capital losses, gain from the sale of investment real estate and gains from the sale of interests in partnerships (to the extent the partner was a passive owner) are common examples of items taken into account in computing net investment income: Capital gains from the sale of a partnership interest by a taxpayer who materially participated in such partnership are generally excluded from the application of the net investment income tax to the extent the gain was subject to trade or business activities under a series of complex rules. See Proposed Regulation Section 1.1411-7.

The net investment income tax does not apply to income if self-employment taxes apply to such income.

Participation by IRAs, Employee Benefit Plans and Similar Tax-Exempt Organizations. IRAs and employee benefit plans and certain charitable and other organizations described in Code Section 501(c) are exempt from federal income tax. However, such entities are subject to tax on unrelated business taxable income. Unrelated business taxable income is gross income derived by an exempt organization from any unrelated trade or business regularly carried on by it or by a partnership of which it is a member. Specific deductions directly connected with the carrying on of such trade or business, computed with modifications, including a $1,000 deduction, are allowed. Since the Partnership will carry on a trade or business, a tax-exempt partner may be considered to be regularly carrying on the trade or business of the Partnership and any Partnership income allocated to a tax-exempt partner may be unrelated business taxable income to such Partner, unless such income is specifically exempt from such classification.

As a result of changes made by the TCJA, it is necessary compute income from each unrelated trade or business separately before applying the specific deduction under Code Section 512(b)(12). Loss from one unrelated trade or business cannot be used to offset income from another but can be carried forward to offset income from the same unrelated trade or business.

The receipt of unrelated business taxable income by a tax-exempt entity generally has no effect on that entity’s tax-exempt status or on the exemption from tax of its other income. However, for certain types of tax-exempt entities, the receipt of any unrelated business income may have extremely adverse consequences including a 100% penalty tax. ACCORDINGLY, EACH PROSPECTIVE TAX-EXEMPT INVESTOR PARTNER IS URGED TO CONSULT ITS OWN ADVISER REGARDING THE POSSIBLE CONSEQUENCES OF PARTICIPATING IN THE PARTNERSHIP.

Foreign Partners. The federal income taxation of non-resident alien individuals, foreign corporations and other foreign entities (hereinafter referred to collectively as “foreign partners”) is a highly complex matter that may be affected by applicable tax treaties and other considerations.

Under Code Section 875, a non-resident alien individual or foreign corporation is deemed engaged in a trade or business within the United States if the partnership of which such foreign partner is a member is so engaged. In general, if foreign partners participate in the Partnership, all items of Partnership income included in their distributive shares, including gains on the sale or other disposition of Partnership properties, will be subject to United States taxation as income that is effectively connected with a United States trade or business (“effectively connected income”). Consequently, such partners will be required to file United States income tax returns and will be subject to United States tax on their distributive shares of net business income from the Partnership at the same rate applicable to a United States citizen, resident or corporation. In determining a partner’s distributive share of net business income from the Partnership, such investor partner would be permitted the same deductions allowed to a United States citizen, resident or corporation.

A nonresident alien individual is entitled to deductions and credits, to the extent qualified, only if a timely return is filed, or caused to be filed, by the nonresident alien. If a return should have been filed and was not, the IRS will have one prepared but will allow no deductions or credits (other than the credit for taxes withheld or the credit for federal excise taxes on gasoline and special fuel).

For sales, exchanges, or other dispositions of Units in the Partnership occurring on or after November 27, 2017, the TCJA (i) provides that a nonresident alien individual’s or foreign corporation’s gain or loss from the sale, exchange, or other disposition of a partnership interest is effectively connected with the conduct of a trade or business in the United States to the extent that the person would have had effectively connected gain or loss had the partnership sold all of its assets at fair market value and (ii) imposes a requirement that the transferee must generally withhold a tax equal to 10 percent of the amount realized on the disposition.

Withholding Tax on Foreign Partners’ Share of FDAP Income. Fixed, Determinable, Annual, or Periodical (FDAP) income of a foreign partner is subject to withholding tax at a 30% (or lower treaty) but only if not effectively connected with U.S. trade or business. The 30% (or lower treaty) rate applies to the gross amount of U.S. source fixed or determinable, annual or periodical gains, profits, or income. Deductions and netting are not allowed against FDAP income. Rents and royalties that are not effectively connected with a U.S trade or business are examples of FDAP income. The extent to which the Partnership will generate FDAP income is dependent upon the actual operations of the Partnership in the future and cannot be predicted at this time.

Withholding Tax on Foreign Partners’ Share of Effectively Connected Income. A U. S. partnership that has income effectively connected with a U.S. trade or business (or income treated as effectively connected) must pay a withholding tax on the effectively connected taxable income that is allocable to its foreign partners. Such withholding under Code Section 1446 is at the highest rate of tax specified in section 1 in the case of the portion of the effectively connected taxable income which is allocable under Code Section 704 to foreign partners who are not corporations (currently 37%), and at the highest rate of tax specified in Code Section 11(b) in the case of the portion of the effectively connected taxable income which is allocable under section 704 to foreign partners which are corporations (currently 21%). Withholding is on income regardless of whether any amounts are distributed to the foreign partner.

A partner that is a foreign person will have effectively connected taxable income if the Partnership has taxable trade or business income.

A foreign partner is required to file a U.S. income tax return even if there is no U.S. tax due. A valid Taxpayer Identification Number (TIN) is required. Partners in the Partnership can be required to file U.S. income tax returns.

If during the Partnership’s tax year, the Partnership has taxable income effectively connected with the conduct of a trade or business within the United Sates that is allocable to a foreign partner, the Code requires the Partnership to report and pay a withholding tax under Code Section 1446 to the IRS. The Partnership must pay the Code Section 1446 withholding tax regardless of the amount of foreign partners’ ultimate U.S. tax liability and regardless of whether the Partnership makes any distributions during its tax year. Payment of withholding is then treated as a distribution under the partnership agreement. Revenue Procedure 92-66, and Treasury Regulation section 1.1446-3 set forth the time and manner for paying the withholding tax, as well as the general reporting obligations with respect to the tax. A partnership that fails to comply with the Code Section 1446 reporting and withholding requirements may be subject to penalties and interest. Various exemptions from withholding may be available.

For sales, exchanges, or other dispositions occurring on or after November 27, 2017, the TCJA (i) provides that a nonresident alien individual’s or foreign corporation’s gain or loss from the sale, exchange, or other disposition of a partnership interest is effectively connected with the conduct of a trade or business in the United States to the extent that the person would have had effectively connected gain or loss had the partnership sold all of its assets at fair market value and (ii) imposes a requirement that the transferee must generally withhold a tax equal to 10 percent of the amount realized on the disposition.

