DORCHESTER MINERALS, L.P. - Annual Report: 2005 (Form 10-K)

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Index to Financial Statements

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

Commission file number: 000-50175

DORCHESTER MINERALS, L.P.

(Exact name of registrant as specified in its charter)

3838 Oak Lawn Avenue, Suite 300

Dallas, Texas 75219

(Address of principal executive offices)(Zip Code)

(214) 559-0300

(Registrant’s telephone number, including area code)

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:

Title of Class

Common Units Representing Limited Partnership Interests

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.    Yes  ¨    No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act.):    Yes  ¨    No  x

The aggregate market value of the common units held by non-affiliates of the registrant (treating all managers, executive officers and 10% unitholders of the registrant as if they may be affiliates of the registrant) was approximately $369,775,851.33 as of June 30, 2005, based on $23.924 per unit, the closing price of the common units as reported on the NASDAQ National Market on such date.

Number of Common Units outstanding as of March 8, 2006: 28,240,431

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement for the registrant’s 2006 Annual Meeting of Unitholders to be held on May 3, 2006, are incorporated by reference in Part III of this Form 10-K. Such definitive proxy statement will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2005.

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TABLE OF CONTENTS

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PART I.

General

Dorchester Minerals, L.P. is a publicly traded Delaware limited partnership that commenced operations on January 31, 2003 upon the combination of Dorchester Hugoton, Ltd., Republic Royalty Company, L.P. and Spinnaker Royalty Company, L.P. Dorchester Hugoton was a publicly traded Texas limited partnership and Republic and Spinnaker were private Texas limited partnerships. Our common units are listed on the NASDAQ National Market. American Stock Transfer & Trust Company is our Registrar and Transfer Agent. Their address and telephone number is 59 Maiden Lane, New York, NY 10038, (800) 937-5449. Our executive offices are located at 3838 Oak Lawn Avenue, Suite 300, Dallas, Texas, 75219-4541 and our telephone number is (214) 559-0300. We do not have an Internet website. We will provide electronic or paper copies of our annual report on Form 10-K, quarterly reports on Form 10-Q, or current reports on Form 8-K and amendments to those reports filed or furnished to the Securities and Exchange Commission, free of charge upon written request to us at our executive offices. In this report, the term “Partnership”, as well as the terms “us,” “our,” “we,” and “its,” are sometimes used as abbreviated references to Dorchester Minerals, L.P. itself or Dorchester Minerals, L.P. and its related entities.

Our general partner is Dorchester Minerals Management LP, which is managed by its general partner, Dorchester Minerals Management GP LLC. As a result, the Board of Managers of Dorchester Minerals Management GP LLC exercises effective control of our Partnership. In this report, the term “general partner” is used as an abbreviated reference to Dorchester Minerals Management LP. Our general partner also controls and owns, directly and indirectly, all of the partnership interests in Dorchester Minerals Operating LP and its general partner, Dorchester Minerals Operating GP LLC. Dorchester Minerals Operating LP owns working interests and other properties underlying our Net Profits Interests, provides day-to-day operational and administrative services to us and our general partner and is the employer of all of the employees who perform such services. In this report, the term “operating partnership” is used as an abbreviated reference to Dorchester Minerals Operating LP. Our wholly owned subsidiary, Dorchester Minerals Acquisition LP has been and may continue to be used as a vehicle through which we may acquire oil and gas properties.

Our general partner and the operating partnership are Delaware limited partnerships and the general partner of our general partner and Dorchester Minerals Operating GP LLC are Delaware limited liability companies. These entities and our Partnership were initially formed in December 2001 in connection with the combination that occurred on January 31, 2003. Dorchester Minerals Acquisition LP is an Oklahoma limited partnership and Dorchester Minerals Acquisition GP, Inc. is an Oklahoma corporation that serves as its general partner. Both were formed in September 2004 in connection with an acquisition of oil and gas properties that was consummated on September 30, 2004.

Our business may be described as the acquisition, ownership and administration of Net Profits Interests and Royalty Properties. The Net Profits Interests represent net profits overriding royalty interests in various properties owned by the operating partnership. The Royalty Properties consist of producing and nonproducing mineral, royalty, overriding royalty, net profits, and leasehold interests located in 573 counties and parishes in 25 states.

Our partnership agreement requires that we distribute quarterly an amount equal to all funds that we receive from the Net Profits Interests and the Royalty Properties less certain expenses and reasonable reserves.

We intend to grow by acquiring additional oil and natural gas properties, subject to the limitations described below. The approval of the holders of a majority of our outstanding common units is required for our general

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partner to cause us to acquire or obtain any oil and natural gas property interest, unless the acquisition is complementary to our business and is made either:

Unless otherwise approved by the holders of a majority of our common units, in the event that we acquire properties for a combination of cash and limited partner interests, including common units, (i) the cash component of the acquisition consideration must be equal to or less than 5% of the aggregate cash distributions made by our Partnership for the four most recent quarters and (ii) the amount of limited partnership interests, including common units, to be issued in such acquisition, after giving effect to such issuance, shall not exceed 10% of the common units outstanding.

Basis of Presentation

Prior to January 31, 2003 we had no operations. The combination transaction consummated on that date among Dorchester Hugoton, Republic and Spinnaker was treated as a purchase by Dorchester Hugoton for accounting purposes. In these circumstances, the financial condition, portions of the business and properties information, and the results of operations are required to be presented for the deemed accounting acquiror, Dorchester Hugoton, for all years ended on or before December 31, 2002. Our Partnership’s financial condition, portions of the business and properties information and the results of operations for the twelve-month period ended December 31, 2003 are required to consist of the one-month period ended January 31, 2003 for Dorchester Hugoton and the eleven-month period ended December 31, 2003 for our Partnership. Consequently, only the twelve month periods ending December 31, 2004 and 2005 contain exclusively Partnership information. For the purposes of this presentation, the term combination means the transactions consummated in connection with the combination of the business and properties of Dorchester Hugoton, Republic and Spinnaker.

Credit Facilities and Financing Plans

We do not have a credit facility in place, nor do we anticipate doing so. We do not anticipate incurring any debt, other than trade debt incurred in the ordinary course of our business. Our partnership agreement prohibits us from incurring indebtedness, other than trade payables, (i) in excess of $50,000 in the aggregate at any given time; or (ii) which would constitute “acquisition indebtedness” (as defined in Section 514 of the Internal Revenue Code of 1986, as amended), in order to avoid unrelated business taxable income for federal income tax purposes. We may finance any growth of our business through acquisitions of oil and natural gas properties by issuing additional limited partnership interests or with cash, subject to the limits described above and in our partnership agreement.

Under our partnership agreement, we may also finance our growth through the issuance of additional partnership securities, including options, rights, warrants and appreciation rights with respect to partnership securities, from time to time in exchange for the consideration and on the terms and conditions established by our general partner in its sole discretion. However, we may not issue limited partnership interests that would represent over 20% of the outstanding limited partnership interests immediately after giving effect to such issuance or that would have greater rights or powers than our common units without the approval of the holders of a majority of our outstanding common units. Except in connection with qualifying acquisitions, we do not currently anticipate issuing additional partnership securities. On May 2, 2005, we filed a registration statement on Form S-4 with the Securities and Exchange Commission to register 5,000,000 common units that may be offered and issued by the Partnership from time to time in connection with asset acquisitions or other business combination transactions. At present, none of the 5,000,000 units have been offered.

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Regulation

Many aspects of the production, pricing and marketing of crude oil and natural gas are regulated by federal and state agencies. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, which frequently increases the regulatory burden on affected members of the industry.

Exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes:

Oil and natural gas operations are also subject to various conservation laws and regulations. These regulations regulate the size of drilling and spacing units or proration units and the density of wells which may be drilled and the unitization or pooling of oil and natural gas properties. In addition, state conservation laws establish a maximum allowable production from oil and natural gas wells. These state laws also generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. These regulations limit the amount of oil and natural gas that the operators of our properties can produce and limit the number of wells or the locations at which the operators can drill.

The transportation of natural gas after sale by operators of our properties is sometimes subject to regulation by state authorities. The interstate transportation of natural gas is subject to federal governmental regulation, including regulation of tariffs and various other matters, by the Federal Energy Regulatory Commission.

Customers and Pricing

The pricing of oil and natural gas sales is primarily determined by supply and demand in the marketplace and can fluctuate considerably. As a royalty owner, we have extremely limited access to timely information, involvement, and operational control over the volumes of oil and natural gas produced and sold and the terms and conditions on which such volumes are marketed and sold.

The operating partnership sells most of its natural gas production to Williams Power Company, Inc. on a daily market price basis through October 2006. The operating partnership frequently reviews alternative gas purchasers. We believe that the loss of Williams Power by the operating partnership or the loss of any single customer would not have a material adverse effect on the results of our operations.

Acquisitions

On January 31, 2003, Dorchester Hugoton contributed assets to us and the operating partnership and then liquidated. Republic and Spinnaker contributed their working interest properties to the operating partnership and then merged with us. As a result, the operating partnership owns certain working interests and management assets and we own the Net Profits Interests and the Royalty Properties.

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On September 30, 2004, we acquired producing and nonproducing mineral, royalty and overriding royalty interests located in 104 counties and parishes in six states in exchange for total consideration of 1,200,000 of our common units. The transaction was structured as a merger between the seller and our wholly owned subsidiary, Dorchester Minerals Acquisition LP.

We acquired minor mineral and leasehold interests located in Steuben County, New York and Hidalgo County, Texas during 2004.

Competition

The energy industry in which we compete is subject to intense competition among many companies, both larger and smaller than we are, many of which have financial and other resources greater than we have.

Operating Hazards and Uninsured Risks

Our operations do not directly involve the operational risks and uncertainties associated with drilling for, and the production and transportation of, oil and natural gas. However, we may be indirectly affected by the operational risks and uncertainties faced by the operators of our properties, including the operating partnership, whose operations may be materially curtailed, delayed or canceled as a result of numerous factors, including:

Also, the ability of the operators of our properties to market oil and natural gas production depends on numerous factors, many of which are beyond their control, including:

The occurrence of an operational risk or uncertainty which materially impacts the operations of the operators of our properties could have a material adverse effect on the amount that we receive in connection with our interests in production from our properties, which could have a material adverse effect on our financial condition or result of operations.

