DORCHESTER MINERALS, L.P. - Annual Report: 2002 (Form 10-K)

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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)

3738 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 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 an accelerated filer (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 $222,923,279 as of March 24, 2003, based on $14.14 per unit, the closing price of the common units as reported on the NASDAQ National Market on such date. As the registrant began trading on February 3, 2003, disclosure of the above information as of the last business day of the most recently completed second fiscal quarter is not possible.

Number of Common Units outstanding as of March 24, 2003: 27,040,431

DOCUMENTS INCORPORATED BY REFERENCE: None.

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PART I.

ITEM 1.     BUSINESS

General

Dorchester Minerals, L.P. is a publicly traded Delaware limited partnership that was formed in December 2001 in connection with the combination, which was completed on January 31, 2003, of Dorchester Hugoton, Ltd., which was a publicly traded Texas limited partnership, and Republic Royalty Company and Spinnaker Royalty Company, L.P., both of which were privately held Texas partnerships. Our common units are listed on the NASDAQ National Market. Our executive offices are located at 3738 Oak Lawn Avenue, Suite 300, Dallas, Texas, 75219, and our telephone number is (214) 559-0300. 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, a Delaware limited partnership, and its general partner is Dorchester Minerals Management GP LLC, a Delaware limited liability company. Dorchester Minerals Management LP is managed by Dorchester Minerals Management GP LLC, its general partner. As a result, the Board of Managers of Dorchester Minerals Management GP LLC exercises effective control of our Partnership. Also, our general partner owns, directly and indirectly through Dorchester Minerals Management GP LLC, all of the partnership interests in Dorchester Minerals Operating LP, a Delaware limited partnership, and indirectly controls its management through Dorchester Minerals Operating GP LLC, a Delaware limited liability company. Dorchester Minerals Operating LP also provides day-to-day operational support and services to us and our general partner, such as accounting, tax and land services.

Dorchester Minerals Operating LP holds the working interest properties previously owned by Dorchester Hugoton and a minor portion of mineral interest properties previously owned by Republic and Spinnaker. Dorchester Minerals Oklahoma LP, which is owned directly and indirectly by our Partnership, holds a 96.97% net profits overriding royalty interest in these properties. We refer to our net profits overriding royalty interest in these properties as the Operating ORRIs. After the close of each month, we receive a payment equaling 96.97% of the net proceeds actually received during that month from the properties subject to the Operating ORRIs.

In addition to the Operating ORRIs, we also hold producing and non-producing mineral, royalty, overriding royalty, net profits and leasehold interests which we acquired as part of the combination upon the mergers of Republic and Spinnaker into our Partnership. We refer to these interests as the Royalty Properties. The Royalty Properties located in Oklahoma are held by Dorchester Minerals Oklahoma, L.P. The remaining Royalty Properties are held directly by our Partnership. We currently own Royalty Properties in 25 states and 564 counties and parishes.

We distribute on a quarterly basis all cash that we receive from the ownership of the Operating ORRIs and Royalty Properties beyond that required to pay our costs and fund reasonable reserves. We do not anticipate incurring any debt, other than trade debt incurred in the ordinary course of our business. We seek to avoid unrelated business taxable income for federal income tax purposes to make it practicable for pension funds, IRAs and other tax exempt investors to invest in our common units.

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 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:

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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 shall be equal to or less than 5% of the aggregate cash distributions made by the 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.

We also intend to grow by encouraging exploration and development of our unleased mineral interests through our relationship with Dorchester Minerals Operating LP, which gives us the ability to participate in the exploration and development of these mineral interests.

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 percent 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.

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:

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Natural gas and oil 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 natural gas and oil 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 and federal authorities, specifically by the Federal Energy Regulatory Commission, also referred to as the FERC. The interstate transportation of natural gas is subject to federal governmental regulation, including regulation of tariffs and various other matters, by the FERC.

Customers and Pricing

Operating ORRIs

The pricing of our gas sales is primarily determined by supply and demand in the marketplace and can fluctuate considerably. During 2002, the highest monthly average price of gas was $4.38/MMBTU in December and the lowest monthly average price was $1.90/MMBTU in February.

We believe that the loss of any single customer would not have a material adverse effect on the results of our operations. See “Dorchester Hugoton, Ltd.-Notes to Financial Statements-General and Summary of Significant Accounting Policies-Operating Revenue”.