FIRPTA Withholding of Tax on Dispositions of United States Real Property Interests. A domestic partnership that is otherwise subject to the withholding requirements of Code sections 1445 (FIRPTA) and 1446 (partnership withholding) will be subject to the payment and reporting requirements of Code Section 1446 only and not Code Section 1445 with respect to partnership gain from the disposition of a U.S. real property interest. A partnership that has complied with the requirements of Code section 1446 will be deemed to satisfy the withholding requirements for FIRPTA. However, a domestic partnership that would otherwise be exempt from Code section 1445 withholding by operation of a non-recognition provision must continue to comply with the FIRPTA requirements (See Treasury Regulation section 1.445-5(b)(2)). In the event that amounts are withheld under FIRPTA at the time of the disposition of a U.S. real property interest, such amount may be credited against 1446 tax. A partnership that fails to comply fully with the requirements of Code section 1446 may be liable for any unpaid 1446 tax and subject to any applicable addition to the tax, interest, and penalties under Code section 1446.

The disposition of a U.S. real property interest by a foreign person (the transferor) is subject to the Foreign Investment in Real Property Tax Act of 1980 (“FIRPTA”) income tax withholding. FIRPTA authorized the United States to tax foreign persons on dispositions of U.S. real property interests. A disposition means “disposition” for any purpose of the Code. This includes but is not limited to a sale or exchange, liquidation, redemption, gift, transfers, etc. Persons purchasing U.S. real property interests (transferees) from foreign persons, certain purchasers’ agents, and settlement officers are required to withhold 15% of the amount realized on the disposition (special rules for foreign corporations). In most cases, the transferee/buyer is the withholding agent. The transferee buyer must find out if the transferor is a foreign person. If the transferor is a foreign person and the transferee buyer fails to withhold, he may be held liable for the tax. For cases in which a U.S. business entity such as the Partnership disposes of a U.S. real property interest, the transferee buyer business entity itself is the withholding agent.

The withholding under FIRPTA is 15% of the amount realized on disposition of a U.S. Real Property Interest (USRPI), not merely the gain.

The transferee must deduct and withhold a tax equal to 15% (or other amount) of the total amount realized by the foreign person on the disposition. The amount realized is the sum of (1) the cash paid, or to be paid (principal only), (2) the fair market value of other property transferred, or to be transferred, and (3) the amount of any liability assumed by the transferee or to which the property is subject immediately before and after the transfer. The amount realized is generally the amount paid for the property. If the property transferred was owned jointly by U.S. and foreign persons, the amount realized is allocated between the transferors based on the capital contribution of each transferor.

In addition, to the extent attributable to USRPIs owned by the Partnership, the amount realized on a sale or exchange by a non-U.S. offeree of its interest in the Partnership would be treated as received in exchange for a USRPI. Gain or loss, to the extent so attributable, therefore would be subject to federal net income tax and the gross proceeds from such sale or exchange may become subject to a 15% withholding tax. However, if 50% or more of the value of the gross assets of the Partnership consists of USRPIs and 90% or more of the value of the gross assets of the Partnership consists of USRPIs plus cash or cash equivalents, then each Partnership interest will be treated in its entirety as a USRPI for purposes of such withholding tax. As a result, the entire proceeds of such sale generally would be subject to a 15% withholding tax. Amounts withheld for federal income taxes may be claimed as a credit against an offeree’s substantive U.S. income tax liability

Foreign Persons and Self-Employment Tax. Self-employment income is income that arises from the performance of personal services, but which cannot be classified as wages because an employer-employee relationship does not exist between the payer and the payee. The Code imposes the self-employment tax on the self-employment income of any U.S. citizen or resident alien who has such self-employment income. Income from a working interest generally produces self-employment income for U.S. citizens or resident aliens.

However, nonresident aliens are not subject to U.S. self-employment tax. Once a nonresident alien individual becomes a U.S. resident under the residency rules of the Code, he/she then becomes liable for self-employment taxes under the same conditions as a U.S. citizen or resident alien.

In spite of the general rules above, self-employment tax may be imposed on a nonresident alien under the terms of an international social security agreement.

The United States has entered into social security agreements with foreign countries to coordinate social security coverage and taxation of workers employed for part or all of their working careers in one of the countries. These agreements are commonly referred to as totalization agreements. Under these agreements, dual coverage and dual contributions (taxes) for the same work are eliminated. The agreements generally make sure that social security taxes (including self-employment tax) are paid only to one country.

The above rules of United States taxation are subject to modification by applicable income and estate tax treaties. THEREFORE, FOREIGN PARTNERS ARE URGED TO CONSULT THEIR OWN TAX ADVISERS WITH RESPECT TO PARTICIPATING IN THE PARTNERSHIP AND THE EFFECT OF THE TAX LAWS OF OTHER JURISDICTIONS IN WHICH THEY ARE SUBJECT TO TAXATION WITH RESPECT TO SUCH PARTICIPATION

State and Local Income Taxes. Certain states or localities where the Partnership may engage in business or where the partners may reside may levy income taxes for which the partners may be liable with respect to their share of the Partnership income, and it may be necessary for each partner to file state or local income tax returns to report income in such jurisdictions. Neither the Managing General Partner nor counsel to the Partnership has reached any conclusions or rendered any opinion on matters of state or local income tax law.

The Partnership may be obligated to file Gross Margin Tax returns with the Texas Comptroller.

Audit of Tax Returns. In light of the announced emphasis by the IRS on audits of tax shelter investment programs, the tax returns of the Partnership may be audited, and such audit may result in adjustments. The Managing General Partner will decide how to report partnership items on the Partnership’s tax returns. Since the Partnership may engage in transactions whose treatment for tax purposes is not clear, there is a risk that a claim of tax liability could be asserted against the Partnership or its Partners. In the event the federal income tax returns of the Partnership are audited by the IRS, the tax treatment of Partnership income and deductions generally is determined at the Partnership level in a single proceeding rather than by individual audits of the Partners. The Managing General Partner, as the “Partnership Representative,” has considerable authority to make decisions affecting the tax treatment of all partners and former partners with respect to the Partnership. Under the Bipartisan Budget Act of 2015 (the “BBA”), the tax treatment of income, gains, deductions and losses of the Partnership and impositions of any tax penalties generally will be determined at the Partnership level. The Partnership will generally be liable for any underpayment of tax, computed by applying the highest rate of tax in effect for the audited year to the underpayment. The Partnership can present facts to obtain a lower rate. No deduction will be allowed for any tax liability paid by the Partnership. Because the tax is paid by the Partnership, the economic burden of audit adjustments will fall on the persons who are partners during the year in which the audit adjustments are made, not the persons who were partners in the tax year audited. It currently appears that an expense for interest imposed under the Code will generally be allocated to the partners in proportion to the imputed underpayment from which it derives in the event of a partnership level proceeding. Also, an expense arising from a substantial understatement of tax under section 6662(d) for an imputed underpayment will generally be allocated in proportion to the notional income item to which it relates.