In accordance with customary industry practices, we maintain insurance against some, but not all, of the risks to which our business exposes us. While we believe that we are reasonably insured against these risks, the occurrence of an uninsured loss could have a material adverse effect on our financial condition or results of operations.

Employees

As of February 28, 2006, the operating partnership had 17 full-time employees in our Dallas, Texas office and nine full-time employees in field locations.

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Risks Related to Our Business

Our cash distributions are highly dependent on oil and natural gas prices, which have historically been very volatile.

Our quarterly cash distributions depend in significant part on the prices realized from the sale of oil and, in particular, natural gas. Historically, the markets for oil and natural gas have been volatile and may continue to be volatile in the future. Various factors that are beyond our control will affect prices of oil and natural gas, such as:

Lower oil and natural gas prices may reduce the amount of oil and natural gas that is economic to produce and may reduce our revenues and operating income. The volatility of oil and natural gas prices reduces the accuracy of estimates of future cash distributions to unitholders.

Terrorist attacks on oil and natural gas production facilities, transportation systems and storage facilities could have a material adverse impact on our business.

Oil and natural gas production facilities, transportation systems and storage facilities could be targets of terrorist attacks. These attacks could have a material adverse impact if certain oil and natural gas infrastructure integral to our operations were interrupted, damaged or destroyed, thus preventing the sale of oil and natural gas.

We do not control operations and development of the Royalty Properties or the properties underlying the Net Profits Interests that the operating partnership does not operate, which could impact the amount of our cash distributions.

Essentially all of the producing properties we acquired from Republic and Spinnaker are royalty interests. As a royalty owner, we do not control the development of these properties or the volumes of oil and natural gas produced from them. The decision to develop these properties, including infill drilling, exploration of horizons deeper or shallower than the currently producing intervals, and application of enhanced recovery techniques will be made by the operator and other working interest owners of each property (including our lessees) and may be influenced by factors beyond our control, including but not limited to oil and natural gas prices, interest rates, budgetary considerations and general industry and economic conditions.

As the owner of a fractional undivided mineral or royalty interest, our ability to influence development of these nonproducing properties is severely limited. Also, since one of our stated business objectives is to avoid the generation of unrelated business taxable income, we are prohibited from participation in the development of our properties as a working interest or other expense-bearing owner. The decision to explore for oil and natural gas

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on these properties will be made by the operator and other working interest owners of each property (including our lessees) and may be influenced by factors beyond our control, including but not limited to oil and natural gas prices, interest rates, budgetary considerations and general industry and economic conditions.

Our unitholders are not able to influence or control the operation or future development of the properties underlying the Net Profits Interests. The operating partnership is unable to influence significantly the operations or future development of properties that it does not operate. The operating partnership and the other current operators of the properties underlying the Net Profits Interests are under no obligation to continue operating the underlying properties. The operating partnership can sell any of the properties underlying the Net Profits Interests that it operates and relinquish the ability to control or influence operations. Any such sale or transfer must also simultaneously include the Net Profits Interests at a corresponding price. Our unitholders do not have the right to replace an operator.

Our lease bonus revenue depends in significant part on the actions of third parties which are outside of our control.

A significant portion of the Royalty Properties are unleased mineral interests. With limited exceptions, we have the right to grant leases of these interests to third parties. We anticipate receiving cash payments as bonus consideration for granting these leases in most instances. Our ability to influence third parties’ decisions to become our lessees with respect to these nonproducing properties is severely limited, and those decisions may be influenced by factors beyond our control, including but not limited to oil and natural gas prices, interest rates, budgetary considerations and general industry and economic conditions.

The operating partnership may transfer or abandon properties that are subject to the Net Profits Interests.

Our general partner, through the operating partnership, may at any time transfer all or part of the properties underlying the Net Profits Interests. Our unitholders are not entitled to vote on any transfer, however, any such transfer must also simultaneously include the Net Profits Interests at a corresponding price.

The operating partnership or any transferee may abandon any well or property if it reasonably believes that the well or property can no longer produce in commercially economic quantities. This could result in termination of the Net Profits Interests relating to the abandoned well.

Cash distributions are affected by production and other costs, some of which are outside of our control.

The cash available for distribution that comes from our royalty and mineral interests, including the Net Profits Interests, is directly affected by increases in production costs and other costs. Some of these costs are outside our control, including costs of regulatory compliance and severance and other similar taxes. Other expenditures are dictated by business necessity, such as drilling additional wells in response to the drilling activity of others.

Our oil and natural gas reserves and the underlying properties are depleting assets, and there are limitations on our ability to replace them.

Our revenues and distributions depend in large part on the quantity of oil and natural gas produced from properties in which we hold an interest. Our producing oil and natural gas properties over time will all experience declines in production due to depletion of their oil and natural gas reservoirs, with the rates of decline varying by property. Replacement of reserves to maintain production levels requires maintenance, development or exploration projects on existing properties, or the acquisition of additional properties.

The timing and size of any maintenance, development or exploration projects depends on the market prices of oil and natural gas and on other factors beyond our control. Many of the decisions regarding implementation of such projects, including drilling or exploration on any unleased and undeveloped acreage, will be made by third parties. In addition, development possibilities in the Hugoton field are limited by the developed nature of that field and by regulatory restrictions.

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Our ability to increase reserves through future acquisitions is limited by restrictions on our use of cash and limited partnership interests for acquisitions and by our general partner’s obligation to use all reasonable efforts to avoid unrelated business taxable income. In addition, the ability of affiliates of our general partner to pursue business opportunities for their own accounts without tendering them to us in certain circumstances may reduce the acquisitions presented to our Partnership for consideration.

Drilling activities on our properties may not be productive, which could have an adverse effect on future results of operations and financial condition.

The operating partnership may undertake drilling activities in limited circumstances on the properties underlying the Net Profits Interests, and third parties may undertake drilling activities on our other properties. Any increases in our reserves will come from such drilling activities or from acquisitions.

Drilling involves a wide variety of risks, including the risk that no commercially productive oil or natural gas reservoirs will be encountered. The cost of drilling, completing and operating wells is often uncertain and drilling operations may be delayed or canceled as a result of a variety of factors, including:

Future drilling activities on our properties may not be successful. If these activities are unsuccessful, this failure could have an adverse effect on our future results of operations and financial condition. In addition, under the terms of the Net Profits Interests, the costs of unsuccessful future drilling on the working interest properties that are subject to the Net Profits Interests will reduce amounts payable to us under the Net Profits Interests by 96.97% of these costs.

Our ability to identify and capitalize on acquisitions is limited by contractual provisions and substantial competition.

Our partnership agreement limits our ability to acquire oil and natural gas properties in the future, especially for consideration other than our limited partnership interests. Because of the limitations on our use of cash for acquisitions and on our ability to accumulate cash for acquisition purposes, we may be required to attempt to effect acquisitions with our limited partnership interests. However, sellers of properties we would like to acquire may be unwilling to take our limited partnership interests in exchange for properties.

Our partnership agreement obligates our general partner to use all reasonable efforts to avoid generating unrelated business taxable income. Accordingly, to acquire working interests we would have to arrange for them to be converted into overriding royalty interests, net profits interests, or another type of interest that does not generate unrelated business taxable income in a manner similar to the treatment of Dorchester Hugoton’s properties in the combination. Third parties may be less likely to deal with us than with a purchaser to which such a condition would not apply. These restrictions could prevent us from pursuing or completing business opportunities that might benefit us and our unitholders, particularly unitholders who are not tax-exempt investors.

The duty of affiliates of our general partner to present acquisition opportunities to our Partnership is limited, including pursuant to the terms of the Amended and Restated Business Opportunities Agreement. Accordingly, business opportunities that could potentially be pursued by us might not necessarily come to our attention, which could limit our ability to pursue a business strategy of acquiring oil and natural gas properties.

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We compete with other companies and producers for acquisitions of oil and natural gas interests. Many of these competitors have substantially greater financial and other resources than we do.

Any future acquisitions will involve risks that could adversely affect our business, which our unitholders generally will not have the opportunity to evaluate.

Our current strategy contemplates that we may grow through acquisitions. We expect to participate in discussions relating to potential acquisition and investment opportunities. If we consummate any additional acquisitions, our capitalization and results of operations may change significantly and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in connection with the acquisition, unless the terms of the acquisition require approval of our unitholders. Additionally, our unitholders will bear 100% of the dilution from issuing new common units while receiving essentially 96% of the benefit as 4% of the benefit goes to our general partner.

Acquisitions and business expansions involve numerous risks, including assimilation difficulties, unfamiliarity with new assets or new geographic areas and the diversion of management’s attention from other business concerns. In addition, the success of any acquisition will depend on a number of factors, including the ability to estimate accurately the recoverable volumes of reserves, rates of future production and future net revenues attributable to reserves and to assess possible environmental liabilities. Our review and analysis of properties prior to any acquisition will be subject to uncertainties and, consistent with industry practice, may be limited in scope. We may not be able to successfully integrate any oil and natural gas properties that we acquire into our operations or we may not achieve desired profitability objectives.

A natural disaster or catastrophe could damage pipelines, gathering systems and other facilities that service our properties, which could substantially limit our operations and adversely affect our cash flow.

If gathering systems, pipelines or other facilities that serve our properties are damaged by any natural disaster, accident, catastrophe or other event, our income could be significantly interrupted. Any event that interrupts the production, gathering or transportation of our oil and natural gas, or which causes us to share in significant expenditures not covered by insurance, could adversely impact the market price of our limited partnership units and the amount of cash available for distribution to our unitholders. We do not carry business interruption insurance.

The vast majority of the properties subject to the Net Profits Interests are geographically concentrated, which could cause net proceeds payable under the Net Profits Interests to be impacted by regional events.