Royalty Properties

As royalty owners, we have no control over the volumes of oil and natural gas produced and sold from the Royalty Properties. In addition, our involvement in the operation of the Royalty Properties is extremely limited.

We believe that the loss of any single customer would not have a material adverse effect on the results of our operations.

The following table sets forth the three largest customers (purchasers and/or remitters of production proceeds) for the Royalty Properties, during 2002:

Acquisitions

On January 31, 2003, Dorchester Hugoton contributed assets to us and Dorchester Minerals Operating LP and then liquidated. Republic and Spinnaker contributed their working interest properties to Dorchester Minerals

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Operating LP and then merged with our Partnership. As a result, Dorchester Minerals Operating LP owns certain working interests and management assets and we own the Operating ORRIs and the Royalty Properties.

Competition

The energy industry in which we compete is subject to intense competition among a large number of 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 Dorchester Minerals Operating LP, 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 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 that our business exposes us to. 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, 2003, Dorchester Minerals Operating LP had 15 full-time permanent employees in our Dallas and Garland, Texas offices and nine full-time permanent employees in field locations. None of these employees is represented by a union and we believe that we have good relations with our employees.

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ITEM 2.     PROPERTIES

Facilities

Dorchester Minerals Operating LP leases 13,420 square feet in Dallas and Garland, Texas for our Partnership offices. Dorchester Minerals Operating LP also owns a field office in Hooker, Oklahoma and leases part of an office in Amarillo, Texas under a month-to-month lease.

Properties

Operating ORRIs

As a result of the combination, one of our principal assets is a 96.97% net profits overriding royalty interest in the working interest properties formerly owned by Dorchester Hugoton and certain unleased mineral interest and cost bearing properties formerly held by Republic and Spinnaker, which we refer to as the Operating ORRIs. Dorchester Minerals Operating LP owns the underlying properties subject to the Operating ORRIs. The information set forth below with respect to the Operating ORRIs does not include information with respect to certain unleased mineral interest properties formerly held by Republic and Spinnaker on which operations are being conducted by third parties. We believe that the exclusion of this information represents a less than 1% change in each item of information set forth below.

Acreage

The following table sets forth as of December 31, 2002, 100% of the combined underlying developed and undeveloped acreage subject to the Operating ORRIs giving effect to the combination on January 31, 2003 as if it occurred on December 31, 2002. Acreage in which an interest is limited to royalty, overriding royalty or similar interests is excluded. Undeveloped acreage underlies the Oklahoma developed acreage.

Costs Incurred and Drilling Results

The following table sets forth information regarding 100% of the costs incurred in acquisition and development activities during the periods indicated in connection with the properties underlying the Operating ORRIs, giving effect to the combination and assuming the consummation of the combination on January 1 of each period indicated.

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Productive Well Summary

The following table sets forth as of December 31, 2002 the combined number of producing wells on the properties subject to the Operating ORRIs giving effect to the combination on January 31, 2003 as if it occurred on December 31, 2002. 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.

Production Costs and Average Prices

The following table sets forth the production costs deducted under the terms of the Operating ORRIs and total average wellhead sales prices for the Royalty Properties and the properties subject to the Operating ORRIs for the periods indicated giving effect to the combination and assuming the consummation of the combination on January 1 of the periods indicated.

Royalty Properties

As a result of the combination, we also hold producing and non-producing mineral, royalty, overriding royalty, net profits and leasehold interests which we acquired in connection with the mergers of Republic and Spinnaker into our Partnership, which we refer to as the Royalty Properties. We currently own Royalty Properties in 564 counties and 25 states.

Acreage Summary

The following table sets forth as of December 31, 2002 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 and the development status of the acres in each category giving effect to the combination on January 31, 2003 as if it occurred on December 31, 2002. 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. For example, our net interest in production from properties in which we own a royalty or overriding royalty interest will be affected by royalty terms negotiated by the mineral interest owners in such tracts and their lessees.

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The following table sets forth as of December 31, 2002 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 giving effect to the combination on January 31, 2003 as if it occurred on December 31, 2002.

Activity Summary

As a royalty owner, our access to information concerning activity and operations on the Royalty Properties is significantly limited. Most of our producing properties will be subject to leases and other contracts pursuant to which we are not entitled to well information. Some of our 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 at any point in time 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.

The following table sets forth a summary of leases consummated and new wells added during 1998 through 2002 giving effect to the combination and assuming the consummation of the combination on January 1 of each year.