In lieu of the Partnership paying the tax, the Partnership Representative may elect to have any audit adjustments including penalties flow through and be taken into account by those persons who were partners during the taxable year audited (a push-out election). If that election is made, the economic effect of the audit adjustments will fall on the persons who were partners during the audited year; however, such persons may have no ability to contest some adjustments. Moreover, adjustments that are favorable to the Partnership may under proposed Treasury Regulations be required to be taken into account in the adjustment year to the benefit of the partners in the year of the adjustment. This may have a material adverse effect on the partners from the reviewed year and cause them to pay extra taxes if they are receiving adjustment attributable to the Partnership’s imputed underpayment. The Managing General Partner as the Partnership Representative may make or not make any elections as it deems appropriate in connection with an audit, including electing to pay tax on any audit adjustments at the Partnership level or electing to have the adjustments taken into account by the persons who were partners during the audited year. It is unclear whether states and localities will follow the provisions of the BBA. The Managing General Partner will have authority to make any and all similar elections under state and local law.

Proposed Treasury Regulations clarify that a partnership’s withholding tax obligations with respect to non-U.S. partners (under chapter 3 of the Code) and FATCA withholding (under chapter 4 of the Code) do not fall within the scope of the BBA. Accordingly, an audit of a partnership’s compliance with its obligations under either withholding regime (and collection of any under withheld tax) may be handled in a separate proceeding not subject to the BBA rules.

It is possible that the Partnership and or certain transactions executed by the Partnership would be subject to tax shelter disclosure registration, special tax filing, record retention requirements and listing requirements under applicable U.S. tax laws and Treasury Regulations. The Partnership intends to provide partners with the information necessary to enable them to satisfy any tax filing and record retention requirements.

Penalty for Substantial Understatements. A penalty is imposed upon a taxpayer substantially understating his tax liability on his tax return. Code Section 6662 imposes a penalty equal to 20% of the amount of the underpayment attributable to a substantial understatement of tax liability. A substantial understatement of tax liability exists if a taxpayer’s reported liability in a taxable year understates the amount required to be reported for such year by the greater of 10% of the total tax due or $5,000 (except with respect to certain corporations and/or unless the taxpayer has claimed a deduction under Section 199A, in which case the percentage is lowered to 5%). Thus, a taxpayer claiming the Code Section 199A deduction has a lower bar to overcome before being assessed a penalty for a substantial underpayment of income tax. Given this potential increased exposure for a penalty, it is important to carefully consider all the limitations and rules when calculating the deduction under Sec. 199A.

Generally, the Code Section 6662 penalty will not be imposed upon that portion of the understatement attributable to the tax treatment of any item if there is or was substantial authority for such treatment or the relevant facts affecting the proper treatment of such items were disclosed on the taxpayer’s return and there was a reasonable basis for the tax treatment. However, as a result of changes made in 2004 with respect to any item attributable to a partnership, the principal purpose of which is to avoid or evade federal income tax, the penalty for understatement of tax liability may not generally be avoided. In addition, all or any part of the penalty may be waived by the IRS if the taxpayer shows a reasonable cause for the understatement and that the taxpayer acted in good faith. Under Treasury Regulations, an opinion of counsel does not constitute substantial authority.

Different rules apply for transactions lacking economic substance.

Under the Bipartisan Budget Act of 2015, penalties are normally determined, and any defenses are to be asserted solely in the partnership level proceeding. Proposed Treasury Regulations, if finalized in their current form, would require partner-level calculations of, and permit partner-level defenses for purposes of calculating penalties attributable to a partnership adjustment in the event of a push-out election.

EACH PROSPECTIVE INVESTOR PARTNER SHOULD CONSULT HIS PERSONAL TAX ADVISER WITH RESPECT TO THE SUBSTANTIAL UNDERSTATEMENT PENALTY.

Reports. The Partnership will annually compute its taxable income or loss for the appropriate taxable period, and in computing such taxable income or loss, it will deduct Intangible Costs, depreciation and other deductible costs to the extent allowable under applicable federal income tax laws and Treasury Regulations. The Partnership will file federal income tax returns which will be for information purposes only, and it will not pay federal income tax on the taxable income computed on that return. Each partner will be furnished either a copy of each Partnership’s federal income tax return or extracts of information therefrom suitable for his use in the preparation of his individual income tax return, and each partner will include in their individual federal income tax return his distributive share of the Partnership’s taxable income (whether or not distributed) or loss, as computed on the federal income tax return of the Partnership.

Each partner is required to treat Partnership items on their return consistently with the treatment on the Partnership return unless the Partner files a statement with the IRS identifying the inconsistency. If a partner fails to satisfy these requirements the IRS may assess any deficiency attributable to any computational adjustment required to make the treatment consistent with the Partnership return.

If a partner sells an interest in the Partnership, the selling partner must promptly notify the Partnership of such transfer (in addition to complying with the restrictions in the partnership agreement). The Partnership is required to file a return for the year of the sale setting forth the name and address of the selling partner and the transferee. By Regulation, the Secretary of the Treasury may require other information and establish rules regarding the time and manner for filing this return. The Partnership must also furnish the information shown on the return to the persons named therein. A penalty may be imposed for failure to give notice, file the return or furnish information in a timely manner.

Partners Required to Maintain Information. Partners are required to maintain records concerning their share of the basis of oil and gas properties and the related depletion allowances. The Partnership will allocate the adjusted basis of each oil and gas property to the partners as set forth in the partnership agreement and provide a report of such allocation to each Partner, who then must keep his own records.

Possible Changes in Federal Tax Laws. The statutes and Treasury Regulations with respect to all of the foregoing tax matters are subject to continual change by Congress or the Department of Treasury. Similarly, interpretations of these statutes and Treasury Regulations may be modified or affected by judicial decision or the Department of Treasury. Any such change may have an effect on the discussion set forth above.

Furthermore, in recent years, there have been a number of other proposals made in Congress by government agencies and the executive branch of the federal government for changes in federal income tax laws. In addition, the IRS has proposed and is still considering changes in Treasury Regulations and procedures, and numerous private interest groups have lobbied for regulatory and legislative changes in federal income taxation. Many of such proposals would, if adopted, have the overall effect of reducing the tax benefits presently associated with participating in partnerships such as the Partnership.

It is likely that further proposals will be forthcoming or that previous proposals will be revived in some form in the future. It is impossible to predict with any degree of certainty what past proposals may be revived or what new proposals may be forthcoming, the likelihood of adoption of any such proposals, the likely effect of any such proposals upon the income tax treatment presently associated with oil and gas partnerships, ventures, investments, or the Partnership, or the effective date of any legislation which may derive from any such past or future proposals.