The vast majority of the properties subject to the Net Profits Interests are all natural gas properties that are located almost exclusively in the Hugoton field in Oklahoma and Kansas. Because of this geographic concentration, any regional events, including natural disasters, that increase costs, reduce availability of equipment or supplies, reduce demand or limit production may impact the net proceeds payable under the Net Profits Interests more than if the properties were more geographically diversified.

The number of prospective natural gas purchasers and methods of delivery are considerably less than would otherwise exist from a more geographically diverse group of properties. As a result, natural gas sales after gathering and compression tend to be sold to one buyer in each state, thereby increasing credit risk.

Under the terms of the Net Profits Interests, much of the economic risk of the underlying properties is passed along to us.

Under the terms of the Net Profits Interests, virtually all costs that may be incurred in connection with the properties, including overhead costs that are not subject to an annual reimbursement limit, are deducted as production costs or excess production costs in determining amounts payable to us. Therefore, to the extent of the

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revenues from the burdened properties, we bear 96.97% of the costs of the working interest properties. If costs exceed revenues, we do not receive any payments under the Net Profits Interests. However, except as described below, we are not required to pay any excess costs.

The terms of the Net Profits Interests provide for excess costs that cannot be charged currently because they exceed current revenues to be accumulated and charged in future periods, which could result in our not receiving any payments under the Net Profits Interests until all prior uncharged costs have been recovered by the operating partnership. The practice of combining several years’ Net Profits Interests that have excess costs has enabled the operating partnership to recoup excess costs out of revenues from a greater number of properties, deferring to some degree payments to us with respect to such Net Profits Interests.

Damage claims associated with the production and gathering of our oil and natural gas properties could affect our cash flow.

The operating partnership owns and operates the gathering system and compression facilities acquired from Dorchester Hugoton. Casualty losses or damage claims from these operations would be production costs under the terms of the Net Profits Interests and could adversely affect our cash flow.

We may indirectly experience costs from repair or replacement of aging equipment.

Some of the operating partnership’s current working interest wells were drilled and have been producing since prior to 1954. The 132-mile Oklahoma gas pipeline gathering system acquired from Dorchester Hugoton was originally installed in or about 1948, and because of its age is in need of periodic repairs and upgrades. Should major components of this system require significant repairs or replacement, the operating partnership may incur substantial capital expenditures in the operation of the Oklahoma properties previously owned by Dorchester Hugoton prior to the consummation of the combination, which, as production costs, would reduce our cash flow from these properties.

Our cash flow is subject to operating hazards and unforeseen interruptions for which we may not be fully insured.

Neither we nor the operating partnership are fully insured against certain of these risks, either because such insurance is not available or because of high premium costs. Operations that affect the properties are subject to all of the risks normally incident to the oil and natural gas business, including blowouts, cratering, explosions and pollution and other environmental damage, any of which could result in substantial decreases in the cash flow from our overriding royalty interests and other interests due to injury or loss of life, damage to or destruction of wells, production facilities or other property, clean-up responsibilities, regulatory investigations and penalties and suspension of operations. Any uninsured costs relating to the properties underlying the Net Profits Interests will be deducted as a production cost in calculating the net proceeds payable to us.

Governmental policies, laws and regulations could have an adverse impact on our business and cash distributions.

Our business and the properties in which we hold interests are subject to federal, state and local laws and regulations relating to the oil and natural gas industry as well as regulations relating to safety matters. These laws and regulations can have a significant impact on production and costs of production. For example, both Oklahoma and Kansas, where properties that are subject to the Net Profits Interests are located, have the ability, directly or indirectly, to limit production from those properties, and such limitations or changes in those limitations could negatively impact us in the future.

As another example, Oklahoma regulations currently require administrative hearings to change the concentration of gas production wells from one well for each 640 acres in the Guymon-Hugoton field (the location of former Dorchester Hugoton properties). Previously, certain interested parties have sought regulatory

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changes in Oklahoma for “infill,” or increased density, drilling similar to that which is available in Kansas, which allows one well for each 320 acres. Should Oklahoma change its existing regulations to readily permit infill drilling, it is possible that a number of producers will commence increased density drilling in areas adjacent to the properties in Oklahoma that are subject to the Net Profits Interests. If the operating partnership or other operators of our properties do not do the same, our production levels relating to these properties may decrease or mineral owners may demand increased density drilling. Capital expenditures relating to increased density on the properties underlying the Net Profits Interests would be deducted from amounts payable to us under the Net Profits Interests.

Environmental costs and liabilities and changing environmental regulation could affect our cash flow.

As with other companies engaged in the ownership and production of oil and natural gas, we always expect to have some risk of exposure to environmental costs and liabilities because the costs associated with environmental compliance or remediation could reduce the amount we would receive from our properties. The properties in which we hold interests are subject to extensive federal, state, tribal and local regulatory requirements relating to environmental affairs, health and safety and waste management. Governmental authorities have the power to enforce compliance with applicable regulations and permits, which could increase production costs on our properties and affect their cash flow. Third parties may also have the right to pursue legal actions to enforce compliance. It is likely that expenditures in connection with environmental matters, as part of normal capital expenditure programs, will affect the net cash flow from our properties. Future environmental law developments, such as stricter laws, regulations or enforcement policies, could significantly increase the costs of production from our properties and reduce our cash flow.

Our oil and gas reserve data and future net revenue estimates are uncertain.

Estimates of proved reserves and related future net revenues are projections based on engineering data and reports of independent consulting petroleum engineers hired for that purpose. The process of estimating reserves requires substantial judgment, resulting in imprecise determinations. Different reserve engineers may make different estimates of reserve quantities and related revenue based on the same data. Therefore, those estimates should not be construed as being accurate estimates of the current market value of our proved reserves. If these estimates prove to be inaccurate, our business may be adversely affected by lower revenues. We are affected by changes in oil and natural gas prices. Oil prices and natural gas prices may experience inverse price changes.

Risks Inherent In An Investment In Our Common Units

Cost reimbursement due our general partner may be substantial and reduce our cash available to distribute to our unitholders.

Prior to making any distribution on the common units, we reimburse the general partner and its affiliates for reasonable costs and expenses of management. The reimbursement of expenses could adversely affect our ability to pay cash distributions to our unitholders. Our general partner has sole discretion to determine the amount of these expenses, subject to the annual limit of 5% of an amount primarily based on our distributions to partners for that fiscal year. The annual limit includes carry-forward and carry-back features, which could allow costs in a year to exceed what would otherwise be the annual reimbursement limit. In addition, our general partner and its affiliates may provide us with other services for which we will be charged fees as determined by our general partner.

Our net income as reported for tax and financial statement purposes may differ significantly from our cash flow that is used to determine cash available for distributions.

Net income as reported for financial statement purposes is presented on an accrual basis in conformity with accounting principles generally accepted in the United States of America. Unitholder K-1 tax statements are calculated based on applicable tax conventions, and taxable income as calculated for each year will be allocated

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among unitholders who hold units on the last day of each month. Distributions, however, are calculated on the basis of actual cash receipts, changes in cash reserves, and disbursements during the relevant reporting period. Consequently, due to timing differences between the receipt of proceeds of production and the point in time at which the production giving rise to those proceeds actually occurs, net income reported on our financial statements and on unitholder K-1’s will not reflect actual cash distributions during that reporting period.

Our unitholders have limited voting rights and do not control our general partner, and their ability to remove our general partner is limited.

Our unitholders have only limited voting rights on matters affecting our business. The general partner of our general partner manages our activities. Our unitholders only have the right to annually elect the managers comprising the Advisory Committee of the Board of Managers of the general partner of our general partner. Our unitholders do not have the right to elect the other managers of the general partner of our general partner, on an annual or any other basis.

Our general partner may not be removed as our general partner except upon approval by the affirmative vote of the holders of at least a majority of our outstanding common units (including common units owned by our general partner and its affiliates), subject to the satisfaction of certain conditions. Our general partner and its affiliates do not own sufficient common units to be able to prevent its removal as general partner, but they do own sufficient common units to make the removal of our general partner by other unitholders difficult.

These provisions may discourage a person or group from attempting to remove our general partner or acquire control of us without the consent of our general partner. As a result of these provisions, the price at which our common units trade may be lower because of the absence or reduction of a takeover premium in the trading price.

The control of our general partner may be transferred to a third party without unitholder consent.

Our general partner has agreed not to withdraw voluntarily as our general partner on or before December 31, 2010 (with limited exceptions), unless the holders of at least a majority of our outstanding common units (excluding common units owned by our general partner and its affiliates) approve the withdrawal. However, the general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Other than some transfer restrictions agreed to among the owners of our general partner relating to their interests in our general partner, there is no restriction in our partnership agreement or otherwise for the benefit of our limited partners on the ability of the owners of our general partner to transfer their ownership interests to a third party. The new owner of the general partner would then be in a position to replace the management of our Partnership with its own choices.

Our general partner and its affiliates have conflicts of interests, which may permit our general partner and its affiliates to favor their own interests to the detriment of unitholders.

We and our general partner and its affiliates share, and therefore compete for, the time and effort of general partner personnel who provide services to us. Officers of our general partner and its affiliates do not, and are not required to, spend any specified percentage or amount of time on our business. In fact, our general partner has a duty to manage our Partnership in the best interests of our unitholders, but it also has a duty to operate its business for the benefit of its partners. Some of our officers are also involved in management and ownership roles in other oil and natural gas enterprises and have similar duties to them and devote time to their businesses. Because these shared officers function as both our representatives and those of our general partner and its affiliates and of third parties, conflicts of interest could arise between our general partner and its affiliates, on the one hand, and us or our unitholders, on the other, or between us or our unitholders on the one hand and the third parties for which our officers also serve management functions. As a result of these conflicts, our general partner and its affiliates may favor their own interests over the interests of unitholders.

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We may issue additional securities, diluting our unitholders’ interests.