Leasing activity during 2002 includes 11 elections to lease under Oklahoma Corporation Commission (OCC) pooling order terms that generally do not include payment of lease bonus. In addition, one of our predecessors

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elected to participate as an unleased mineral interest owner under four OCC pooling orders. Leasing activity for years prior to 2002 does not include pooling elections of these types.

Oil and Natural Gas Reserves

The following table sets forth on a pro forma basis proved reserves, proved developed reserves, future net revenues and discounted present value of future net revenues using SEC PV-10 present value at December 31, 2002 for the Operating ORRIs and the Royalty Properties giving effect to the combination on January 31, 2003 as if it occurred on December 31, 2002, based on the reports of Calhoun, Blair & Associates as to the properties formerly owned by Dorchester Hugoton and Huddleston & Co., Inc. as to the properties formerly owned by Republic and Spinnaker, both independent petroleum engineer consulting firms. 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 some of our assets may continue to be held by our predecessors until we have made 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.

ITEM 3.     LEGAL PROCEEDINGS

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, referred to as RRNGR, sued Dorchester Hugoton, Anadarko Petroleum Corporation, Conoco, Inc., XTO Energy Inc., ExxonMobil Corporation, Phillips Petroleum Company, Incorporated and Texaco Exploration and Production, Inc. The suit is currently pending in the District Court of Texas County, Oklahoma and discovery is underway by the plaintiffs and defendants. The individuals and RRNGR 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 lease agreements with defendants in the 1930s to the 1950s. Plaintiffs also assert defendants conspired to restrain trade by warning of dangers of natural gas use and using such warnings to induce some plaintiffs to release their domestic gas rights. Plaintiffs also seek certification of class action against defendants. Additionally, plaintiffs seek an accounting of fuel use by defendants. Dorchester Hugoton believes plaintiffs’ claims are completely without merit as to Dorchester Hugoton and has filed an answer. In July 2002, the defendants were granted a motion for

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summary judgment removing RRNGR as a plaintiff. We assumed this liability in connection with the combination, however, based upon past measurements of such gas usage, we believe the damages sought by plaintiffs to be minimal.

We are, and expect to be, involved from time to time in various other legal and administrative proceedings and threatened legal and administrative proceedings incidental to the ordinary course of our business.

ITEM 4.     SUBMISSION OF A MATTER TO A VOTE OF UNITHOLDERS

No matters were submitted to a vote of unitholders during the fourth quarter of the year ended December 31, 2002.

PART II.

ITEM 5.     MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED UNITHOLDER

MATTERS

The 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 March 24, 2003, there were 1,539 common unit holders of record.

Beginning with the quarter ended March 31, 2003, we will 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. Due to the timing of our receipt of production revenues, our initial quarterly distribution will generally reflect two months of production from the Royalty Properties and one month of production from the properties underlying the Operating ORRIs, rather than three months production from both. This is a one-time occurrence associated with the creation of the Operating ORRIs and the delay in our receipt of revenue, as well as the January 31, 2003 closing date of the combination. In addition, our initial quarterly distribution will also reflect payment of costs and expenses for which we are responsible in connection with the combination, such as NASDAQ listing fees, director and officer insurance premiums, recording and filing fees and legal expenses.

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 Dorchester Minerals Management LP 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 Dorchester Minerals Management LP 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

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Section 4(2) thereof on the basis that the transactions did not involve a public offering. No underwriters were involved in the foregoing transactions. Other than the foregoing transactions, there have been no other sales of unregistered securities by our partnership during the last three years.

See Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters, which sets forth certain information with respect to equity compensation plans.

ITEM 6.     SELECTED FINANCIAL DATA

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, Dorchester Minerals 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 the periods indicated and certain pro forma operating data assuming the combination occurred on January 1, 2001. The historical data does not contain any information with respect to Republic, Spinnaker or Dorchester Minerals, post combination. 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 has been derived from the audited financial statements of Dorchester Hugoton and does not contain any information with respect to Republic, Spinnaker or Dorchester Minerals, post combination.

ITEM 7.     MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In the combination completed on January 31, 2003 and accounted for as a purchase, Dorchester Hugoton was designated as the accounting acquirer. Prior to January 31, 2003, Dorchester Minerals had no combined operations. In these circumstances, we are required to discuss and analyze the financial condition and results of operations of Dorchester Hugoton, the accounting acquiror, for the three years ended December 31, 2002. In this Item 7 of this first annual report of Dorchester Minerals, we do not provide any historical information with respect to Republic, Spinnaker, or the post-combination Dorchester Minerals. In future annual reports, we will provide historical information regarding the financial condition and results of operations of Dorchester Minerals, post combination.