CONSULTATION WITH PERSONAL TAX ADVISERS. THE FOREGOING ANALYSIS IS NOT INTENDED AS A SUBSTITUTE FOR CAREFUL TAX PLANNING. EACH PROSPECTIVE INVESTOR PARTNER IN THE PARTNERSHIP SHOULD CONSULT WITH HIS OWN PERSONAL TAX ADVISER CONCERNING (I) THE APPLICABILITY TO AND EFFECT ON HIM OF THE UNITED STATES INCOME TAX LAWS AND THEIR ADMINISTRATION, AND (II) THE APPLICABILITY TO AND EFFECT ON HIM OF STATE, LOCAL AND FOREIGN TAX LAWS AND THEIR ADMINISTRATION.

THE TAX BENEFITS OF OIL AND GAS EXPLORATION DO NOT ELIMINATE THE RISKS.

SUMMARY OF PARTNERSHIP AGREEMENT

The rights and obligations of the partners in the Partnership will be governed by the limited partnership agreement of the Partnership. The form of partnership agreement of the Partnership is attached to this offering circular as an exhibit. You should study carefully the partnership agreement in its entirety before subscribing for Units. The following summary of material terms of the partnership agreement is not complete and in no way amends or modifies the partnership agreement.

Our Responsibility

We will exclusively manage and control all aspects of the business of the Partnership. No investor partner shall have any voice in the day-to-day business operations of the Partnership. We are authorized to delegate and subcontract our duties under the partnership agreement to others, including entities related to us. As the Managing General Partner, we cannot delegate our fiduciary duty to the Partnership while we serve as the Managing General Partner.

Liability of General Partners, Including Additional General Partners

General partners, including additional general partners, will not be protected by limited liability for partnership activities. The additional general partners will be jointly and severally liable for all obligations and liabilities to creditors and claimants, whether arising out of contract or tort, in the conduct of partnership operations. Although the Partnership will maintain insurance coverage in amounts we deem appropriate, insurance coverage may be insufficient.

We intend to maintain general liability insurance. In addition, we have agreed to indemnify each of the additional general partners for obligations related to casualty and business losses that exceed available insurance coverage and partnership assets.

The additional general partners, by execution of the partnership agreement, grant us the exclusive authority to manage the Partnership business in our sole discretion and to bind the Partnership and all partners in our conduct of the Partnership business. The additional general partners will not be authorized to participate in the management of the Partnership business. The partnership agreement prohibits the additional general partners from acting in a manner harmful to the assets or the business of the Partnership or to do any other act that would make it impossible to carry on the ordinary business of the Partnership. If an additional general partner acts in contravention of the terms of the partnership agreement, losses caused by his actions will be borne by such additional general partner alone and such additional general partner may be liable to other partners for all damages resulting from his breach of the partnership agreement. Additional general partners who choose to assign their Units in the future may only do so as provided in the partnership agreement. The liability of partners who have assigned their Units may continue after such assignment unless a formal assumption and release of liability is effected.

Liability of Limited Partners

The Partnership is governed by the TBOC under which a limited partner’s liability for the obligations of the Partnership is limited to his capital contribution, his share of partnership assets and the return of distributions from the Partnership to the partner that were made at a time when the partner knew the liabilities of the Partnership exceeded its assets. A limited partner will not otherwise be liable for the obligations of the Partnership unless, in addition to the exercise of his rights and powers as a limited partner, such person takes part in the control of the business of the Partnership.

Allocations and Distributions

General. Profits and losses are to be allocated and cash is to be distributed in the manner described in the section of this offering circular entitled “PARTICIPATION IN DISTRIBUTIONS, PROFITS AND LOSSES.”

Time of Distributions. We will determine distributable cash at least on a monthly basis. At our discretion, we may make distributions more or less frequently.

Liquidating Distributions. In the event of dissolution of the Partnership, distributions will be made only after due provision has been made for, among other things, payment of all Partnership debts and liabilities. Any in-kind property distributions to limited and additional general partners from the Partnership may, in the Managing General Partner’s discretion, be made to a liquidating trust or similar entity. Also, if the Partnership is liquidated we will be repaid for any debts owed to us by the Partnership before there are any payments to limited and additional general partners in the Partnership. Distributions to the partners will then be made in accordance with their respective positive capital account balances after taking into account all contributions, distributions, and allocations for prior periods. No limited partner will have any obligation to make any contribution to the capital of the Partnership in the event such limited partner has a capital account deficit balance. However, additional general partners will be required to fund any respective deficit during the applicable fiscal year.

Voting Rights

Meetings of the partners of the Partnership may be called by the Managing General Partner or by investor partners owning a majority or more of the then outstanding Units for any matters for which the investor partners may vote under the limited partnership agreement. Such call for a meeting will be deemed to have been made upon receipt by the Managing General Partner of a written request from investor partners holding the requisite percentage of Units stating the purposes of the meeting. The Managing General Partner will call such a meeting and will provide written notice to all investor partners of the meeting and the purpose of the meeting, which will be held on a date not less than 10 nor more than 60 days after the date of mailing of such notice. Investor partners have the right to vote in person or by proxy. For the Partnership, an affirmative vote by the partners representing a majority in interest, without the necessity of our concurrence, will be required to approve any of the following matters:

For the Partnership, an affirmative vote of the partners representing a majority in interest, without the necessity of our concurrence, will be required to approve any of the following matters:

We, if we were removed by the investor partners in the Partnership, may elect to retain our interest in the Partnership as a limited partner in the successor limited partnership (assuming that the investor partners determined to continue the Partnership and elected a successor managing general partner).

Our Retirement and Removal

We have generally agreed not to withdraw from the Partnership as the managing general partner. However, we may do so only after giving 120 days’ prior written notice and obtaining the consent of a super-majority in interest of the investor partners.

In the event that the investor partners desire to remove us (or any successor) as the managing general partner, they may do so at any time upon 90 days’ written notice with the consent of a super-majority in interest of the investor partners, and upon the selection of a successor managing general partner within such 90 day period by the investor partners.

Term and Dissolution

The Partnership will continue until December 31, 2071, unless earlier dissolved upon the occurrence of any of the following:

Indemnification

We will be entitled to reimbursement and indemnification for all expenditures made (including amounts paid in settlement of claims) or losses or judgments suffered by us in the ordinary and proper course of the Partnership’s business;. We will have no liability to the Partnership or to any partner for any loss suffered by the Partnership that arises out of any action or inaction by us if we, in good faith, determined that such course of conduct was in the best interest of the Partnership and such course of conduct did not constitute intentional or willful misconduct by us. We will be indemnified by the Partnership against any losses, judgments, liabilities, expenses and amounts paid in settlement of any claims sustained by us in connection with the Partnership, provided that the same were not the result of intentional or willful misconduct on our part. In the event of any action by an investor partner against the Managing General Partner, we will be indemnified and held harmless so long as we are successful in the action.