We can and may issue additional common units and other capital securities representing limited partnership units, including options, warrants, rights, appreciation rights and securities with rights to distributions and allocations or in liquidation equal or superior to the securities described in this document, however, a majority of the unitholders must approve such issuance if (i) the partnership securities to be issued will have greater rights or powers than our common units or (ii) if after giving effect to such issuance, such newly issued partnership securities represent over 20% of the outstanding limited partnership interests.

If we issue additional common units, it will reduce our unitholders’ proportionate ownership interest in us. This could cause the market price of the common units to fall and reduce the per unit cash distributions paid to our unitholders. In addition, if we issued limited partnership units with voting rights superior to the common units, it could adversely affect our unitholders’ voting power.

Our unitholders may not have limited liability in the circumstances described below and may be liable for the return of certain distributions.

Under Delaware law, our unitholders could be held liable for our obligations to the same extent as a general partner if a court determined that the right of unitholders to remove our general partner or to take other action under our partnership agreement constituted participation in the “control” of our business.

The general partner generally has unlimited liability for the obligations of our Partnership, such as its debts and environmental liabilities, except for those contractual obligations of our Partnership that are expressly made without recourse to the general partner.

In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that, under certain circumstances, a unitholder may be liable for the amount of distribution for a period of three years from the date of distribution.

Because we conduct our business in various states, the laws of those states may pose similar risks to our unitholders. To the extent to which we conduct business in any state, our unitholders might be held liable for our obligations as if they were general partners if a court or government agency determined that we had not complied with that state’s partnership statute, or if rights of unitholders constituted participation in the “control” of our business under that state’s partnership statute. In some of the states in which we conduct business, the limitations on the liability of limited partners for the obligations of a limited partnership have not been clearly established.

We are dependent upon key personnel, and the loss of services of any of our key personnel could adversely affect our operations.

Our continued success depends to a considerable extent upon the abilities and efforts of the senior management of our general partner, particularly William Casey McManemin, its Chief Executive Officer, James E. Raley, its Chief Operating Officer, and H. C. Allen, Jr., its Chief Financial Officer. The loss of the services of any of these key personnel could have a material adverse effect on our results of operations. We have not obtained insurance or entered into employment agreements with any of these key personnel.

We are dependent on service providers who assist us with providing Schedule K-1 tax statements to our unitholders.

There are a very limited number of service firms that currently perform the detailed computations needed to provide each unitholder with estimated depletion and other tax information to assist the unitholder in various United States income tax computations. There are also very few publicly traded limited partnerships that need these services. As a result, the future costs and timeliness of providing Schedule K-1 tax statements to our unitholders is uncertain.

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Disclosure Regarding Forward-Looking Statements

Statements included in this report which are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions or forecasts related thereto), are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “will,” “expect,” “anticipate,” “estimate,” “continue” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information.

These forward-looking statements are made based upon management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements.

Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed under “Risk Factors” and elsewhere in this report.

You should read these statements carefully because they may discuss our expectations about our future performance, contain projections of our future operating results or our future financial condition, or state other “forward-looking” information. Before you invest, you should be aware that the occurrence of any of the events herein described in “Risk Factors” and elsewhere in this report could substantially harm our business, results of operations and financial condition and that upon the occurrence of any of these events, the trading price of our common units could decline, and you could lose all or part of your investment.

None.

Facilities

Our office in Dallas consists of 11,847 square feet of leased office space. The operating partnership owns a field office in Hooker, Oklahoma and leases part of an office in Amarillo, Texas.

Properties

Our Partnership owns two categories of properties, the Net Profits Interests and the Royalty Properties.

Net Profits Interests

We own net profits overriding royalty interests (referred to as the Net Profits Interests) in various properties owned by the operating partnership. All of the properties formerly owned by Dorchester Hugoton and various mineral, royalty and working interests formerly owned by Republic and Spinnaker were conveyed to the operating partnership subject to a Net Profits Interest upon our formation. We receive monthly payments equaling 96.97% of the net profits actually realized by the operating partnership from these properties in the preceding month. In the event costs exceed revenues in a given month for properties subject to a Net Profits Interest, no payment is made and any deficit is accumulated and carried over and reflected in the following month’s calculation of net profit.

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In accordance with our partnership agreement we have the continuing right to create additional Net Profits Interests by transferring properties to the operating partnership subject to the reservation of a Net Profits Interest identical to the Net Profit Interests created upon our formation. One such interest was created in each of calendar years 2003, 2004 and 2005 by transferring various properties to the operating partnership subject to a Net Profit Interest. These interests were subsequently combined effective December 31, 2004 and 2005 and we refer to it as the 2003/2004/2005 NPI. As of December 31, 2005 cumulative costs and expenses, which include an interest equivalent, totaled $3,020,000 attributable to the 2003/2004/2005 NPI and exceeded cumulative revenues by $561,000, an amount which we refer to as the 2003/2004/2005 NPI deficit. Our financial statements do not reflect activity attributable to properties subject to Net Profits Interests that are in a deficit status. Consequently, revenues, expenses, production sales volumes and prices, and oil and gas reserves set forth herein do not reflect amounts attributable to the 2003/2004/2005 NPI properties, but information concerning acreage owned and drilling activity thereon do reflect amounts attributable to these properties. All such deficits are borne 100% by our General Partner until the deficit is extinguished. Thereafter, we receive the 96.97% Net Profits Interests attributable to the previously deficit property groups.

Acreage Summary

The following tables set forth as of December 31, 2005 information concerning properties owned by the operating partnership and subject to the Net Profits Interests. Acreage amounts listed under Leasehold reflect gross acres leased by the operating partnership and the working interest share (net acres) in those properties. Acreage amounts listed under Mineral reflect gross acres in which the operating partnership owns a mineral interest and the undivided mineral interest (net acres) in those properties. The operating partnership’s interest in these properties may be unleased, leased by others or a combination thereof. Acreage amounts may not add across due to overlapping ownership among categories.

The following table reflects the states in which the acreage amounts listed above are located.

The operating partnership owns working interests below the currently producing horizons in 47,360 gross/46,960 net acres in Texas County, Oklahoma. The operating partnership has from time to time farmed out its leasehold interests in portions of these lands, reserving an overriding royalty interest therein, and will consider additional exploration or development of these lands as circumstances warrant.

Drilling Activity

During 2005, the operating partnership participated as a working interest or unleased mineral interest owner in 49 wells located on lands subject to the Net Profits Interest. These wells were located in 15 counties in seven states. As of December 31, 2005, 20 of these wells had been completed as producing oil or natural gas wells, one was deemed to be a dry hole and 12 were in various stages of drilling or completion operations. In addition, four

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wells that were drilling as of December 31, 2004 were completed as producing oil or natural gas wells during 2005. Selected new wells drilled in 2005 and the working and net revenue interests owned therein by the operating partnership are summarized in the following table:

Costs Incurred

The following table sets forth information regarding 100% of the costs incurred on a cash basis by the operating partnership during the periods indicated in connection with the properties underlying the Net Profits Interests.

Productive Well Summary

The following table sets forth as of December 31, 2005 the combined number of producing wells on the properties subject to the Net Profits Interests. Gross wells refer to wells in which a working interest is owned. Net wells are determined by multiplying gross wells by the working interest in those wells.

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Royalty Properties

We own Royalty Properties representing producing and nonproducing mineral, royalty, overriding royalty, net profits and leasehold interests in properties located in 573 counties and parishes in 25 states. Acreage amounts listed herein represent our best estimates based on information provided to us as a royalty owner. Due to the significant number of individual deeds, leases and similar instruments involved in the acquisition and development of the Royalty Properties by us or our predecessors, acreage amounts are subject to change as new information becomes available. In addition, as a royalty owner, our access to information concerning activity and operations on the Royalty Properties is limited. Most of our producing properties are subject to old leases and other contracts pursuant to which we are not entitled to well information. Some of our newer leases provide for access to technical data and other information. We may have limited access to public data in some areas through third party subscription services. Consequently, the exact number of wells producing from, or drilling on the Royalty Properties is not determinable. The primary manner by which we will become aware of activity on the Royalty Properties is the receipt of division orders or other correspondence from operators or purchasers.

Acreage Summary

The following table sets forth as of December 31, 2005 a summary of our gross and net, where applicable, acres of mineral, royalty, overriding royalty and leasehold interests, and a compilation of the number of counties and parishes and states in which these interests are located. The majority of our net mineral acres are unleased. Acreage amounts may not add across due to overlapping ownership among categories.

Our net interest in production from royalty, overriding royalty and leasehold interests is based on lease royalty and other third party contractual terms which vary from property to property. Consequently, net acreage ownership in these categories is not determinable. Our net interest in production from properties in which we own a royalty or overriding royalty interest may be affected by royalty terms negotiated by the mineral interest owners in such tracts and their lessees. Our interest in the majority of these properties is perpetual in nature. However, a minor portion of the properties are subject to terms and conditions pursuant to which a portion of our interest may terminate upon cessation of production.

The following table sets forth as of December 31, 2005 the combined summary of total gross and net (where applicable) acres of mineral, royalty, overriding royalty and leasehold interests in each of the states in which these interests are located.

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Leasing Activity

We received cash payments in the amount of $1,734,000 from various sources during 2005, including lease bonus attributable to 69 leases and nine pooling elections and extensions of four leases in lands located in 26 counties and parishes in five states. These leases reflected bonus payments ranging up to $800/acre and initial royalty terms ranging up to 30%. Many of these leases contain additional overriding royalty interests, and provisions for optional working interest participation in subsequent wells, back-in working interests after payout or escalating royalty terms. These cash payments are reflected in our financial statements in various categories including, but not limited to, lease bonus and other income.

We received cash payments in the amount of $1,168,000 from various sources during the fourth quarter of 2005, including lease bonus attributable to 27 leases and pooling elections of our interests in lands located in 14 counties and parishes in four states. These leases reflected bonus payments ranging up to $700/acre and initial royalty terms ranging up to 30%. These cash payments are reflected in our financial statements in various categories including, but not limited to, lease bonus and other income.