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With respect to the Dorchester Hugoton information, you should refer to Dorchester Hugoton’s financial statements and the notes to the financial statements included elsewhere in this document in conjunction with this discussion. The amounts and results of operations included in this discussion and in the accompanying financial statements and notes thereto reflect the historical amounts and results of operations of Dorchester Hugoton and do not contain any information with respect to Dorchester Minerals, Republic or Spinnaker, with exception for certain forward looking matters.

Overview

Dorchester Hugoton’s business operations consisted of producing, gathering and selling natural gas from the long-established Hugoton gas field in Oklahoma and Kansas. Dorchester Hugoton distributed a large proportion of its net cash flow each year. Dorchester Hugoton did not engage in exploration activities and did not engage in development activities except to a very limited extent with respect to replacement or improvement of its existing wells. Dorchester Hugoton’s cash flow from operations was historically sufficient to fund needed cash and capital expenditure requirements, and, while it previously maintained a revolving credit arrangement with a bank, its borrowings since January 1, 1998 were minimal. On June 4, 2002, Dorchester Hugoton repaid all borrowings and terminated its credit arrangement.

Dorchester Hugoton’s period-to-period changes in net earnings and cash flows from operating activities were principally determined by changes in natural gas sales volumes and gas prices. Dorchester Hugoton’s portion of gas sales volumes (not reduced for the Oklahoma production payment, where applicable) and weighted average sales prices were:

It is expected that Dorchester Minerals’ net operating revenues for 2003 and future years will be benefited by Dorchester Hugoton’s acquisition in 2001 of a production payment, which had reduced net operating income and cash flow in prior years. The benefit will be partially offset by increased depletion. Since future payments depend upon future gas prices, the amount of future benefit is not reasonably quantifiable. During the twelve-month periods ending March 1, 2001 and 2000, the production payment to others was approximately $1,701,000 and $730,000, respectively.

Commodity Price Risks

Dorchester Hugoton’s profitability was and Dorchester Minerals’ profitability will continue to be affected by volatility in prevailing natural gas prices. Natural gas prices have been subject to significant volatility in recent years in response to changes in the supply and demand for oil and natural gas in the market and general market volatility.

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Dorchester Hugoton Results of Operations

Year Ended December 31, 2002 Compared with the Year Ended December 31, 2001

As shown in the table above, Dorchester Hugoton’s Oklahoma 2002 gas sales volumes were 5% lower than 2001. Oklahoma volumes were influenced by reduced gas pipeline receipts in 2002 because of an explosion unrelated to Dorchester Hugoton and natural reservoir decline. Dorchester Hugoton’s Kansas 2002 gas sales volumes were 13% lower than 2001 as a result of state well testing and natural reservoir decline. The decline in Kansas sales volume appears to be more stable, as discussed in the comparison of 2001 to 2000.

Dorchester Hugoton’s natural gas weighted average sales prices in 2002 were down 27% compared to 2001 but were up approximately 33% comparing fourth quarter 2002 to third quarter 2002. The significantly lower gas prices and lower gas volumes caused net operating revenues to decrease in 2002 compared to 2001.

Dorchester Hugoton’s operating costs during 2002 were lower than 2001 primarily as a result of lower production taxes associated with reduced gas revenues and lower operating expenses due to the completion in 2001 of scheduled Oklahoma engine maintenance repairs of approximately $300,000.

Dorchester Hugoton recognized a gain in other income of $2,000,000 on the sale of Exxon Mobil stock during December 2002, which it sold in anticipation of the combination.

In summary, net income was down in 2002 compared to 2001 primarily due to significantly reduced operating income as natural gas prices have declined from their early 2001 high levels.

Year Ended December 31, 2001 Compared with the Year Ended December 31, 2000

As shown in the table above, Dorchester Hugoton’s Oklahoma 2001 gas sales volumes were approximately 8% lower than 2000 primarily as a result of extensive scheduled maintenance during 2001 causing downtime on the Oklahoma central gas compression units that deliver the gas into transmission pipelines, combined with natural reservoir decline and pipeline repairs.