Notwithstanding the above, we shall not be indemnified for any losses, liabilities or expenses arising under federal and state securities laws unless:

In any claim for indemnification for federal or state securities laws violations, the party seeking indemnification must place before the court the position of the Commission and other respective state securities divisions with respect to the issue of indemnification for securities laws violations.

The advancement of Partnership funds to us or our affiliates for legal expenses and other costs incurred as a result of any legal action for which indemnification is being sought is permissible only if the Partnership has adequate funds available and the following conditions are satisfied:

The Partnership will not incur the cost of the portion of any insurance that insures any party against any liability as to which such party is prohibited from being indemnified under the partnership agreement.

Reports to Partners

We will furnish to the investor partners of the Partnership statements of operating income and expenditures, at least as often as monthly. We will also provide annual reports that will contain financial statements (including a balance sheet and statements of income, partners’ equity and cash flows). More specifically for the Partnership, on an annual basis, we will provide to each person who was a partner of the Partnership during the applicable year, reports containing, except as otherwise indicated, at least the following information:

(a)              a balance sheet as of the last day of the accounting year;

(b)              a statement of income or loss for the full year;

(c)              a statement of changes in financial position;

(d)              a statement of cash flow and distributions for the full year;

(e)              a detailed statement of distributions to and changes in the capital accounts for all partners of the Partnership; and

(f)               a detailed statement of assessments and borrowings, if any.

The Managing General Partner will also furnish to each partner of the Partnership on an annual basis a detailed statement of any transactions by the Partnership with the Managing General Partner and its affiliates, and of fees, commissions, compensation and other benefits paid or accrued to the Managing General Partner and its affiliates.

All investor partners will receive a report containing information necessary for the preparation of their federal income tax returns and any required state income tax returns for each calendar year. We may provide such other reports and financial statements as we deem necessary or desirable. We will retain all appraisals together with the supporting documentation for them in the Partnership’s records for at least six years from the date given.

If, and for so long as, the Partnership is subject to the periodic reporting requirements of the Securities Exchange Act of 1934, current, monthly and annual reports will be filed by the Partnership with the SEC and be publicly available to investor partners. To the extent that such monthly and annual reports filed with the SEC contain any information required to be provided, our obligation to provide such information shall be satisfied by making the monthly or annual reports available on our website to the investor partners or by submission of such information by email.

Access to Partnership Records

The investor partners of the Partnership and/or their representatives have the right to review and copy the Partnership’s books and records at any reasonable time, after adequate notice. The investor partner shall pay all reasonable costs, including costs of the time of personnel, incurred by the Partnership or the Managing General Partner in regard to such review or copying. The Managing General Partner will maintain and preserve during the term of the Partnership and for an additional four years (or such longer period as may be required for tax purposes) all such records, books of account, and other relevant partnership documents. However, the Managing General Partner may keep logs, well reports and other drilling data confidential for a reasonable period of time.

An alphabetical list of the names, addresses and business telephone numbers of the investor partners of the Partnership along with the number of Units held by each of them shall be maintained, and updated at least quarterly , as a part of the books and records of the Partnership. Such partner list will be available for the inspection by an investor partner or its designated agent at the home office of the Partnership upon the request of the investor partner. A copy of the partner list will be mailed to the investor partner requesting the partner list for a proper purpose within a reasonable time after the request. The copy of the partner list will be printed in alphabetical order, on white paper, and in a readily readable type size (in no event smaller than 10-point type). A reasonable charge for copy work may be charged by the Partnership. The purposes for which an investor partner may request a copy of the partner list include, without limitation, matters relating to voting rights under the partnership agreement and the exercise of investor partners’ rights under federal proxy laws. If the Managing General Partner neglects or refuses to exhibit, produce, or mail a copy of the partner list as requested, the Managing General Partner will be liable to any investor partner requesting the list for the costs, including attorneys’ fees, incurred by that investor partner for compelling the production of the partner list, and for actual damages suffered by any investor partner by reason of such refusal or neglect. It will be a defense that the actual purpose and reason for the request for inspection or for a copy of the partner list is to secure the list of investor partners or other information for the purpose of selling such list or information or copies thereof, or of using the list for a commercial purpose other than in the interest of the investor partner relative to the affairs of the Partnership. The Managing General Partner may require the investor partner requesting the partner list to represent that the list is not requested for a commercial purpose unrelated to the investor partner’s interest in the Partnership. The foregoing remedies provided to investor partners requesting copies of the partner list are in addition to, and will not limit, other remedies available to investor partners under federal law, or the laws of any state.

Power of Attorney

Each limited and additional general partner in the Partnership will grant us a power of attorney to execute certain documents deemed by us to be necessary or convenient to the Partnership’s business or required in connection with the qualification and continuance of the Partnership.

Other Provisions

Other provisions of the partnership agreement are summarized in this offering circular under the headings “Terms of the Offering,” “Sources of Funds and Use of Proceeds,” “Participation in Distributions Profits AND Losses,” “Management,” “Conflicts of Interest,” “Fiduciary Responsibility of the managing partner,” and “Transferability of Units.”

TRANSFERABILITY OF UNITS

No Market for the Units. An investment in the Partnership is an illiquid investment. The Units will not be traded on an established securities market or on the substantial equivalent of an established securities market.

Assignment of Units; Substitution. Units may be assigned only to a person otherwise qualified to become a limited or an additional general partner, including the satisfaction of any relevant suitability requirements imposed by law or the Partnership. In no event may any assignment be made that, in the opinion of counsel to the Partnership:

Transferees of Units of partnership interest may be admitted to the Partnership as substituted limited or additional general partners only with our consent, which we may withhold in our sole discretion.

The Partnership will not be required to recognize any assignment until the instrument of assignment has been delivered to us. The assignee of such interest has certain rights of ownership but may become a substituted limited or and additional general partner and thus be entitled to all of the rights of a limited or additional general partner only upon meeting certain conditions, including (i) obtaining our consent to such substitution, (ii) paying all costs and expenses incurred in connection with such substitution, and (iii) executing appropriate documents to evidence its agreement to be bound by all of the terms and provisions of the partnership agreement.

INDEPENDENT AUDITORS

The financial statements of the Managing General Partner, which comprise the balance sheet as of October 4, 2021, and the related statements of operations, member’s equity and cash flows for the period from June 4, 2021 (date of inception) through October 4, 2021, included in this offering circular and the related notes to those financial statements, have been audited by Turner, Stone & Company, LLP, independent auditors, as stated in their report appearing herein.

ACCESS TO INFORMATION

All prospective partners will be given access to information appropriate to the determination of whether to purchase the Units.

Prospective partners may review, at our offices, at any reasonable hour and after reasonable notice, any materials available to us relating to the Partnership, us, or any other matters or items discussed in or accompanying this offering circular. However, we are not obligated to discuss proprietary information.