The following table sets forth a summary of leases and pooling elections consummated during 2003 through 2005.

Fifteen leases were granted for no bonus consideration in 2005 but which reflected primary terms of as little as six months and royalty terms ranging from 25% to 30%. Average bonus and royalty terms reflected above include these fifteen leases. Ten leases were granted in 2005 which included (in addition to royalty or bonus) an overriding royalty interest, back-in working interest or optional working interest participation. Average royalty terms reflected above do not reflect these additional interests. Amounts reflected above may differ from the financial statements which are presented on an accrual basis. Average Royalty and Bonus exclude amounts attributable to pooling elections. Other Land Revenue includes gas storage, shut-in and delay rental payments, coal royalty, surface use agreements, litigation judgments and settlement proceeds, proceeds of royalty payment audits and other sources. These cash payments are reflected in our financial statements in various categories including, but not limited to, lease bonus, and other income. Other Land Revenue does not include interest income and note principal payments which totaled $413,000 in 2005.

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Drilling Activity

We received division orders for, or otherwise identified 289 new wells completed on our Royalty Properties and Net Profits Interests in 66 counties and parishes in 13 states during 2005. We received division orders for, or otherwise identified 77 new wells completed on our Royalty Properties and Net Profits Interests in 35 counties and parishes in eight states during the fourth quarter of 2005. Selected new wells and the net revenue interest (NRI) owned therein by us are summarized in the following table.

Additional information concerning selected recent activity is summarized below:

T-Patch (Reklaw OSO) Field, Jim Hogg and Starr Counties, Texas—We own varying undivided mineral interests totaling 4,994/1,583 gross/net acres in three tracts in Jim Hogg and Starr Counties, Texas and which we leased to EOG Resources, Inc. (“EOG”) in 2004.

EOG has drilled and completed eight wells on one of these tracts (which we call the Southwest Texas Corp. tract) since August 2004. Initial production test rates from these wells as reported to the Texas Railroad Commission ranged up to 8,970 mcf and 184 barrels of oil per day. These wells produce natural gas and condensate from the Queen City “Reklaw” reservoir at approximately 9,000 feet and have exhibited significant declines from initial production rates. Total gas production from the Southwest Texas Corp. tract declined from a peak of 32,500 mcf per day from five wells in May, 2005 to 14,181 mcfd from seven wells in November. Based on available production data, management is unable to project whether these wells will exhibit hyperbolic or exponential decline profiles. These wells contributed significantly to the increase in royalty gas sales volumes and related cashflow during 2005. We expect volumes and cashflow attributable to these wells to continue to decline in 2006. We received $3,015,000 in cash receipts in 2005 attributable to production during November 2004 through October 2005 from these wells including $1,058,000 in the fourth quarter. We received $505,000 in January and February 2006 attributable to production during November and December 2005 from these wells. Our estimated proved reserves as of December 31, 2005 reflect our 5.12% net revenue interest share of estimated gross remaining reserves of 12.8 bcf and 180,296 barrels attributable to these eight wells. These reserves reflect average gross ultimate reserves of 2.5 bcf and 42,700 barrels per well. No proved undeveloped reserves have been assigned to this property.

EOG has drilled one well and is drilling another on the second of these tracts (which we call the Guerra Mineral Trust tract). The Guerra Mineral Trust No. 1 well spud in January 2006 to a permitted total depth of 8,100 feet and is currently waiting on completion operations. The Guerra Mineral Trust No. 2 well spud in March 2006 to a permitted total depth of 8,000 feet and is currently drilling. We own a 10.2% net revenue interest in this tract.

EOG has not permitted a well to be drilled on the third tract leased in 2004. We own varying undivided mineral interests in eight tracts adjacent to or in the vicinity of this third tract totaling 3,254/1,306 gross/net mineral acres. On January 23, 2006, we circulated a Request For Proposals (RFP) to industry participants, soliciting expressions of interest to lease our interests in these eight tracts. We are currently negotiating an offer with one party. We can not project if, when or with whom we may elect to lease our interests in these lands.

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Jeffress (Vicksburg S) Field, Hidalgo County, Texas—We own varying undivided mineral interests in several thousand acres in the greater Jeffress Field area of western Hidalgo County, Texas. Jeffress and associated nearby fields produce gas and condensate from tight Vicksburg sandstone reservoirs at depths ranging from 8,000 feet to 14,000 feet. El Paso Production and XTO Energy are the most active operators in this area. We leased our interest in approximately 417 acres to Dan A. Hughes Company (“Hughes”) in October 2005 for a 25% royalty. In addition, the operating partnership was granted a five percent overriding royalty interest in the first well which is convertible to a 25% working interest at payout. The operating partnership has the option to participate for a 25% working interest in all future wells drilled on the 417 acre tract or within a surrounding area comprising approximately 1,000 acres. In the event the operating partnership does not exercise this option it will receive a 5% override in wells drilled on the 417 acre tract. Each of these interests is proportionately reduced to our mineral interest, resulting in our ownership of a 6.25% net royalty interest and the operating partnership’s 1.3% net overriding royalty interest or 6.25% working interest.

Hughes drilled the Coates-Dorchester 1 well in November 2005 to a permitted total depth of 11,500 feet. As of December 31, 2005 the well was waiting on completion operations. The well was tested to sales on January 26, 2006 at rates of 3,263 mcf and 96 barrels per day and was flowing at rates of 4,093 mcf and 72 barrels per day on March 7, 2006. No proved reserves have been assigned to our 6.25% net revenue interest or the operating partnership’s 1.3% overriding royalty interest in this well. The overriding royalty interest, back-in working interest and optional working interest in future wells (if any) is part of the 2003/2004/2005 NPI.

Haley Field Area, Loving and Winkler Counties, Texas—We own varying undivided mineral and royalty interests in over 90 sections located in north central Loving and western Winkler counties, Texas and southeastern Lea County, New Mexico portions of the Delaware basin in the vicinity of the Haley Field. Operators active in this area include Anadarko, Browning Oil, Chesapeake Energy and Forest Oil. We leased our interests in 2004 and 2005 in 39 sections for a one-quarter royalty and bonuses ranging up to $700/acre. In addition, the operating partnership has the option to participate for a 10% working interest in wells drilled in 11 of these sections, which option is exercisable after the first well is drilled in each of these sections and in all subsequent wells. Each of these interests is proportionately reduced to our mineral interest in each tract. The optional working interest is part of the 2003/2004/2005 NPI.

As of December 31, 2005, no wells were permitted on these lands.

Fayetteville Shale Trend of Northern Arkansas—We own varying undivided mineral interests totaling 19,543/9,753 gross/net acres located in Cleburne, Conway, Faulkner, Pope, Van Buren and White Counties, Arkansas. These lands are unleased, perpetual mineral interests and are located in what is commonly referred to as the “Fayetteville Shale” trend of the Arkoma Basin. Southwestern Energy and Chesapeake Energy are the most active operators in the play. We have received numerous lease offers for our interests in this area, which offers we have declined to date in order to gather additional information.

On January 30, 2006, we circulated a Request For Proposals (RFP) to industry participants, which RFP solicited expressions of interest to lease our interests in this play. We are currently evaluating several offers. We can not project if, when or with whom we may elect to lease our interests in these lands.

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Oil and Natural Gas Reserves

The following table reflects the Partnership’s proved developed and total proved reserves, future net revenues and SEC PV-10 at December 31, 2003, 2004 and 2005. The reserves and future net revenues are based on the reports of the independent petroleum engineering consulting firms of Calhoun, Blair & Associates as to the Net Profits Interests and Huddleston & Co., Inc. as to the Royalty Properties. Other than those filed with the SEC, our estimated proved reserves have not been filed with or included in any reports to any federal agency.

Title to Properties

Our general partner believes we have satisfactory title to all of our assets. Record title to essentially all our assets has undergone the appropriate filings in the jurisdictions in which such assets are located. Title to property may be subject to encumbrances. Our general partner believes that none of such encumbrances should materially detract from the value of our properties or from our interest in these properties or should materially interfere with their use in the operation of our business.

In connection with the combination, we succeeded to the rights and liabilities of Dorchester Hugoton, Republic and Spinnaker with respect to all legal proceedings involving those partnerships.

In January 2002, some individuals and an association called Rural Residents for Natural Gas Rights sued Dorchester Hugoton, Ltd., along with several other operators in Texas County, Oklahoma. The operating partnership now owns and operates the properties formerly owned by Dorchester Hugoton. These properties contribute a major portion of the Net Profits Interests amounts paid to the Partnership. The plaintiffs consist primarily of Texas County, Oklahoma residents who, in residences located on leases use natural gas from gas wells located on the same leases, at their own risk, free of cost. The plaintiffs seek declaration that their domestic gas use is not limited to stoves and inside lights and is not limited to a principal dwelling as provided in the oil and gas leases entered into in the 1930s to the 1950s. Plaintiffs’ claims against defendants include failure to prudently operate wells, violation of rights to free domestic gas, and fraud. Plaintiffs also seek certification of class action against defendants. On October 1, 2004, the plaintiffs severed claims against the operating partnership regarding royalty underpayments. The operating partnership believes plaintiffs’ claims, including severed claims, are completely without merit. Based upon past measurements of such domestic gas usage, the operating partnership believes the domestic gas damages sought by plaintiffs to be minimal. An adverse decision could reduce amounts the Partnership receives from the Net Profits Interests.

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The Partnership and the operating partnership are involved in other legal and/or administrative proceedings arising in the ordinary course of their businesses, none of which have predictable outcomes and none of which are believed to have any significant effect on financial position or operating results.

No matters were submitted to a vote of unitholders during the fourth quarter of the year ended December 31, 2005.

PART II.

Our Partnership’s common units began trading on the NASDAQ National Market on February 3, 2003. The following summarizes the high and low sales information for the common units for the period indicated. The information below reflects inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions.

As of December 31, 2005, there were 6,973 common unitholders.