Dorchester Hugoton’s Kansas 2001 sales volumes were 10% lower than 2000 as a result of declining well volumes and pressures typical of other producers in that area. The gas volume percentage decline from 2000 was smaller compared to prior years’ declines, which were approximately 20%.

Dorchester Hugoton’s natural gas weighted average sales prices in 2001 were 12% higher than 2000, because of higher marketplace prices during the first half of 2001.

Compared to the prior year, Dorchester Hugoton’s 2001 net operating revenues increased as a result of improved gas pricing, more than offsetting lower gas sales volumes, and as a result of the acquisition of a production payment in Oklahoma which reduced overriding royalty costs $860,000.

Dorchester Hugoton’s operating costs during 2001 were higher than 2000 as a result of: (i) higher production taxes associated with increased gas revenues; (ii) a $530,000 increase in depletion costs resulting from the purchase of the Oklahoma production payment prior to being offset by reduced depletion due to increases in reserves; (iii) increased operating costs (repairs) of $300,000 from scheduled Oklahoma engine maintenance; (iv) higher general and administrative costs (primarily insurance) of approximately $200,000; and, (v) an increase in legal and other costs of $450,000 associated with the proposed combination with Republic and Spinnaker.

As a result, Dorchester Hugoton’s increased cost in 2001 compared to 2000 tended to offset its 2001 increased net operating revenues compared to 2000, producing essentially the same net income for the two years.

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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.

Unaudited Pro Forma Data

The following table sets forth summary unaudited pro forma financial data for our Partnership for the years ended December 31, 2002 and 2001 as though the combination occurred as of January 1, 2001.

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.

ITEM 7A.     QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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 Operating ORRIs 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.

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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, following the combination. 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.

ITEM 8.     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

ITEM 9.     CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND

FINANCIAL DISCLOSURE

None.

ITEM 10.     DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Management of the General Partner

Our general partner is Dorchester Minerals Management LP, a Delaware limited partnership. The management of Dorchester Minerals Management LP is conducted by its general partner, Dorchester Minerals Management GP LLC, a Delaware limited liability company, which owns a 0.1% general partnership interest in Dorchester Minerals Management LP. The business and affairs of Dorchester Minerals Management GP LLC are managed by its Board of Managers. By virtue of this ownership structure, the Board of Managers of Dorchester Minerals Management GP LLC exercises the effective control of the management of our Partnership.

The Board of Managers consists of:

The current appointed managers are H.C. Allen, Jr., William Casey McManemin, Preston A. Peak, James E. Raley and Robert C. Vaughn. Each appointed manager will hold office until the earlier of his death, resignation or removal from office. In the event of any vacancy on the Board of Managers left by an appointed manager, the member who holds the right to appoint the appointed manager will designate the replacement appointed manager, unless the member who otherwise holds the right to appoint the replacement appointed manager has lost his appointment right.

The current independent managers are Buford P. Berry, Frank M. Burke and Rawles Fulgham. Each independent manager will hold office until the next annual meeting of the members, unless he or she has earlier been removed or has resigned. Any vacancy on the Board of Managers left by an independent manager will be filled by the member or members who holds or hold the right to nominate the independent manager whose death, resignation or removal has created the vacancy.

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Advisory Committee/Audit Committee

The independent managers serve on an advisory committee to review specific matters which the Board of Managers believes may involve conflicts of interest between Dorchester Minerals Management LP or any of its affiliates and us, our limited partners or any assignees of our limited partners. The advisory committee determines if the resolution of a conflict of interest is fair and reasonable to us. Any matters approved by the advisory committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. All matters decided upon by the advisory committee require the approval of the majority of the committee’s members. In addition, the members of the advisory committee also serve as an audit committee for us to the extent required by NASDAQ rules and will review our external financial reporting, recommends engagement of our independent auditors and reviews procedures for internal auditing and the adequacy of our internal accounting controls.

Operating Committee

The appointed managers serve on an operating committee that has the authority to oversee day-to-day operations of our business. All matters decided upon by the Operating Committee require the approval of the majority of the committee’s members.

Information Regarding Executive Officers and Appointed and Independent Managers of the General Partner of our General Partner

The following information sets forth the age, position and business experience of each executive officer and manager of Dorchester Minerals Management GP LLC. Each executive officer began serving in that capacity on December 12, 2001 and will serve until his successor is appointed by the Board of Managers or until his death, resignation or removal. The appointed and independent managers began serving in that capacity upon the consummation of the combination on January 31, 2003.