We will answer all inquiries from prospective partners concerning the matters contained in this offering circular, and will afford prospective partners the opportunity to obtain any additional information (to the extent we possess the information or can acquire it without unreasonable effort or expense) necessary to verify the accuracy of any information in this offering circular.

Universe Energy, LLC

Financial Statements as of

October 4, 2021

INDEX TO FINANCIAL STATEMENTS

Independent Auditors’ Report

To Management of

Universe Energy, LLC

We have audited the accompanying financial statements of Universe Energy, LLC, which comprise the balance sheet as of October 4, 2021, and the related statements of operations, of member’s capital and cash flows for the period June 4, 2021 (date of inception) through October 4, 2021, and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Universe Energy, LLC as of October 4, 2021, and the results of its operations and its cash flows for the period June 4, 2021 (date of inception) through October 4, 2021, in accordance with accounting principles generally accepted in the United States of America.

Emphasis of Matter

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the financial statements, the Company has suffered recurring losses from operations and has insufficient working capital to fund future operations both of which raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

October 25, 2021

Turner, Stone & Company, L.L.P.
Accountants and Consultants
12700 Park Central Drive, Suite 1400
Dallas, Texas 75251 Telephone: 972-239-1660/Facsimile: 972-236-1665 Toll Free: 877-853-4195 Web site: turnerstone.com

Universe Energy, LLC

Balance Sheet

October 4, 2021

The accompanying notes are an integral part of these financial statement.

Universe Energy, LLC

Statement of Operations

For the Period from June 4, 2021 (Date of Inception) through October 4, 2021

The accompanying notes are an integral part of these financial statement.

Universe Energy, LLC

Statement of Member’s Equity

For the Period from June 4, 2021 (Date of Inception) through October 4, 2021

The accompanying notes are an integral part of these financial statement.

Universe Energy, LLC

Statement of Cash Flows

For the Period from June 4, 2021 (Date of Inception) through October 4, 2021

The accompanying notes are an integral part of these financial statement.

Universe Energy, LLC

Notes to Financial Statements

October 4, 2021

Note 1 - Organization, Operations, and Summary of Accounting Policies

Universe Energy, LLC (the “Company”) is a limited liability company duly organized and existing under the laws of the State of Texas. On June 4, 2021, the Company’s Certificate of Formation was filed with the Secretary of State of the State of Texas.

The Company serves as the managing general partner of Universe Energy Partners, LP (the “Partnership”), which was formed for the purpose of (i) acquiring interests in producing oil and gas properties and (ii) exploring for oil and gas reserves. The Company intends to acquire working interests currently owned by the Company’s affiliate, Energy Production Corporation, which is owned by the same shareholder as the Company and operated by common management.

The Company will purchase a 1% interest in the Partnership and additionally holds a 20% carried interest in the operations of the Partnership, pursuant to the Partnership Agreement of the Partnership. The Company will also receive 15% of any offering proceeds received from the Partnership as a management fee, from which the Company will pay all syndication costs, including commissions and finders’ fees that may be paid to licensed broker-dealers and to finders.

Neither the Company nor the Partnership had commenced business operations as of October 4, 2021. There was no business activity between formation and October 4, 2021.

Going Concern

The accompanying financial statement and factors within it, have been prepared on a going concern basis, which contemplates, among other things, the realization of assets and satisfaction of liabilities in the normal course of business and the ability of the Company to continue as a going concern for a reasonable period of time. The Company had net losses of $0 and had cash used in operating activities of $0 for the period of June 4, 2021 (inception) through October 4, 2021. The Company may incur losses and negative operating cash flows in the future. The Company’s ability to continue as a going concern depends upon its ability to obtain adequate funding to support its operations through continuing investments of debt and/or equity by qualified investors/creditors, internally generated working capital. No assurance can be given that the Company will be successful in these efforts. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. The accompanying financial statement has been prepared assuming the Company will continue as a going concern and do not include adjustments that might result from the outcome of this uncertainty. This basis of accounting contemplates the recovery of assets and the satisfaction of liabilities in the normal course of business.

Basis of Presentation

The Company follows the accrual basis of accounting in accordance with generally accepted accounting principles in the United States of America (U.S. GAAP) and has a year-end of December 31.

Use of Estimates

The preparation of the financial statement in conformity with accounting principle generally accepted in the United States of American requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash Equivalents

Cash equivalents are defined as highly liquid investments with original maturities of ninety (90) days or less. The Company places its cash investments with financial institutions insured by the FDIC. No amounts exceeded federally insured limits as of October 4, 2021.

Fair Value of Financial Instruments

In accordance with the reporting requirements of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 825, “Financial Instruments”, the Company measures the fair value of its assets and liabilities which qualify as financial instruments under this standard and includes this additional information in the notes to the financial statements when the fair value is different than the carrying value of those financial instruments. Cash is accounted for at cost which approximates fair value due to the relatively short maturity of these instruments.

We follow accounting guidance for financial and non-financial assets and liabilities. This standard defines fair value, provides guidance for measuring fair value and requires certain disclosures. This standard does not require any new fair value measurements, but rather applies to all other accounting pronouncements that require or permit fair value measurements. This guidance discusses valuation techniques, such as the market approach (comparable market prices), the income approach (present value of future income or cash flow), and the cost approach (cost to replace the service capacity of an asset or replacement cost). The guidance utilizes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three broad levels. The following is a brief description of those three levels:

Level 1: Quoted prices for identical instruments in active markets.

Level 2: Quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations where inputs are observable or where significant value drivers are observable.

Level 3: Instruments where significant value drivers are unobservable to third parties.

Revenues

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). This update provides a comprehensive new revenue recognition model that requires a company to recognize revenue to depict the transfer of goods or services to a customer to an amount that reflects the consideration it expects to receive in exchange for those goods or services. The guidance also requires additional disclosure about the nature, amount, timing, and uncertainty of revenue and cash flows arising from customer contracts. We have adopted this update but have generated no revenues since inception.

Income Taxes

The Company does not incur income taxes; instead, its earnings will be included in the member’s personal income tax return and taxed depending on his personal tax situations. The financial statement, therefore, will not include a provision for income taxes.

Effect of Recent Accounting Pronouncements

The Company reviews new accounting standards and updates as issued. No new standards or updates had any material effect on these financial statements. The accounting pronouncements and updates issued subsequent to the date of these financial statements that were considered significant by management were evaluated for the potential effect on these financial statements.

There have been recent outbreaks in several countries, including the United States, of the highly transmissible and pathogenic coronavirus (“COVID-19”). The outbreak of COVID-19 resulted in a widespread health crisis that adversely affected general commercial activity and the economies and financial markets of many countries, including the United States. Although to date the Company has not been adversely affected by COVID-19, the measures taken by the governments of countries affected could adversely affect the Company’s business, financial condition, and results of operations.