Beginning with the quarter ended March 31, 2003, as required by our partnership agreement, we distributed and will continue to distribute, on a quarterly basis, within 45 days of the end of the quarter, all of our available cash. Available cash generally means, all cash and cash equivalents on hand at the end of that quarter, less any amount of cash reserves that our general partner determines is necessary or appropriate to provide for the conduct of its business or to comply with applicable law or agreements or obligations to which we may be subject.

Since our Partnership’s combination on January 31, 2003, unitholder cash distributions per common unit have been:

Distributions beginning with the third quarter 2004 were paid on 28,240,431 units; previous distributions were paid on 27,040,431 units. The partnership agreement requires the next cash distribution to be paid by May 15, 2006.

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Please see “Fourth Quarter 2005 Distribution Indicated Price” discussion contained in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Distributions for production periods and cash receipts and weighted average prices corresponding to the fourth quarter 2005 distribution.

Recent Sales of Unregistered Securities

In connection with the closing of the combination on January 31, 2003, under the terms of the combination agreement we issued (i) a number of common units determined in accordance with the combination agreement to Dorchester Hugoton which were distributed to the former general partners of Dorchester Hugoton as part of the liquidation of Dorchester Hugoton and (ii) general partner interests in our Partnership to the former general partners of Republic and Spinnaker. The former general partners of Dorchester Hugoton, Republic and Spinnaker contributed the common units and general partner interests, as applicable, to our general partner in accordance with the terms of the Contribution Agreement dated December 13, 2001. Under the terms of our partnership agreement, the common units contributed to our general partner by the former general partners of Dorchester Hugoton were converted into general partner interests in our Partnership. The foregoing transactions were exempt from registration under the Securities Act of 1933, as amended, pursuant to Section 4(2) thereof on the basis that the transactions did not involve a public offering. No underwriters were involved in the foregoing transactions.

The combination of Republic, Spinnaker and Dorchester Hugoton on January 31, 2003 was accounted for as a purchase and Dorchester Hugoton was designated as the accounting acquirer in connection with the combination. Prior to January 31, 2003, our Partnership had no combined operations. As a result, the following table sets forth a summary of historical selected financial and operating data for Dorchester Hugoton for 2001 through 2002, and certain pro forma operating data assuming the combination occurred on January 1, 2002. As required, the data presented for fiscal year ended December 31, 2003 consists of 11 months of our Partnership’s results and January 2003 results for Dorchester Hugoton. The years ended December 31, 2004 and 2005 are exclusively our Partnership data. This table should be read in conjunction with the financial statements and related notes included elsewhere in this document. All of the historical data presented prior to 2003 has been derived from the audited financial statements of Dorchester Hugoton and does not contain any information with respect to Republic or Spinnaker, or our Partnership, pre-combination.

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Basis of Presentation

In the combination completed on January 31, 2003 and accounted for as a purchase, Dorchester Hugoton was designated as the accounting acquiror. Prior to January 31, 2003, our Partnership had no combined operations. In these circumstances, we are required to present, discuss and analyze the financial condition and results of operations of Dorchester Hugoton, the accounting acquiror, for the one month period ended January 31, 2003 and the financial condition and results of operations for our Partnership for the eleven month period ended December 31, 2003. Information for the years ended December 31, 2004 and 2005 are exclusively our Partnership. For the purposes of this presentation, the term combination means the transactions consummated in connection with the combination of the business and properties of Dorchester Hugoton, Republic and Spinnaker.

Critical Accounting Policies

We utilize the full cost method of accounting for costs related to our oil and gas properties. Under this method, all such costs are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the units-of-production method. These capitalized costs are subject to a ceiling test however, which limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and gas reserves discounted at 10% plus the lower of cost or market value of unproved properties. In accordance with applicable accounting rules, Dorchester Hugoton was deemed to be the accounting acquiror of the Republic and Spinnaker assets. Our Partnership’s acquisition of these assets was recorded at a value based on the closing price of Dorchester Hugoton’s common units immediately prior to consummation of the combination transaction, subject to certain adjustments. Consequently, the acquisition of these assets was recorded at values that exceed the historical book value of these assets prior to consummation of the combination transaction. Our Partnership did not assign any book or market value to unproved properties, including non-producing royalty, mineral and leasehold interests. The full cost ceiling is evaluated at the end of each quarter. For 2003, our unamortized costs of oil and gas properties exceeded the ceiling test. As a result, in 2003, our Partnership recorded full cost write-downs of $43,804,000. No additional impairments have been recorded since the quarter ended September 30, 2003.

The discounted present value of our proved oil and gas reserves is a major component of the ceiling calculation and requires many subjective judgments. Estimates of reserves are forecasts based on engineering and geological analyses. Different reserve engineers may reach different conclusions as to estimated quantities of natural gas or crude oil reserves based on the same information. Our reserve estimates are prepared by independent consultants. The passage of time provides more qualitative information regarding reserve estimates, and revisions are made to prior estimates based on updated information. However, there can be no assurance that more significant revisions will not be necessary in the future. Significant downward revisions could result in an impairment representing a non-cash charge to earnings. In addition to the impact on calculation of the ceiling test, estimates of proved reserves are also a major component of the calculation of depletion.

While the quantities of proved reserves require substantial judgment, the associated prices of oil and gas reserves that are included in the discounted present value of our reserves are objectively determined. The ceiling test calculation requires use of prices and costs in effect as of the last day of the accounting period, which are generally held constant for the life of the properties. As a result, the present value is not necessarily an indication of the fair value of the reserves. Oil and gas prices have historically been volatile and the prevailing prices at any given time may not reflect our Partnership’s or the industry’s forecast of future prices.

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The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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. For example, estimates of uncollected revenues and unpaid expenses from royalties and Net Profits Interests in properties operated by non-affiliated entities are particularly subjective due to inability to gain accurate and timely information. Therefore, actual results could differ from those estimates. Please see Item 1. Business—Customers and Pricing and Item 2. Properties—Royalty Properties for additional discussion.

New Accounting Standards

None.

Contractual Obligations

Our office lease in Dallas, Texas comprises our contractual obligations.

Results of Operations

Normally, our period-to-period changes in net earnings and cash flows from operating activities are principally determined by changes in oil and natural gas sales volumes and prices, and to a lesser extent, by capital expenditures deducted under the Net Profits Interests calculation. Our portion of oil and gas sales volumes and weighted average sales prices are shown in the following table. The portion of the sales volumes during January 2003 from the properties formerly owned by Dorchester Hugoton is not comparable to production volumes from the same properties in Note 7 of the Notes to Financial Statements because of fuel, shrinkage and pipeline loss.

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Comparison of the twelve-month periods ended December 31, 2005, 2004 and 2003

Net Profits Interests Properties oil sales volumes increased 38% from 8 mbbls during 2004 to 11 mbbls during 2005, primarily as a result of improved production in North Dakota properties. Net Profits Interests Properties gas sales volumes decreased 9% from 5,351 mmcf during 2004 to 4,873 mmcf during 2005 principally as a result of natural reservoir depletion in the Guymon-Hugoton field in Oklahoma.

Royalty Properties oil sales volumes increased 14% from 299 mbbls during 2004 to 340 mbbls during 2005. Royalty Properties gas sales volumes increased 12% from 3,469 mmcf during 2004 to 3,890 mmcf during 2005. The increases in Royalty Property oil and gas sales volumes are attributable to the effects of the acquisition consummated at the end of third quarter of 2004 and new wells drilled in late 2004 and early 2005. See discussion under Drilling Activity in Item 2. Properties—Royalty.

Oil and natural gas sales volumes attributable to the Royalty Properties and oil and natural gas sales volumes attributable to the Net Profits Interests in properties formerly owned by Republic and Spinnaker prior to February 2003 are not included in the table above. See “—Basis of Presentation” and Note 1 of the Notes to Financial Statements. As a result, direct comparison of 2003/2004 volumes is not accurate. Assuming average monthly volumes for the 11 months of results for 2003 are representative of the full year of production, management estimates the 2004 aggregate gas sales volumes from these properties are 2% lower than 2003 and the 2004 aggregate crude oil volumes are 8% lower than 2003. These declines reflect normal reservoir depletion, partially offset by the effects of new drilling activity and properties acquired at the end of the 2004 third quarter.

Weighted average oil sales prices attributable to the Royalty Properties increased 33% from $38.44 per bbl in 2004 to $51.07 per bbl in 2005. Similarly, Royalty Properties weighted average gas sales prices increased 34% from $5.56 per mcf during 2004 to $7.43 per mcf during 2005. Weighted average Net Profits Interests Properties gas sales prices increased 38% from $5.67 per mcf during 2004 to $7.82 per mcf during 2005. Net Profits Interests Properties weighted average oil sales prices increased 35% from $37.51 per bbl during 2004 to $50.58 per bbl during 2005. All such increases resulted from changing market conditions.

Weighted average oil and natural gas sales prices attributable to the Royalty Properties and oil and natural gas sales prices attributable to the Net Profits Interests in properties formerly owned by Republic and Spinnaker prior to February 2003 are not included in the table above. See “—Basis of Presentation” and Note 1 of the Notes to Financial Statements. As a result, direct comparison of 2003/2004 prices is not accurate. Management estimates the 2003 weighted average oil and natural gas sales prices from these properties would not change significantly by inclusion of January 2003. Consequently, Net Profits Interests oil pricing increased approximately 31% and Royalty oil pricing increased approximately 34% from 2003 to 2004. Similarly, Net Profits Interests gas pricing increased approximately 6% and Royalty gas pricing increased approximately 9% from 2003 to 2004.

Our 2005 net operating revenues increased 41% from $56,767,000 during 2004 to $79,765,000 primarily as a result of increased oil and natural gas sales prices. Our 2004 net operating revenues increased 15.3% from $49,224,000 during 2003 to $56,767,000 primarily as a result of increased oil and natural gas sales prices. Management cautions the reader in the comparison of 2003 results because revenues attributable to properties formerly owned by Republic and Spinnaker are not included in January 2003. See “—Basis of Presentation” and Note 1 of the Notes to Financial Statements.

General and administrative costs (“G&A”) decreased from $2,580,000 in 2004 to $2,354,000 in 2005 primarily due to the completion of the Partnership’s office relocation in 2004 as well as the elimination of certain costs that did not occur in 2005. G&A increased from $2,401,000 in 2003 to $2,580,000 in 2004 primarily because of approximately $300,000 in increased costs related to additional personnel and other employee expenses, approximately $125,000 increase related to the October 2004 office relocation, and approximately $170,000 increase due to a one-time production tax deposit by the operating partnership, partially offset by one-time expenses incurred in 2003.

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Tax and regulatory expenses decreased from $1,033,000 in 2004 to $525,000 in 2005 primarily due to reduced compliance costs of both audit and Sarbanes Oxley 404 internal controls over financial reporting, and stabilizing of costs related to the preparation of Annual Form K-1’s for investors. Tax and regulatory expenses increased from $587,000 in 2003 to $1,033,000 in 2004 primarily due to increased compliance costs of both audit and Sarbanes Oxley 404 internal controls over financial reporting costs as well as the preparation of Annual Form K-1’s for investors.

During 2004, several categories of costs were lower than in 2003 as a result of non-recurring expenses associated with the 2003 liquidation of Dorchester Hugoton. Such comparisons include no combination and related expenses in 2004 compared with $3,080,000 primarily as a result of approximately $2,500,000 in 2003 severance payments and related costs. Similarly, management fees in 2003 include a one-time $496,000 charge. See “—Basis of Presentation” and Note 1 of the Notes to Financial Statements.

Depletion and amortization was $20,795,000 in 2004 compared to $20,858,000 in 2005 primarily as a result of a lower depletable base due to the effects of previous depletion. Depletion, depreciation and amortization decreased from $23,639,000 in 2003 to $20,795,000 in 2004 primarily as a result of a lower depletable base due to effects of previous depletion, depreciation and impairment of assets during 2003. Cash flow from operations and cash distributions to unitholders are not affected by depletion, depreciation and amortization. Management cautions the reader in the comparison of 2003 results because operations of the properties formerly owned by Republic and Spinnaker are not included in January 2003. See “—Basis of Presentation,” and Note 1 of the Notes to Financial Statements.

During 2003, our Partnership recorded non-cash charges against earnings totaling $43,804,000. The write-down represents an impairment of oil and gas properties that resulted primarily from the difference, after accumulated depletion and prior write-downs, between the discounted present value of our Partnership’s proved natural gas and oil reserves using the quarter ending gas and oil prices as compared to the initial book value assigned to former Republic and Spinnaker assets in accordance with purchase accounting rules, which value significantly exceeded historic book value. The write-down is a function of such increased initial book value, accumulated depletion and prior write-downs, and changes in prevailing oil and gas prices since the combination transaction. Cash flow from operations and cash distributions to unitholders are not affected by the write-down. See Notes 1 and 5 of the Notes to Financial Statements and “—Critical Accounting Policies.” Considering the impairment (asset write-down) representing the non-cash charge to earnings, 2004 net earnings increased from a loss of $26,827,000 during 2003 to $30,076,000 during 2004. Management cautions the reader in the comparison of results for 2003 because operations of the properties formerly owned by Republic and Spinnaker are not included for January 2003. See “—Basis of Presentation” and Note 1 of the Notes to Financial Statements.

Net cash provided by operating activities increased 42.1% from $48,629,000 during 2004 to $69,112,000 during 2005 and increased 25.6% from $38,727,000 during 2003 to $48,629,000 during 2004 due primarily to the effects of increased oil and natural gas sales prices compared to the prior periods. Management cautions the reader in the comparison of results for 2003 because operations of the properties formerly owned by Republic and Spinnaker are not included for January 2003. See “—Basis of Presentation” and Note 1 of the Notes to Financial Statements.

Liquidity and Capital Resources

Capital Resources

Our primary sources of capital are our cash flow from the Net Profits Interests and the Royalty Properties. Our only cash requirements are the distributions to our unitholders, the payment of oil and gas production and property taxes not otherwise deducted from gross production revenues and general and administrative expenses incurred on our behalf and allocated in accordance with our partnership agreement. Since the distributions to our unitholders are, by definition, determined after the payment of all expenses actually paid by us, the only cash requirements that may create liquidity concerns for us are the payments of expenses. Since most of these

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expenses vary directly with oil and natural gas prices and sales volumes, we anticipate that sufficient funds will be available at all times for payment of these expenses. See Item 5. Market for Registrant’s Common Equity and Related Unitholder Matters for the amounts and dates of cash distributions to our unitholders.

We are not directly liable for the payment of any exploration, development or production costs. We do not have any transactions, arrangements or other relationships that could materially affect our liquidity or the availability of capital resources.

Pursuant to the terms of our partnership agreement, we cannot incur indebtedness, other than trade payables, (i) in excess of $50,000 in the aggregate at any given time or (ii) which would constitute “acquisition indebtedness” (as defined in Section 514 of the Internal Revenue Code of 1986, as amended).

Off-Balance Sheet Arrangements

We have no significant off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to unitholders.

Expenses and Capital Expenditures

The operating partnership does not currently anticipate drilling additional wells as a working interest owner in the Fort Riley zone or the Council Grove formations or elsewhere in the Oklahoma properties previously owned by Dorchester Hugoton. Successful activities by others in these formations or other developments currently underway could prompt a reevaluation of this position. Any such drilling is estimated to cost $300,000 to $350,000 per well. The operating partnership anticipates continuing additional fracture treating in the Oklahoma properties previously owned by Dorchester Hugoton but is unable to predict the cost as a specific engineering study is required for each fracture treatment. Three fracture treatments in those properties were conducted in 2005 and cost between $50,000 and $80,000 per well. The wells did not require casing repairs. The increases in production ranged from 0 mcfd to 119 mcfd. Such activities by the operating partnership could influence the amount we receive from the Net Profits Interests.

The operating partnership owns and operates the wells, pipelines and gas compression and dehydration facilities located in Kansas and Oklahoma previously owned by Dorchester Hugoton. The operating partnership anticipates gradual increases in expenses as repairs to these facilities become more frequent, and anticipates gradual increases in field operating expenses as reservoir pressure declines. The operating partnership does not anticipate incurring significant expense to replace these facilities at this time. These capital and operating costs are reflected in the Net Profits Interests payments we receive from the operating partnership.

In 1998, Oklahoma regulations removed production quantity restrictions in the Guymon-Hugoton field, and did not address efforts by third parties to persuade Oklahoma to permit infill drilling in the Guymon-Hugoton field. Both infill drilling and removal of production limits could require considerable capital expenditures. The outcome and the cost of such activities are unpredictable. Such activities by the operating partnership could influence the amount we receive from the Net Profits Interests. No additional compression affecting the wells formerly owned by Dorchester Hugoton has been installed since 2000 by operators on adjoining acreage. The operating partnership believes it now has sufficient field compression and permits for vacuum operation to remain competitive with adjoining operators for the foreseeable future.

Liquidity and Working Capital

Year-end cash and cash equivalents totaled $23,389,000 for 2005, $12,365,000 for 2004, and $10,881,000 for 2003.

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Distributions

Distributions to limited partners and general partners related to cash receipts for the period from October 2003 through December 2005 were as follows:

Beginning with the third quarter 2004, distributions were paid on 28,240,431 units; previous distributions were paid on 27,040,431 units. In general, the limited partners are allocated 99% of the Net Profits Interest Receipts and 96% of the Royalty Properties Net Receipts.

Net Profits Interests

We receive monthly payments from the operating partnership equal to 96.97% of the net proceeds actually realized by the operating partnership from the properties underlying the Net Profits Interests. The operating partnership retains the 3.03% balance of these net proceeds. Net proceeds generally reflect gross proceeds attributable to oil and natural gas production actually received during the month less production costs actually paid during the same month. Production costs generally reflect drilling, completion, operating and general and administrative costs and exclude depletion, amortization and other non-cash costs. The operating partnership made Net Profits Interests Payments to us totaling $25,018,854 during October 2004 through September 2005, which payments reflected 96.97% of total net proceeds of $25,800,574 realized from September 2004 through August 2005. Net proceeds realized by the operating partnership during September through November 2005 were reflected in Net Profits Interests payments made during October through December 2005. These payments were included in the fourth quarter distribution paid in early 2006 and are excluded from this 2005 analysis.

Royalty Properties

Revenues from the Royalty Properties are typically paid to us with proportionate severance (production) taxes deducted and remitted by others. Additionally, we generally pay ad valorem taxes, general and administrative costs, and marketing and associated costs since royalties and lease bonuses generally do not otherwise bear operating or similar costs. After deduction of the above described costs including cash reserves, our net cash receipts from the Royalty Properties during the period October 2004 through September 2005 were $33,008,437: $31,688,100 (96%) of which was distributed to the limited partners and $1,320,337 (4%) of which was distributed to the general partner. Proceeds received by us from the Royalty Properties during the period October through December 2005 became part of the distribution paid in 2006. Such distribution is excluded from this 2005 analysis.

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Distribution Determinations

The actual calculation of distributions is performed each calendar quarter in accordance with our partnership agreement and the following calculation covering the period October 2004 through September 2005 demonstrates the method.

In summary, our limited partners received 96% and our general partner received 4% of the net cash generated by our activities and those of the operating partnership during this period. Due to these fixed percentages, our general partner does not have any incentive distribution rights or other right or arrangement which will increase its percentage share of net cash generated by our activities or those of the operating partnership.

During the period October 2004 through September 2005, our Partnership’s quarterly distribution payments to limited partners were based on all of its available cash. Our Partnership’s only significant cash reserves that influenced quarterly payments were $748,000 for ad valorem taxes. Additionally, certain production costs under the Net Profits Interests calculation and a small portion of management expense reimbursements include amounts for which funds were set aside monthly to enable payment when due. Examples are pension contributions and payroll taxes. These amounts generally are not held for periods over one year.

Fourth Quarter 2005 Distribution Indicated Price

In an effort to provide the reader with information concerning prices of oil and gas sales that correspond to our quarterly distributions, management calculates the weighted average price by dividing gross revenues received by the net volumes of the corresponding product without regard to the timing of the production to which such sales may be attributable. This “indicated price” does not necessarily reflect the contractual terms for such sales and may be affected by transportation costs, location differentials, and quality and gravity adjustments. While the relationship between the Partnership’s cash receipts and the timing of the production of oil and gas may be described generally, actual cash receipts may be materially impacted by purchasers’ release of suspended funds and by prior period adjustments.

Cash receipts attributable to the Partnership’s Net Profits Interests during the 2005 fourth quarter totaled $10,088,000. These receipts generally reflect oil and gas sales from the properties underlying the Net Profits Interests during August through October 2005. The weighted average indicated prices for oil and gas sales during the 2005 fourth quarter attributable to the Net Profits Interests were $56.78/bbl and $9.75/mcf, respectively.

Cash receipts attributable to the Partnership’s Royalty Properties during the 2005 fourth quarter totaled $12,969,000. These receipts generally reflect oil sales during September through November 2005 and gas sales during August through October 2005. The weighted average indicated prices for oil and gas sales during the 2005 fourth quarter attributable to the Royalty Properties were $58.08/bbl and $9.25/mcf, respectively.

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General and Administrative Costs

In accordance with our partnership agreement, we bear all general and administrative and other overhead expenses subject to certain limitations. We reimburse our general partner for certain allocable costs, including rent, wages, salaries and employee benefit plans. This reimbursement is limited to an amount equal to the sum of 5% of our distributions plus certain costs previously paid. Through December 31, 2005, the limitation was substantially in excess of the reimbursement amounts actually paid or accrued.

Unaudited Pro Forma Data

The following table sets forth summary unaudited pro forma financial data for our Partnership for the year ended December 31, 2003 as though the combination occurred as of January 1, 2003. The pro forma amounts are not necessarily indicative of the results that may be reported in the future. Pro forma adjustments have been made to depletion, depreciation, and amortization to reflect the new basis of accounting for the assets of Spinnaker and Republic as of January 31, 2003, and to revenues to reflect the revenues of Dorchester Hugoton as Net Profits Interests.

Quantitative and Qualitative Disclosures About Market Risk

The following information provides quantitative and qualitative information about our potential exposures to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices, interest rates and currency exchange rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses.

Market Risk Related to Oil and Natural Gas Prices

Essentially all of our assets and sources of income are from the Net Profits Interests and the Royalty Properties, which generally entitle us to receive a share of the proceeds from oil and natural gas production on those properties. Consequently, we are subject to market risk from fluctuations in oil and natural gas prices. Pricing for oil and natural gas production has been volatile and unpredictable for several years. We do not anticipate entering into financial hedging activities intended to reduce our exposure to oil and natural gas price fluctuations.

Absence of Interest Rate and Currency Exchange Rate Risk

We do not anticipate having a credit facility or incurring any debt, other than trade debt. Therefore, we do not expect interest rate risk to be material to us. We do not anticipate engaging in transactions in foreign currencies which could expose us to foreign currency related market risk.

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The financial statements are set forth herein commencing on page F-1.

None.

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, our Partnership’s principal executive officer and principal financial officer, carried out an evaluation of the effectiveness of our disclosure controls and procedures as defined in rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the Exchange Act). Based on their evaluation, they have concluded that our Partnership’s disclosure controls and procedures effectively ensure that the information required to be disclosed in the reports the Partnership files with the SEC is recorded, processed, summarized and reported, within the time periods specified by the SEC.

Managements Annual Report on Internal Control Over Financial Reporting

Management acknowledges its responsibility for establishing and maintaining adequate internal control over financial reporting in accordance with Rule 13a-15(f) promulgated under the Exchange Act. Management has also evaluated the effectiveness of its internal control over external financial reporting in accordance with generally accepted accounting principles within the guidelines of the COSO framework. Based on the results of this evaluation, Management has determined that the Partnership’s internal control over financial reporting was effective as of December 31, 2005. The Partnership’s external auditor, Grant Thornton LLP, has audited the Partnership’s financial statements and has issued an attestation report on Management’s assessment of the Partnership’s internal control over financial reporting. This report is included on page F-2.

Changes in Internal Controls

There were no changes in our Partnership’s internal control over financial reporting (as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934) during the quarter ended December 31, 2005 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

None.

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PART III

The information required by this item is incorporated herein by reference to the 2006 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 2005.

The information required by this item is incorporated herein by reference to the 2006 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 2005.

The information required by this item is incorporated herein by reference to the 2006 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 2005.

The information required by this item is incorporated herein by reference to the 2006 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 2005.

The information required by this item is incorporated herein by reference to the 2006 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 2005.

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PART IV

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GLOSSARY OF CERTAIN OIL AND GAS TERMS

The definitions set forth below shall apply to the indicated terms as used in this document. All volumes of natural gas referred to herein are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.

“bbl” means a standard barrel of 42 U.S. gallons and represents the basic unit for measuring the production of crude oil, natural gas liquids and condensate.

“bcf” means one billion cubic feet under prescribed conditions of pressure and temperature and represents a unit for measuring the production of natural gas.

“Depletion” means (a) the volume of hydrocarbons extracted from a formation over a given period of time, (b) the rate of hydrocarbon extraction over a given period of time expressed as a percentage of the reserves existing at the beginning of such period, or (c) the amount of cost basis at the beginning of a period attributable to the volume of hydrocarbons extracted during such period.

“Division order” means a document to protect lessees and purchasers of production, in which all parties who may have a claim to the proceeds of the sale of production agree upon how the proceeds are to be divided.

“Enhanced recovery” means the process or combination of processes applied to a formation to extract hydrocarbons in addition to those that would be produced utilizing the natural energy existing in that formation. Examples of enhanced recovery include water flooding and carbon dioxide (CO2) injection.

“Estimated Future Net Revenues” (also referred to as “estimated future net cash flow”) means the result of applying current prices of oil and natural gas to estimated future production from oil and natural gas proved reserves, reduced by estimated future expenditures, based on current costs to be incurred, in developing and producing the proved reserves, excluding overhead.

“Formation” means a distinct geologic interval, sometimes referred to as the strata, which has characteristics (such as permeability, porosity and hydrocarbon saturations) which distinguish it from surrounding intervals.

“Gross acre” means the number of surface acres in which a working interest is owned.

“Gross well” means a well in which a working interest is owned.

“Lease bonus” means the initial cash payment made to a lessor by a lessee in consideration for the execution and conveyance of the lease.

“Leasehold” means an acre in which a working interest is owned.

“Lessee” means the owner of a lease of a mineral interest in a tract of land.

“Lessor” means the owner of the mineral interest who grants a lease of his interest in a tract of land to a third party, referred to as the lessee.

“Mineral interest” means the interest in the minerals beneath the surface of a tract of land. A mineral interest may be severed from the ownership of the surface of the tract. Ownership of a mineral interest generally involves four incidents of ownership: (1) the right to use the surface; (2) the right to incur costs and retain profits, also called the right to develop; (3) the right to transfer all or a portion of the mineral interest; and (4) the right to retain lease benefits, including bonuses and delay rentals.

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“mcf” means one thousand cubic feet under prescribed conditions of pressure and temperature and represents the basic unit for measuring the production of natural gas.

“mbbls” means one thousand standard barrels of 42 U.S. gallons and represents the basic unit for measuring the production of crude oil, natural gas liquids and condensate.

“mmcf” means one million cubic feet under prescribed conditions of pressure and temperature and represents the basic unit for measuring the production of natural gas.

“Net acre” means the product determined by multiplying “gross” acres by the interest in such acres.

“Net well” means the product determined by multiplying “gross” oil and natural gas wells by the interest in such wells.

“Net profits interest” means a non-operating interest that creates a share in gross production from another (operating or non-operating) interest in oil and natural gas properties. The share is determined by net profits from the sale of production and customarily provides for the deduction of capital and operating costs from the proceeds of the sale of production. The owner of a net profits interest is customarily liable for the payment of capital and operating costs only to the extent that revenue is sufficient to pay such costs but not otherwise.

“Operator” means the individual or company responsible for the exploration, development, and production of an oil or natural gas well or lease.

“Overriding royalty interest” means a royalty interest created or reserved from another (operating or non-operating) interest in oil and natural gas properties. Its term extends for the same term as the interest from which it is created.

“Proved developed reserves” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

“Proved reserves” means the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

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(iii) Estimates of proved reserves do not include the following: (a) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves” (b) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (c) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (d) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

“Proved undeveloped reserves” means proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

“Royalty” means an interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage.

“SEC PV-10” means the pretax present value of estimated future net revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.

“Severance tax” means an amount of tax, surcharge or levy recovered by governmental agencies from the gross proceeds of oil and natural gas sales. Production tax may be determined as a percentage of proceeds or as a specific amount per volumetric unit of sales. Severance tax is usually withheld from the gross proceeds of oil and natural gas sales by the first purchaser (e.g. pipeline or refinery) of production.

“Standardized measure of discounted future net cash flows” (also referred to as “standardized measure”) means the SEC PV-10 defined above, less applicable income taxes.

“Undeveloped acreage” means lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

“Unitization” means the process of combining mineral interests or leases thereof in separate tracts of land into a single entity for administrative, operating or ownership purposes. Unitization is sometimes called “pooling” or “communitization” and may be voluntary or involuntary.

“Working interest” (also referred to as an “operating interest”) means a real property interest entitling the owner to receive a specified percentage of the proceeds of the sale of oil and natural gas production or a percentage of the production, but requiring the owner of the working interest to bear the cost to explore for, develop and produce such oil and natural gas. A working interest owner who owns a portion of the working interest may participate either as operator or by voting his percentage interest to approve or disapprove the appointment of an operator and certain activities in connection with the development and operation of a property.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: March 8, 2006

Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.