William Casey McManemin serves as Chief Executive Officer and as an Appointed Manager of Dorchester Minerals Management GP LLC, and as Chief Executive Officer of Dorchester Minerals Operating GP LLC and Dorchester Minerals. In addition, he currently serves as Vice-President of the general partner of SAM Partners, Ltd., a limited partner of Dorchester Minerals Management LP and member of Dorchester Minerals Management GP LLC, and of Smith Allen Oil & Gas, Inc., a limited partner of Dorchester Minerals Management LP and member of the Dorchester Minerals Management GP LLC. Mr. McManemin has served in those capacities since 1993 and 1996, respectively. He co-founded SASI Minerals Company, Republic Royalty Company, Spinnaker Royalty Company, L.P. and CERES Resource Partners, LP with Mr. Allen in 1988, 1993, 1996 and 1998, respectively. He was previously associated with the firm of Huddleston & Co., Inc., a petroleum engineering firm, from 1984 to 1988. He received his Bachelor of Science degree in Petroleum Engineering from Texas A&M University in 1984 and has been a Registered Professional Engineer in Texas since 1988. Mr. McManemin currently serves on the board of directors of Dale Gas Partners, LP and WAH Royalty Company.

H.C. Allen, Jr. serves as Chief Financial Officer and as an Appointed Manager of Dorchester Minerals Management GP LLC, and as Chief Financial Officer of Dorchester Minerals Operating GP LLC and Dorchester

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Minerals. In addition, he currently serves as Secretary of the general partner of SAM Partners, Ltd., a limited partner of Dorchester Minerals Management LP and member of Dorchester Minerals Management GP LLC, and of Smith Allen Oil & Gas, Inc., a limited partner of Dorchester Minerals Management LP and member of Dorchester Minerals Management GP LLC. Mr. Allen has served in those capacities since 1993 and 1996, respectively. He co-founded SASI Minerals Company, Republic Royalty Company, Spinnaker Royalty Company, L.P. and CERES Resource Partners, LP with Mr. McManemin in 1988, 1993, 1996 and 1998, respectively. He received his Bachelor of Business Administration degree from the University of Texas in 1962, his Master of Business Administration degree from the University of North Texas in 1963, and has been a Certified Public Accountant since 1964. Mr. Allen has been active in oil and gas investments, real estate development and agribusiness operations since 1969. Mr. Allen was previously associated with a predecessor firm to KPMG Peat Marwick from 1964 to 1968.

James E. Raley serves as Chief Operating Officer and as an Appointed Manager of Dorchester Minerals Management GP LLC, and as Chief Operating Officer of Dorchester Minerals Operating GP LLC and Dorchester Minerals. In addition, he is the sole member of Yelar LLC, the general partner of Yelar Partners L.L.P., which is the successor to James E. Raley, Inc., which served as a general partner of Dorchester Hugoton since 1990 and is currently a limited partner of Dorchester Minerals Management LP and member of Dorchester Minerals Management GP LLC. Mr. Raley previously served as an independent consulting engineer and as a principal in Barnes & Click, Inc., consulting engineers, since 1984. Prior to 1984, Mr. Raley was President of Dorchester Gas Producing Company and Senior Vice President of Dorchester Gas Corporation. After receiving a Bachelor of Science degree in Mechanical Engineering from Texas Tech University in 1962, Mr. Raley was employed by Skelly Oil Company in various engineering positions. Mr. Raley has been a Registered Professional Engineer in Texas since 1969.

Buford P. Berry serves as an Independent Manager of Dorchester Minerals Management GP LLC. He is currently a senior partner at Thompson & Knight L.L.P., a Texas based law firm. Mr. Berry has been an attorney with Thompson & Knight L.L.P., serving in various capacities since 1963, including as Managing Partner from 1986 to 1998. Mr. Berry also serves as a member of the Advisory Board of the Institute for Energy Law of the Center for American and International Law (formerly Southwestern Legal Foundation) and previously served as a Vice Chair of this organization. He is a past Chairman of the Natural Resources Committee of the Taxation Section of the American Bar Association and past Chairman of the Southwestern Legal Foundation Oil and Gas Tax Institute. From 1958 to 1960, Mr. Berry served as a Lieutenant in the United States Naval Reserve. He received his Bachelor of Business Administration degree in 1958 and his Bachelor of Laws Degree in 1963, both from the University of Texas.