Note 2 – Commitments and Contingencies

Although we may, from time to time, be involved in various legal claims arising out of our operations in the normal course of business, we do not believe that the resolution of these matters will have a material adverse impact on our financial condition or results of operations.

Note 3 – Member’s Equity

The operations of the Company are governed by the limited liability company agreement of the Company. The sole member of the Company is Joe E. Vaughan. The member of the Company is responsible for all management and decisions of the Company. The member will not be liable for additional calls in excess of the original commitment.

Note 4 – Subsequent Events

The Company has evaluated subsequent events through the date of the financial statements were issued, October 25, 2021. The Company has determined that there are no other such events that warrant disclosure or recognition in the financial statements.

PART III - EXHIBITS

EXHIBIT INDEX

* To be filed by amendment.

** Included with the legal opinion provided pursuant to item (12)

SIGNATURES

Pursuant to the requirements of Regulation A, the issuer certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form 1-A and has duly caused this offering statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Dallas, Texas on this October 28 of 2021.

UNIVERSE ENERGY PARTNERS, LP,

a Texas limited partnership

By:       Universe Energy, LLC,

             a Texas limited liability company

Its:        General Partner

By:        /s/ Joe E. Vaughan

Name:   Joe E. Vaughan

Its:        Chief Executive Officer, Manager, and Sole Member

By:        /s/ David W. Vaughan

Name:   David W. Vaughan

Its:        President and Manager

By:       /s/ David W. Vaughan

Name:  David W. Vaughan

Its:       Chief Financial Officer of the General Partner

            (Principal Financial Officer and Principal Accounting Officer)

Exhibit 2.1

Corporations Section P.O. Box 13697 Austin, Texas 78711-3697

Jose A. Esparza Deputy Secretary of State

Office of the Secretary of State

CERTIFICATE OF FILING

OF

Universe Energy Partners, LP

File Number: 804218607

The undersigned, as Deputy Secretary of State of Texas, hereby certifies that a Certificate of Formation for the above named Domestic Limited Partnership (LP) has been received in this office and has been found to conform to the applicable provisions of law.

ACCORDINGLY, the undersigned, as Deputy Secretary of State, and by virtue of the authority vested in the secretary by law, hereby issues this certificate evidencing filing effective on the date shown below.

The issuance of this certificate does not authorize the use of a name in this state in violation of the rights of another under the federal Trademark Act of 1946, the Texas trademark law, the Assumed Business or Professional Name Act, or the common law.

Dated: 08/30/2021

Effective: 08/30/2021

/s/ Jose A. Esparza                Jose A. Esparza Deputy Secretary of State

Come visit us on the Internet at https://www.sos.texas.gov/

CERTIFICATE OF FORMATION

OF

UNIVERSE ENERGY PARTNERS, LP

Pursuant to the provisions of the Texas Business Organizations Code, the undersigned certifies as follows:

1.                 The name of the limited partnership is Universe Energy Partners, LP.

2.                 The street address of the initial registered office of the limited partnership is Premier Place 5910 North Central Expressway, Suite 370, Dallas. Texas 75206, and the name of its initial registered agent for service of process at such address is David William Vaughan.

3.                 The location of the principal place of business of the limited partnership where records are to be kept or made available is Premier Place 5910 North Central Expressway, Suite 370, Dallas, Texas 75206, or at such other location that may hereafter be determined by the limited partnership.

4.                 The name, the mailing address and the business street address of the General Partner of the limited partnership is:

Universe Energy, I

Premier Place

5910 North Central Expressway, Suite 370

Dallas, Texas 75206

5.                 This Certificate of Formation shall become effective when filed by the Secretary of State.

The undersigned signs this document subject to the penalties imposed by law for the submission of a materially false or fraudulent instrument.

Exhibit 4.1

Universe Energy Partners, LP

Units of Limited and Additional General Partnership Interest

SUBSCRIPTION BOOKLET

Offering Price: $25,000 per Unit

Minimum Purchase: $10,000 (0.40 Unit)

Please read the enclosed Instructions to Subscribers and complete the enclosed Subscription Agreement.

EACH INVESTOR IS SUBJECT TO LIMITATIONS ON THE AMOUNT HE OR SHE MAY INVEST, AS SET OUT HEREIN, UNLESS SUCH INVESTOR IS OTHERWISE AN “ACCREDITED INVESTOR” (AS THAT TERM IS DEFINED IN SECTION 501 OF REGULATION D PROMULGATED UNDER THE SECURITIES ACT OF 1933, AS AMENDED (THE “SECURITIES ACT”)). THE COMPANY IS RELYING ON THE REPRESENTATIONS AND WARRANTIES SET FORTH BY EACH SUBSCRIBER IN THIS SUBSCRIPTION AGREEMENT AND THE OTHER INFORMATION PROVIDED BY SUBSCRIBER IN CONNECTION WITH THIS OFFERING TO DETERMINE THE APPLICABILITY TO THIS OFFERING OF EXEMPTIONS FROM THE REGISTRATION REQUIREMENTS OF THE SECURITIES ACT.

Instructions to Subscribers

If you wish to purchase units of limited and/or additional general partnership interest in Universe Energy Partners, LP (the “Partnership”) as described in the Offering Circular, please complete the following steps:

Universe Energy Partners, LP

Premier Place

5910 North Central Expressway, Suite 370

Dallas, Texas 75206

Attention: David Vaughan

Offerees must deliver this booklet (“Subscription Booklet”) no later than 5:00 p.m. Central Standard Time on _________, unless the offering is completed, extended, withdrawn or terminated sooner. If you have any questions concerning this offering or how to complete this Subscription Booklet, please contact David Vaughan at Premier Place, 5910 North Central Expressway, Suite 370, Dallas, Texas 75206, telephone: (972) 885-6799.

When required by the context, use in this Subscription Booklet of the singular shall include the plural, and the masculine gender shall include the feminine and neuter genders, and vice-versa.

EXHIBIT B TO OFFERING CIRCULAR
SUBSCRIPTION AGREEMENT

I hereby agree to purchase:

_______Unit(s) of Limited Partner and/or Additional General Partner interest in Universe Energy Partners, LP (the “Partnership”). Enclosed is my check in the amount of $ ______________________, payable to “Universe Energy Partners, LP” representing my capital contribution of $25,000 per Unit subscribed.

________(initial) My completion and execution of this Subscription Agreement also constitutes my execution of the Limited Partnership Agreement and, if applicable, the Certificate of Formation of the Partnership. If this Subscription is accepted, I agree to be bound and governed by the provisions of the Limited Partnership Agreement of the Partnership. With respect to this purchase, being aware that Universe Energy LLC (“Universe MGP”), as the general partner, may sell to me only if I qualify according to the express standards stated herein and in the offering circular of the Partnership dated October 28, 2021 (the “Offering Circular”), I represent that (initial all that apply):

THE ABOVE REPRESENTATIONS DO NOT CONSTITUTE A WAIVER OF ANY RIGHTS THAT I MAY HAVE UNDER ANY APPLICABLE FEDERAL OR STATE SECURITIES LAW.

