Dorchester Minerals Liquidity and Capital Resources

Capital Resources

After the combination, our primary sources of capital are our cash flow from the Operating ORRIs and the Royalty Properties. Our only cash requirements are the distributions to our unitholders and 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 properly 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 expenses vary directly with oil and natural gas prices and sales volumes, sufficient funds are anticipated to be available at all times for payment thereof.

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. We have not guaranteed the debt of any other party, nor do we have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt.

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).

Credit Facility

Prior to the combination and between 1994 and 2002, Dorchester Hugoton maintained an unsecured revolving credit facility for $15,000,000 with Bank One, Texas, N.A. While the most recent borrowing base was $6,000,000, since August 1997 the highest amount outstanding was $100,000. On June 4, 2002, Dorchester Hugoton repaid its borrowings and terminated the agreement.

Expenses and Capital Expenditures

Prior to the combination, Dorchester Hugoton’s expenses, including merger-related costs, but excluding depreciation, depletion and amortization, ranged from 24% to 32% of net operating revenues for the years ending December 31, 2002, 2001 and 2000. Dorchester Hugoton’s capital expenditures, excluding the acquisition of the Oklahoma production payment in 2001, were less than 2% of net operating revenues for the years ended December 31, 2002, 2001 and 2000.

Dorchester Minerals Operating LP does not currently anticipate drilling additional wells as a working interest owner in the Fort Riley zone, the Council Grove formation or elsewhere in the Oklahoma properties previously owned by Dorchester Hugoton, but successful activities by others in these formations could prompt a reevaluation. Any such drilling is estimated to require $250,000 to $300,000 per well. Dorchester Minerals Operating LP anticipates continuing additional fracture treating in the Oklahoma properties previously owned by Dorchester Hugoton but is unable to predict the cost until additional engineering studies are done. One well, scheduled for fracture treating in February 2003, recovered its volume with minor treatment.

Regarding the facilities formerly owned by Dorchester Hugoton, Dorchester Minerals Operating LP anticipates normal gradual increases in repairs to its Oklahoma gas compression and dehydration facility and gradual increases in Oklahoma field operating costs and expenses as repairs to its 50-year-old pipelines and gas wells become more frequent and as pressures decline. Dorchester Minerals Operating LP does not anticipate significant replacement of these items at this time. However, Dorchester Minerals Operating LP will install rental field compression units at various locations on its Oklahoma gas gathering pipelines in 2003 because of lower pressures. The cost of such additional compression could require from $400,000 to $600,000 in capital and require $450,000 to $500,000 per year additional operating costs (primarily compressor rental). While it is

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believed that the benefits of such compression will more than exceed cost and recover capital, the amount of increased gas production is not currently predictable. At present, environmental permits are being obtained.

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. No additional compression that affects the wells formerly owned by Dorchester Hugoton has been installed since 2000 by operators on adjoining acreage resulting from the relaxed production rules. Such installations by others could require expenditures by Dorchester Minerals Operating LP to stay competitive with adjoining operators.

Liquidity and Working Capital

Dorchester Hugoton’s year-end cash and cash equivalents totaled $23,129,000 for 2002, $18,439,000 for 2001 and $15,767,000 for 2000.

Critical Accounting Policies

Dorchester Minerals uses the full cost method of accounting for its gas properties. Under the full cost method of accounting, all costs of acquisition, exploration and development of gas properties are capitalized in a “full cost pool” as such costs are incurred. Gas properties in the pool, plus estimated future development and abandonment costs are depleted and charged to operations using the unit of production method. The full cost method subjects companies to a quarterly calculation of a “ceiling test” or limitation on the amount that may be capitalized on the balance sheet attributable to gas properties. To the extent capitalized costs (net of depreciation, depletion and amortization) exceed the calculated ceiling, the excess must be permanently written off to expense.

Our discounted present value of our proved natural 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 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 a full cost write-down. 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.

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While the quantities of proved reserves require substantial judgment, the associated prices of natural gas reserves that are included in the discounted present value of our reserves are objectively determined. The ceiling calculation requires prices and costs in effect as of the last day of the accounting period 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. Natural 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.

New Accounting Standards

In July 2001, the Financial Accounting Standards Board issued SFAS No. 143, “Accounting for Asset Retirement Obligations”. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted each period toward its future value, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity reports a gain or loss upon settlement to the extent the actual costs differ from the recorded liability. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. Dorchester Minerals adopted SFAS No. 143 on January 1, 2003 and does not expect it to have a material effect on its financial statements.

Risks Related to Our Business

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

Our Partnership’s 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 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 gas.

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Our Partnership does not control operations and development of the Royalty Properties or Operating ORRIs, 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 Partnership’s stated business objectives is to avoid the generation of unrelated business taxable income, we will generally avoid 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 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 Operating ORRIs, except by removal of our general partner. Dorchester Minerals Operating LP is unable to influence significantly the operations or future development of properties that it does not operate. Dorchester Minerals Operating LP and the other current operators of the properties underlying the Operating ORRIs are under no obligation to continue operating the underlying properties. Dorchester Minerals Operating LP can sell any of the properties underlying the Operating ORRIs that it operates and relinquish the ability to control or influence operations. Any such sale or transfer must also simultaneously include the Operating ORRIs 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 nonproducing properties acquired from Republic and Spinnaker are 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.

Dorchester Minerals Operating LP may transfer or abandon properties that are subject to the Operating ORRIs.

Our general partner, through Dorchester Minerals Operating LP, may at any time transfer all or part of the properties underlying the Operating ORRIs. Our unitholders are not entitled to vote on any transfer, however, any such transfer must also simultaneously include the Operating ORRIs at a corresponding price.

Dorchester Minerals Operating LP 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 Operating ORRIs 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 Operating ORRIs, is directly affected by increases in production costs and other costs. Some of these costs are

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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.

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.

Dorchester Minerals Operating LP may undertake drilling activities in limited circumstances on the properties underlying the Operating ORRIs, 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 Operating ORRIs, the costs of unsuccessful future drilling on the working interest properties that are subject to the Operating ORRIs will reduce amounts payable to us under the Operating ORRIs by 96.97% of these costs.

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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 or another type of interest that did 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.

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 future 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.

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.

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

The vast majority of the properties subject to the Operating ORRIs 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 Operating ORRIs 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 Operating ORRIs, much of the economic risk of the underlying properties is passed along to us.

Under the terms of the Operating ORRIs, 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, we bear 96.97% of the costs of the working interest properties, and if costs exceed revenues, we do not receive any payments under the Operating ORRIs.

In addition, the terms of the Operating ORRIs 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 Operating ORRIs until all prior uncharged costs have been recovered by Dorchester Minerals Operating LP.

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

Dorchester Minerals Operating LP 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 Operating ORRIs and could adversely affect our cash flow.

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

Some of Dorchester Minerals Operating LP’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, Dorchester Minerals Operating LP 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 operations are subject to operating hazards and unforeseen interruptions for which we may not be fully insured.

Neither we nor Dorchester Operating Minerals LP 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 Operating ORRIs will be deducted as a production cost in calculating the net proceeds payable to us.

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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 Operating ORRIs 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 restrict the concentration of gas production wells to one well for each 640 acres. For some time, certain interested parties have sought regulatory changes in Oklahoma which would permit “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 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 Operating ORRIs. If Dorchester Minerals Operating LP, or other operators of our properties do not do the same, our production levels relating to these properties may decrease. Capital expenditures relating to increased density on the properties underlying the Operating ORRIs would be deducted from amounts payable to us under the Operating ORRIs.

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 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 not experience corresponding 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

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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 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 accordance with generally accepted accounting practices. Unitholder K-1 tax statements are calculated based on applicable tax conventions. 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. Beginning with the 2004 annual meeting of limited partners, 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

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be 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.

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.

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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.

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 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.