Frank M. Burke serves as an Independent Manager of Dorchester Minerals Management GP LLC. He has served as Chairman, Chief Executive Officer and Managing General Partner of Burke, Mayborn Company Ltd, a private investment company located in Dallas Texas, since 1984. He is a member of the National Petroleum Council and also serves as a director of Arch Coal, Inc., Kaneb Pipe Line Partners, L.P., Xanser Corporation and Kaneb Services LLC. Prior to that, Mr. Burke was a partner in Peat, Marwick, Mitchell & Co. Mr. Burke received his Bachelor of Business Administration and Master of Business Administration from Texas Tech University and his Juris Doctor from Southern Methodist University. He is a certified public accountant and member of the State Bar of Texas.

Rawles Fulgham serves as an Independent Manager of Dorchester Minerals Management GP LLC. He has served as a member of the Advisory Committee and the Audit Committee of Dorchester Hugoton since 1995. He also served as Chairman of the Board and Chief Executive Officer of Global Industrial Technologies, Inc. from July 1998 until 2000. From 1982 until December 1998, Mr. Fulgham served as senior advisor of the Investment Banking Division of Merrill Lynch & Co. Prior to that, he was employed in various capacities by First National Bank in Dallas and its successor holding companies from 1954 until 1982. He was President and co-Chief Executive Officer of the First National Bank in Dallas, and subsequently, President of its successor holding companies. Mr. Fulgham has served on the boards of directors of BancTec, Inc., NCH Corporation, Dresser

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Industries, Inc and as Chairman of the Board of Directors of the Children’s Medical Center of Dallas. In addition, Mr. Fulgham also served as a member of the Executive Committee of President Reagan’s Grace Commission. He received a Bachelor of Arts degree from the Virginia Military Institute, a Bachelor of Business Administration degree from Southern Methodist University and has also completed several graduate courses for a Masters of Business Administration. Mr. Fulgham served in the United States Marine Corps, attaining the rank of captain.

Preston A. Peak serves as an Appointed Manager of Dorchester Minerals Management GP LLC. Mr. Peak is a member of Peak GP LLC, the general partner of Preston A. Peak Limited Partnership, which is the successor to P.A. Peak, Inc., which served as a general partner of Dorchester Hugoton and is currently a limited partner of Dorchester Minerals Management LP and member of Dorchester Minerals Management GP LLC. Mr. Peak co-founded Dorchester Hugoton in 1982. He holds a Bachelor of Science degree from the U.S. Naval Academy and a Master of Business Administration degree from the Wharton School of the University of Pennsylvania. From 1954 until 1984 he served Dorchester Gas Corporation in various financial capacities, including Vice Chairman. Mr. Peak previously served on the boards of directors of each of Kaneb Services, Inc. and Kaneb Pipe Line Partners, L.P.

Robert C. Vaughn serves as an Appointed Manager of Dorchester Minerals Management GP LLC. Mr. Vaughn has served in various capacities with Vaughn Petroleum, Inc., and affiliated entities since 1979, including as President and Chief Executive Officer from 1986 until 1995, and since 1995 as chairman and chief executive officer. He co-founded Vaughn Brothers Oil Company in 1981, CM/Vaughn Joint Venture in 1986, Vaughn Petroleum 1989 Joint Venture in 1989, Republic Royalty Company in 1993 and Vaughn Petroleum Royalty Partners, Ltd. in 1994. Vaughn Petroleum, Inc. is the successor to entities formed by Grady H. Vaughn in the early 1900s and was a general partner of Republic Royalty Company and is the general partner of Vaughn Petroleum Royalty Partners, Ltd. He attended the Petroleum Land Management program at The University of Texas at Austin. He currently serves on the Board of Trustees of the Culver Educational Foundation and the Development Board of The University of Texas.

Management of the Operating Subsidiary

Our general partner owns, directly and indirectly, through its general partner, all of the partnership interests in Dorchester Minerals Operating LP, and indirectly controls its management through Dorchester Minerals Operating GP LLC. Dorchester Minerals Operating LP provides day-to-day operational support and services to us and our general partner. As noted above, Messrs. McManemin, Raley and Allen also serve as executive officers of Dorchester Minerals Operating GP LLC.