Re: UNIVERSE ENERGY PARTNERS, LP - A Texas Limited Partnership

Please complete the following:

Investors are required to execute their own Subscription Agreements. Universe MGP will not accept any Subscription Agreement that has been executed by someone other than the investor or in the case of fiduciary accounts by someone who does not have the legal power of attorney to sign on the investor’s behalf.

NOTICES

An investment in the Units is not liquid.

SIGNATURE AND POWER OF ATTORNEY

I hereby appoint Universe Energy LLC, with full power of substitution, my true and lawful attorney to execute, file, swear to and record any Certificate(s) of Formation or amendments thereto (including but not limited to any amendments filed for the purpose of the admission of any substituted partners) or cancellation thereof, including any other instruments that may be required by law in any jurisdiction to permit qualification of the Partnership as a limited partnership or for any other purpose necessary to implement the Limited Partnership Agreement, and as more fully described in the Limited Partnership Agreement.

DATED: ________________________, 20___.

Subscription for ___________ Unit(s), at $25,000 per Unit totaling $__________. Payable $25,000 per unit at time of subscription.

Amount Enclosed: $__________

_______________________________

Printed Name(s) for Ownership of Record

________________________________________

Subscriber’s Printed Name(s) for Ownership Record

______________________________

Subscriber’s Signature

_______________________________

Co-Subscriber’s Signature

Title to Units to be held as follows:

☐ Individual Ownership

☐ Joint Tenants with Right of Survivorship (both persons must sign)

☐ Tenants in Common (both persons must sign)

☐ Other

If you choose “Other,” then please describe below and include supporting documentation. For example: corporation, LLC, partnership, or trust (other forms of ownership)

Documentation required: Trust documents, Certificate of Formation, Articles or Certificate of Incorporation or Partnership Agreement (or equivalent document).

Address for Notices, if different from that shown on page B-3:

____________________________________________________

Street

I utilize the calendar year as my federal income tax year, unless indicated otherwise as follows:

Other federal income tax year (if applicable):

Re: UNIVERSE ENERGY PARTNERS, LP - A Texas Limited Partnership

Please choose from ONE of the following options:

Type of Account: _______Checking/Broker _______ Savings _____________

PAYEE: (Name check

is to be made out to) ______________________

Street or P.O. Box: ______________________

City, State, Zip Code: ____________________

For the Benefit of (Name): ________________

Account Number: ________

Name: __________________

Address: ________________

City, State, Zip Code: __________

Subscriber's signature is required in order to process information

***Subscriber's Name:       (Print)________________ Date:_____

***Subscriber’s Signature: (Sign) _____________ Date:_________

***Co-Subscriber's Name: (Print)________________ Date:_____

***Co-Subscriber’s Signature: (Sign) _____________ Date:_________

Re: UNIVERSE ENERGY PARTNERS, LP - A Texas Limited Partnership

ACCEPTANCE OF SUBSCRIPTION

Universe Energy Partners, LP hereby accepts the foregoing subscription as of the _______day of __________, 20__.

UNIVERSE ENERGY PARTNERS, LP

By:       Universe Energy LLC,

            Its Managing General Partner

By: _________________

Name: _______________

Title: ________________

SCHEDULE K-1 RELEASE FORM

Re: Universe Energy, LP - A Texas Limited Partnership

This form authorizes Universe Energy LLC and the Partnership to release your federal tax form Schedule K-1 related to the Partnership to your tax preparer listed below.

1. My Tax Preparer Information

By signing below, I hereby authorize Universe Energy LLC and the Partnership to deliver copies of my federal tax form Schedule K-1 (which includes my Partnership tax information and my social security number) related to the Partnership to my financial professional listed in this Subscription Agreement and to the tax preparer identified below.

If I do not sign below, Universe Energy LLC and the Partnership will not release my Schedule K-1 to my tax preparer. The Partnership and Universe Energy LLC will continue to rely on the information regarding my tax preparer contained in the Subscription Agreement until notified otherwise in writing by me.

2. Signature (If title to units is held as Joint Tenants, both parties must sign.)

In an ongoing effort to reduce the amount of paper being used and to reduce costs to our Partnership, Universe Energy LLC and the Partnership would like your consent to distribute your Schedule K-1 electronically instead of by mail.

Please let us know if you would like to receive your Schedule K-1 tax information electronically by returning this page with your Subscription Agreement. Your consent means that Universe Energy LLC will no longer send a paper copy of your Schedule K-1 in the mail.

EXHIBIT C TO OFFERING CIRCULAR
SUITABILITY QUESTIONNAIRE

INSTRUCTIONS

PART I—PURCHASERS WHO ARE INDIVIDUALS

To be qualified to invest in the Partnership, you must either be an Accredited Investor or limit your purchase price to no more than 10% of the greater of your annual income or net worth. Please check the appropriate representation that applies to you.

or

o I confirm that my total individual liabilities, or my total joint liabilities together with my spouse, do not exceed $ . I represent that all liabilities necessary to determine my individual net worth, or my joint net worth together with my spouse, for the purpose of determining my status as an accredited investor are reflected in the dollar amount in the preceding sentence.

o In addition, I confirm that I have not incurred any incremental mortgage or other debt secured by my primary residence in the 60 days preceding the date of this Questionnaire, and I will not incur any incremental mortgage or other debt secured by my primary residence prior to the date of the closing for the sale of the interests in the Partnership to me. I agree to promptly notify Universe MGP if, between the date of this Questionnaire and the date of the closing for the sale of the interests in the Partnership, I incur any incremental mortgage or other debt secured by my primary residence.

Note: For the purposes of calculating your net worth, Net Worth is defined as the difference between total assets and total liabilities. This calculation must exclude the value of your primary residence and may exclude any indebtedness secured by your primary residence (up to an amount equal to the value of your primary residence). In the case of fiduciary accounts, net worth and/or income suitability requirements may be satisfied by the beneficiary of the account or by the fiduciary, if the donor or grantor is the fiduciary and the fiduciary directly or indirectly provides funds for the purchase of the Units.

2. Representations

I represent that:

Signatures for Individuals:

PART II—PURCHASERS WHO ARE NOT INDIVIDUALS

1. General Information

Name of Entity: ________________________________

Address of Principal Office: _______________________

Type of Organization:____________________________

Date and State of Organization: ____________________

Taxpayer Identification No.: _______________________

2. Investor Status

To be qualified to invest in the Partnership, the entity either must be an Accredited Investor or have revenue or net assets for such purchaser’s most recently completed fiscal year end. Please check the appropriate description which applies to the entity.

or