Section 16(a) Beneficial Ownership and Reporting Compliance

Section 16(a) requires managers and officers of the Company, and persons who own more than 10% of the common units of the Company, to file with the SEC initial reports of ownership and reports of changes in ownership of the common units. Managers, officers and 10% holders of the common units are required by SEC regulations to furnish the Company with copies of all Section 16(a) forms they file. To the Company’s knowledge, based solely on a review of the copies of such reports furnished to the Company to date, all Section 16(a) requirements applicable to its managers, officers and 10% holders were met.

ITEM 11.     EXECUTIVE COMPENSATION

Our Partnership was formed in December 2001 but did not conduct any business until February 2003. No officer of Dorchester Minerals Management GP LLC received any cash or other compensation for services rendered to our Partnership in 2002.

All decisions regarding compensation or benefits paid by us, Dorchester Minerals Management LP, Dorchester Minerals Management GP LLC, Dorchester Minerals Operating LP or Dorchester Minerals Operating

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GP LLC to any executive officers are reviewed by the Advisory Committee of Dorchester Minerals Management GP LLC. Actions by the Advisory Committee require the approval of the majority of the committee’s members.

Our officers are not paid any compensation for their services as officers of our Partnership. Our officers, generally, serve in the same capacities for Dorchester Minerals Management GP LLC, our general partner, and for Dorchester Minerals Operating LP and may be compensated by Dorchester Minerals Operating LP for their service in those capacities. Each of Messrs. McManemin, Raley and Allen receive a salary of $96,000 per year as approved by the Advisory Committee. Such compensation will be borne indirectly by us as a result of our obligation to reimburse Dorchester Minerals Management LP and Dorchester Minerals Operating LP for management expenses, subject to the limitation on reimbursement.

We do not have nor do we anticipate implementing any option or other incentive compensation plans for the benefit of our employees and officers and those of our affiliates.

Compensation of Managers

Each Independent Manager of Dorchester Minerals Management GP LLC is paid an annual retainer fee of $30,000.

ITEM 12.     SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

AND RELATED UNITHOLDER MATTERS

Security Ownership

The following table sets forth information regarding the beneficial ownership of our common units as of March 24, 2003. The information is set forth for (i) each appointed manager of Dorchester Minerals Management GP LLC, (ii) each of the named executive officers of Dorchester Minerals Management GP LLC, (iii) all executive officers and appointed managers of Dorchester Minerals Management GP LLC as a group, and (iv) all those known by us to be beneficial owners of more than five percent of our common units.

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Equity Compensation Plans

We do not have any securities authorized for issuance under any equity compensation plans.

ITEM 13.     CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Legal Representation

Buford P. Berry is a senior partner of the law firm Thompson & Knight L.L.P., which firm serves as primary outside counsel to our Partnership.

Severance Policy

In connection with the consummation of the combination, pursuant to a February 1998 severance policy (which acted as an employee retention program), James E. Raley, Inc., a general partner of Dorchester Hugoton, received a $496,000 payment at the same time payments were made to qualifying Dorchester Hugoton employees.

ITEM 14.     CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The Company’s principal executive officer and principal financial officer, based on their evaluation of the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-14c) as of a date within 90 days prior to the filing of this Form 10-K, have concluded that the Company’s disclosure controls and procedures effectively ensure that the information required to be disclosed in the reports the Company files with the SEC is recorded, processed, summarized and reported, within the time periods specified by the SEC.

Changes in Internal Controls

There were no significant changes in the Company’s internal controls or in other factors that could significantly affect the Company’s internal controls subsequent to the date of their evaluation.

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ITEM 15.     EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

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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.

“BTU” means British thermal unit.

“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, sometime referred to as the strata, which has characteristics (such as permeability, porosity and hydrocarbon saturations) which distinguish it from surrounding intervals.

“Gross acre” means an acre 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.

“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.

“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.

“MMBTU” means one million BTUs.

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“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 nonoperating) 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.

(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.

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“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 present value” 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 present value 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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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 27, 2003

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.

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CERTIFICATIONS

I, William Casey McManemin, Chief Executive Officer of Dorchester Minerals Management GP LLC, General Partner of Dorchester Minerals Management LP, General Partner of Dorchester Minerals, L.P., (the “Registrant”), certify that:

Date:    March 27, 2003

/s/    William Casey McManemin

William Casey McManemin

Chief Executive Officer

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I, H.C. Allen, Chief Financial Officer of Dorchester Minerals Management GP LLC, General Partner of Dorchester Minerals Management LP, General Partner of Dorchester Minerals, L.P., (the “Registrant”), certify that: