As filed with the Securities and Exchange Commission on May 15, 2002
Registration No. 333-

SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM S-4
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933


Dorchester Minerals, L.P.
(Exact name of registrant as specified in its charter)

    Delaware
 (State or other
 jurisdiction of                              1311                                 Applied For
incorporation or                  (Primary Standard Industrial                  (I.R.S. Employer
  organization)                       Classification No.)                      Identification No.)

     c/o Dorchester Minerals Management GP LLC                               William Casey McManemin
              3738 Oak Lawn, Suite 300                                Dorchester Minerals Management GP LLC
                Dallas, Texas 75219                                          3738 Oak Lawn, Suite 300
                   (214) 559-0300                                              Dallas, Texas 75219
(Address, including zip code, and telephone number,                               (214) 559-0300
   including area code, of registrant's principal               (Name, address, including zip code, and telephone
                 executive offices)                             number, including area code, of agent for service)


Copies to:

Joe Dannenmaier Bryan E. Bishop
David G. Harris Locke Liddell & Sapp LLP
Thompson & Knight, L.L.P. 2200 Ross Avenue, Suite 2200
1700 Pacific Avenue, Dallas, Texas 75201
Suite 3300
Dallas, Texas 75201


Approximate date of commencement of proposed sale to the public: Upon the effective date of the Combination described in this Registration Statement.
If the securities being registered on this Form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box. [_] If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [_] If this Form is a post-effective amendment filed pursuant to Section 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [_]


CALCULATION OF REGISTRATION FEE


                                                                      Proposed       Proposed
                                                                      maximum        maximum
                                                    Amount to be   offering price   aggregate        Amount of
Title of each class of securities to be registered   registered      per share    offering price  registration fee
------------------------------------------------------------------------------------------------------------------
      Common Units of partnership interest,          27,040,431
        par value $.01 per share.................. common units(1)      N/A       $197,934,490(2)     $18,210
------------------------------------------------------------------------------------------------------------------


(1) Consists of (a) 27,040,431 common units issuable upon (i) the conversion pursuant to the Mergers of Republic and Spinnaker and (ii) the transfer by Dorchester Hugoton of certain assets.
(2) Estimated solely for the purpose of determining the registration fee pursuant to Rule 457(f), based on the average of the high and low sales prices for Dorchester Hugoton's partnership interests on the Nasdaq National Market on May 9, 2002 and on the book value of the partnership interests of Republic and Spinnaker to be received or cancelled by the Registrant.

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until this Registration Statement shall become effective on such date as the Commission, acting pursuant to such Section 8(a), may determine.



DORCHESTER HUGOTON, LTD.
1919 S. Shiloh Road, Suite 600 - LB 48
Garland, Texas 75042


NOTICE OF SPECIAL MEETING OF LIMITED PARTNERS
To be Held on , 2002


To the Limited Partners of
Dorchester Hugoton, Ltd.

Dorchester Hugoton, Ltd. will hold a special meeting of limited partners on , 2002 at a.m. (Dallas, Texas time) at , Dallas, Texas for the following purposes:

1. To consider and vote upon a proposal to adopt and approve the combination agreement, dated as of December 13, 2001, among Dorchester Hugoton, Ltd., Republic Royalty Company, L.P., Spinnaker Royalty Company, L.P., Dorchester Minerals, L.P., Dorchester Minerals Management LP and Dorchester Minerals Management GP LLC, and the transactions contemplated by it; and

2. To transact any other business that may properly be presented at the special meeting or any adjournments of the meeting.

The parties to the combination agreement will not complete the combination transaction unless Dorchester Hugoton's limited partners adopt and approve the combination agreement and the transactions contemplated by it.

Only limited partners of record as of the close of business on , 2002 are entitled to notice of and to vote at the meeting and any adjournments of the meeting.

Please complete, date, sign and promptly return your proxy card so that your partnership interests may be voted in accordance with your wishes and so that the presence of a quorum at the meeting may be assured. Giving a proxy does not affect your right to vote in person if you attend the meeting. You may revoke your proxy at any time before it is exercised at the meeting.

By Order of the General Partners,

P.A. Peak, Inc., General Partner

By: -----------------------------
Preston A. Peak,
President

James E. Raley, Inc., General Partner

By: -----------------------------
James E. Raley,
President

Dallas, Texas
, 2002


SPINNAKER ROYALTY COMPANY, L.P.
3738 Oak Lawn, Suite 300
Dallas, Texas 75219


NOTICE OF SPECIAL MEETING OF LIMITED PARTNERS
To be Held on , 2002


To the Limited Partners of
Spinnaker Royalty Company, L.P.

Spinnaker Royalty Company, L.P. will hold a special meeting of limited partners on , 2002 at a.m. (Dallas, Texas time) at , Dallas, Texas for the following purposes:

1. To consider and vote upon a proposal to adopt and approve the combination agreement, dated as of December 13, 2001, among Dorchester Hugoton, Ltd., Republic Royalty Company, L.P., Spinnaker Royalty Company, L.P., Dorchester Minerals, L.P., Dorchester Minerals Management LP and Dorchester Minerals Management GP LLC, and the transactions contemplated by it; and

2. To transact any other business that may properly be presented at the special meeting or any adjournments of the meeting.

The parties to the combination agreement will not complete the combination transaction unless Spinnaker's limited partners adopt and approve the combination agreement and the transactions contemplated by it.

Only limited partners of record as of the close of business on , 2002 are entitled to notice of and to vote at the meeting and any adjournments of the meeting.

Please complete, date, sign and promptly return your proxy card so that your partnership interests may be voted in accordance with your wishes and so that the presence of a quorum at the meeting may be assured. Giving a proxy does not affect your right to vote in person if you attend the meeting. You may revoke your proxy at any time before it is exercised at the meeting.

By Order of the General Partner,

Smith Allen Oil & Gas, Inc.

By: --------------------------------
H.C. Allen, Jr.
Secretary

Dallas, Texas
, 2002


Preliminary Draft Dated May 15, 2002, Subject to Completion

DORCHESTER MINERALS, L.P.

COMMON UNITS OF PARTNERSHIP INTEREST

Dear Limited Partners:

On December 13, 2001, Dorchester Hugoton, Ltd., Republic Royalty Company, and Spinnaker Royalty Company entered into agreements providing for the creation of a new limited partnership, Dorchester Minerals, L.P.

. The agreements also provide for the combination of the businesses and properties of each of the three combining partnerships: Dorchester Hugoton, Republic and Spinnaker.

. The general partners of the combining partnerships are sending this document to you together.

Dorchester Minerals' objective will be to distribute quarterly all cash beyond that required to pay costs and fund reasonable reserves.

Dorchester Hugoton is a publicly-traded limited partnership, and Republic and Spinnaker are privately held, each by a small number of industry or institutional investors. Except where the context otherwise requires, discussions in this document assume that the reorganization of Republic described on page 56 has occurred and references to the limited partners of the combining partnerships include the holders of Dorchester Hugoton's depositary receipts.

If the combination is completed, limited partners of the combining partnerships will receive common units of partnership interests of Dorchester Minerals, called the common units. The former limited partners of Dorchester Hugoton will receive one common unit of Dorchester Minerals for each depositary receipt of Dorchester Hugoton representing in the aggregate approximately 39.73% of the common units, while the former limited partners of Republic will receive approximately 40.51% and the former limited partners of Spinnaker will receive approximately 19.76%, in each case with respect to their limited partnership interests. For a more detailed description of the combination exchange ratios and how they were computed, see "Background and Reasons for the Combination--Combination Exchange Ratios and Consideration Allocated to General Partner Interests" beginning on page 42.

The combination is expected to be tax-free to Dorchester Minerals and the owners of the combining partnerships, including limited partners, except those who elect to exercise dissenters' rights and except for certain distributions of cash to limited partners.

The combination will not occur unless the limited partners of each of the combining partnerships approve the combination. Special meetings of the Dorchester Hugoton and Spinnaker partners will be held to consider and vote upon the proposal to adopt the combination, and Republic partners are being asked to execute a written consent in lieu of meeting, in each case specified in the applicable accompanying notice.

Prior to this transaction there has been no public market for Dorchester Minerals common units. Dorchester Minerals will apply to have the common units listed on the Nasdaq National Market System under the symbol "DMLP."

Your vote is important. Whether or not you plan to attend the applicable special meeting, please take the time to vote by completing and mailing to us your enclosed proxy card or consent card, as applicable. This will not prevent you from revoking your proxy or consent card, as applicable, at any time prior to the special meeting or from voting your partnership interest in person if you later choose to attend the special meeting.

Sincerely,

P.A. Peak, Inc.           SAM Partners, Ltd.
James E. Raley, Inc.      Vaughn Petroleum, Ltd.
General Partners of       General Partners of
Dorchester Hugoton        Republic

Smith Allen Oil & Gas, Inc. General Partner of
Spinnaker

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this document or the accompanying supplement is truthful or complete. Any representation to the contrary is a criminal offense.

The combination involves various risks described in "Summary--Risk Factors" on page 11 and "Risk Factors" beginning on page 14. These risks include among others:

. The combination exchange ratios for each combining partnership were negotiated based in part upon reserve estimates that may vary significantly from the quantities of oil and natural gas actually recovered by that partnership, and consequently future net revenues may be materially different from the estimates used in the negotiation of the combination exchange ratio for a particular partnership.

. The combination exchange ratio for a combining partnership will not be adjusted for changes in oil and natural gas prices between the date the ratios were established and the completion of the combination.

. No appraisals or valuations, other than the reserve reports, have been done for any of the combining partnerships.

. You were not independently represented in establishing the terms of the combination.

. The consideration limited and general partners receive and the terms of the combination were determined by the general partners of the combining partnerships, which have inherent conflicts of interest.

The date of this document is , 2002.


WHERE YOU CAN FIND MORE INFORMATION

Dorchester Hugoton files annual, quarterly and special reports, proxy statements and other information with the Securities and Exchange Commission. You may read and copy any reports or other information that Dorchester Hugoton files at the SEC's public reference room at 450 Fifth Street, N.W., Washington, D.C. 20549. Copies of these materials may also be obtained from the SEC for a fee by writing to the Public Reference Section of the Securities and Exchange Commission, 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room. Dorchester Hugoton's filings with the SEC are also available to the public from commercial document retrieval services and at the web site maintained by the SEC at www.sec.gov.

Dorchester Hugoton's depositary receipts are quoted on the Nasdaq National Market System under the symbol "DHULZ." Dorchester Hugoton's reports and other information filed with the SEC can also be inspected at the offices of the NASD or at www.nasdaq.com.

We have filed a registration statement on Form S-4 to register with the SEC our common units to be issued to the limited partners of the combining partnerships. This document is part of that registration statement and constitutes the prospectus of our partnership in addition to being the proxy statement of Dorchester Hugoton and Spinnaker and the consent solicitation of Republic. As allowed by SEC rules, this document does not contain all the information you can find in the registration statement or the exhibits to the registration statement.

The SEC allows Dorchester Hugoton to incorporate by reference information into this document, which means that Dorchester Hugoton can disclose important information to you by referring you to another document filed separately with the SEC. The information incorporated by reference is deemed to be a part of this document, except for any information superseded by information in this document. This document incorporates by reference the document sets forth below that Dorchester Hugoton has previously filed with the SEC and that contain important information about Dorchester Hugoton and its finances:

. Annual Report on Form 10-K for the year ended December 31, 2001.

Dorchester Hugoton is also incorporating by reference additional documents that it files with the SEC under sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934 between the date of this document and the date of the special meeting or the date the consent card must be returned by, as applicable, for each partnership.

The supplement to this document for each combining partnership contains important information about each partnership. The supplement for each combining partnership constitutes an integral part of this document. Please carefully read the supplement for each combining partnership in which you are a limited partner.

Dorchester Hugoton has supplied all information contained or incorporated by reference in this document relating to Dorchester Hugoton, and our partnership, Republic and Spinnaker have supplied all the information contained in this document relating to them.

You can obtain any of the documents incorporated by reference from Dorchester Hugoton or the SEC. Documents incorporated by reference are available from Dorchester Hugoton without charge upon oral or written request to Dorchester Hugoton, Ltd., 1919 S. Shiloh Road, Suite 600-LB 48, Garland, Texas 75042, telephone (972) 864-8610, Attention: James E. Raley. Exhibits to documents will not be sent, however, unless those exhibits have specifically been incorporated by reference as exhibits in this document.

If you would like to request information from us or a combining partnership in which you own an interest, please do so by , 2002 so that you may receive them before the applicable special meeting or the date you must return the written consent by, as applicable. If you request any incorporated documents, we or the applicable combining partnership will mail them to you by first class mail or other equally prompt means as soon as practicable after we or the applicable combining partnership receives your request.

You should rely on the information contained or incorporated by reference in this document to vote on the participation in the combination of each combining partnership in which you own an interest. We have not


authorized anyone to give any information that is different from what is contained in this document. This document is dated , 2002. You should not assume that the information contained in this document is accurate as of any date other than that date, and neither the mailing of this document to you nor the issuance of our common units creates an implication to the contrary.

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TABLE OF CONTENTS

QUESTIONS AND ANSWERS ABOUT THE COMBINATION.............................................  1
SUMMARY.................................................................................  4
   The Parties..........................................................................  4
   The Combination......................................................................  5
   Business After Completion of the Combination.........................................  6
   Structure and Management of the Combining Partnerships Prior to the Combination......  6
   Structure and Management of Dorchester Minerals After the Combination................  6
   Recommendations of the Combination...................................................  9
   Methods of Determining Combination Exchange Ratios................................... 10
   Risk Factors......................................................................... 11
   Combination Agreement................................................................ 11
   Partner Vote Required to Approve the Combination..................................... 12
   Comparison of Rights of Partners..................................................... 12
   Resales of Common Units.............................................................. 12
   Other Information.................................................................... 12
   Comparative per Unit Market Price Information........................................ 13
   Certain Pro Forma Financial Data..................................................... 13
RISK FACTORS............................................................................ 14
   Risks Related to Our Business........................................................ 14
   Risks Related to the Combination..................................................... 20
   Risks Inherent In An Investment In Our Common Units.................................. 24
   Tax Risks............................................................................ 28
BACKGROUND AND REASONS FOR THE COMBINATION.............................................. 33
   Background of the Combination........................................................ 33
   Combination Exchange Ratios and Consideration Allocated to General Partner Interests. 42
   Reasons for the Combination.......................................................... 44
   Reasons for Structure Adopted for the Combination.................................... 52
THE COMBINATION......................................................................... 52
   Overview of the Combination.......................................................... 52
   Preparatory Steps.................................................................... 53
   Transfer of Assets by Dorchester Hugoton and Liquidation............................. 57
   Merger of Republic with Dorchester Minerals.......................................... 59
   Merger of Spinnaker with Dorchester Minerals......................................... 59
   Contributions to Dorchester Minerals Management LP................................... 60
   Ownership Structure of Dorchester Minerals........................................... 60
THE COMBINATION AGREEMENT............................................................... 60
   Effective Time of the Combination.................................................... 61
   Conditions........................................................................... 61
   Representations and Warranties....................................................... 62
   Certain Covenants.................................................................... 63
   Acquisition Proposals................................................................ 63
   Termination.......................................................................... 64
   Termination Fee...................................................................... 65
   Amendments........................................................................... 66
   Issuance of Units; Fractional Units.................................................. 66
   Dissenters' Rights................................................................... 68
   Nasdaq Listing....................................................................... 69
   Interests of Certain Persons in the Combination...................................... 69
   Resales of Common Units.............................................................. 69

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   Accounting Treatment.....................................................................  69
   Expenses and Fees........................................................................  70
   Additional Agreements....................................................................  71
FAILURE TO APPROVE THE COMBINATION..........................................................  71
SPECIAL MEETINGS OF THE COMBINING PARTNERSHIPS AND CONSENT SOLICITATION
  MATTERS...................................................................................  72
   General..................................................................................  72
   Voting Rights............................................................................  72
   Proxy Forms and Revocation of Proxies (applies to Dorchester Hugoton and Spinnaker only).  72
   Action by Written Consent (applies to Republic only).....................................  73
   Solicitation.............................................................................  73
   Voting Requirements......................................................................  74
   Procedures for Exercise of Dissenters' Rights of Appraisal...............................  74
   Access to Investor List/Rights of Inspection.............................................  74
MATERIAL UNITED STATES FEDERAL INCOME TAX CONSEQUENCES......................................  74
   In General...............................................................................  74
   Consequences of Pre-Combination Transactions.............................................  76
   Consequences of the Combination..........................................................  77
   Consequences of Ownership of Our Common Units After the Combination......................  80
BUSINESS OF DORCHESTER MINERALS AFTER COMPLETION OF THE COMBINATION.........................  94
   General..................................................................................  94
   Properties...............................................................................  95
   Oil and Natural Gas Reserves.............................................................  97
   Capitalization...........................................................................  98
   Credit Facilities and Financing Plans....................................................  98
   Regulation...............................................................................  98
   Competition..............................................................................  99
   Operating Hazards and Uninsured Risks....................................................  99
   Legal Proceedings........................................................................ 100
   Facilities............................................................................... 100
   Employees................................................................................ 100
   Quantitative and Qualitative Disclosures About Market Risk............................... 100
INFORMATION CONCERNING DORCHESTER HUGOTON................................................... 102
   General.................................................................................. 102
   Properties and Operations................................................................ 102
   Acreage.................................................................................. 104
   Costs Incurred and Drilling Results...................................................... 104
   Productive Well Summary.................................................................. 105
   Natural Gas Reserves..................................................................... 105
   Other Properties......................................................................... 105
   Selected Financial and Operating Data.................................................... 106
   Management's Discussion and Analysis of Financial Condition and Results of Operations.... 106
   Changes in and Disagreements with Accountants............................................ 109
   Regulation............................................................................... 110
   Customers and Pricing.................................................................... 111
   Competition.............................................................................. 112
   Environmental Laws and Regulations....................................................... 112
   Tax Returns.............................................................................. 112
   Legal Proceedings........................................................................ 112
   Security Ownership....................................................................... 113
   Principal Holders........................................................................ 114
   Other Information........................................................................ 114

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INFORMATION CONCERNING REPUBLIC................................................................... 115
   General........................................................................................ 115
   Description of the Republic Properties......................................................... 116
   Oil and Natural Gas Reserves................................................................... 118
   Contribution and Distribution Information...................................................... 121
   Selected Historical Combined Financial and Operating Information............................... 121
   Management's Discussion and Analysis of Combined Financial Condition and Results of Operations. 121
   Changes in and Disagreements with Accountants.................................................. 125
   Regulation..................................................................................... 125
   Competition.................................................................................... 126
   Environmental Laws and Regulations............................................................. 126
   Legal Proceedings.............................................................................. 126
   Security Ownership............................................................................. 127
INFORMATION CONCERNING SPINNAKER.................................................................. 128
   General........................................................................................ 128
   Description of the Spinnaker Properties........................................................ 129
   Oil and Natural Gas Reserves................................................................... 130
   Contribution and Distribution Information...................................................... 133
   Selected Historical Financial and Operating Information........................................ 133
   Management's Discussion and Analysis of Financial Condition and Results of Operations.......... 134
   Changes in and Disagreements with Accountants.................................................. 137
   Regulation..................................................................................... 137
   Competition.................................................................................... 137
   Environmental Laws and Regulations............................................................. 137
   Security Ownership............................................................................. 138
MANAGEMENT........................................................................................ 139
   The General Partner............................................................................ 139
   Absence of Management Fees; Reimbursement of General Partner................................... 139
   Ownership Structure of the General Partner and its General Partner............................. 140
   Management of the General Partner.............................................................. 141
   The Operating Subsidiary....................................................................... 144
   Conflicts of Interest.......................................................................... 145
   Officers of Dorchester Minerals................................................................ 145
   Executive Compensation......................................................................... 145
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES........................................................ 146
   General........................................................................................ 146
   Fiduciary Duties Owed to Our Unitholders....................................................... 148
   Interest of Certain Persons in the Combination................................................. 150
THE BUSINESS OPPORTUNITIES AGREEMENT.............................................................. 155
   Renunciation of Business Opportunities......................................................... 155
   Contractual Obligations of Certain Affiliates.................................................. 156
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.................................... 158
THE PARTNERSHIP AGREEMENT......................................................................... 159
   Organization................................................................................... 159
   Purpose........................................................................................ 159
   Power of Attorney.............................................................................. 159
   Capital Contributions.......................................................................... 160
   Limited Liability.............................................................................. 160
   Issuance of Additional Securities.............................................................. 160
   Distributions of Available Cash................................................................ 161

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   Amendment of the Partnership Agreement.............................  161
   Merger, Sale or Disposition of Assets..............................  163
   Termination and Dissolution........................................  163
   Liquidation and Distribution of Proceeds...........................  163
   Withdrawal or Removal of the General Partner.......................  164
   Transfer of General Partner Interest...............................  165
   Change of Management Provisions....................................  165
   Members; Voting....................................................  165
   Status of Limited Partner or Assignee..............................  166
   Non-Citizen Assignees; Redemption..................................  166
   Indemnification....................................................  167
   Books and Reports..................................................  167
   Right to Inspect Books and Records.................................  167
   Registration Rights................................................  168
COMPARISON OF RIGHTS OF PARTNERS......................................  168
DESCRIPTION OF COMMON UNITS OF DORCHESTER MINERALS....................  178
   General............................................................  178
   Transfer Agent and Registrar.......................................  178
   Transfer of Common Units...........................................  178
LEGAL MATTERS.........................................................  179
EXPERTS...............................................................  180
FORWARD LOOKING STATEMENTS............................................  180
GLOSSARY OF CERTAIN OIL AND GAS TERMS.................................  181
UNAUDITED PRO FORMA FINANCIAL INFORMATION.............................  P-1
INDEX TO FINANCIAL STATEMENTS.........................................  F-1
LIST OF APPENDICES....................................................
FAIRNESS OPINION OF BRUCE E. LAZIER, P.E., dated July 30, 2001........ A1-1
FAIRNESS OPINION OF BRUCE E. LAZIER, P.E., dated December 13, 2001.... A2-1
SUMMARY RESERVE REPORT OF CALHOUN, BLAIR & ASSOCIATES FOR DORCHESTER
  HUGOTON, LTD., as of December 31, 2001, 2000 and 1999...............  B-1
SUMMARY RESERVE REPORT HUDDLESTON & CO, INC. FOR REPUBLIC ROYALTY
  COMPANY, as of January 1, 2002, 2001 and 2000.......................  C-1
SUMMARY RESERVE REPORT OF HUDDLESTON & CO., INC. FOR SPINNAKER ROYALTY
  COMPANY, L.P. as of January 1, 2002, 2001 and 2000..................  D-1
FORM OF PROXY FOR DORCHESTER HUGOTON AND SPINNAKER....................  E-1
FORM OF CONSENT FOR REPUBLIC..........................................  F-1

iv

QUESTIONS AND ANSWERS ABOUT THE COMBINATION

Q: What are the general partners of the combining partnerships proposing?

A: The general partners of the combining partnerships are proposing the combination of the businesses and properties of Dorchester Hugoton, Republic and Spinnaker into a new publicly traded limited partnership. Discussions in this document assume that the reorganization of Republic described beginning on page 56 has occurred, except where the context otherwise requires.

Q: Why is the combination being proposed?

A: The general partners of the combining partnerships believe that the combination is in the best interests of the limited partners of the combining partnerships. After the completion of the combination, limited partners should benefit from:

. a larger and more diversified asset base;

. improved capital efficiencies; and

. the opportunity for future growth from both undeveloped property and from acquisitions.

See the discussion beginning on page 33 for a more complete discussion of the reasons for the combination.

Q: What will I receive as a result of the combination?

A: Limited partners will receive our common units based on set combination exchange ratios, in proportion to their limited partnership interest compared to the total limited partnership interests in that combining partnership. The number of common units to be issued by us to Dorchester Hugoton in exchange for its assets has been determined so that Dorchester Hugoton depositary receipt holders will receive one common unit for each depositary receipt of Dorchester Hugoton.

Q: What will happen to the cash on hand in Dorchester Hugoton when the combination occurs?

A: Prior to the combination, Dorchester Hugoton will sell its Exxon Mobil Corporation stock. These proceeds and any other cash on hand, but net of amounts used to fund its (i) combination costs, (ii) payments to its depositary receipt holders who dissent, if any, and (iii) severance payments and other accrued expenses, will remain in Dorchester Hugoton immediately following its transfer of assets to Dorchester Minerals. Dorchester Hugoton will then liquidate, and this remaining cash will be distributed to Dorchester Hugoton's depositary receipt holders and general partners. See the discussion beginning on page 58 for a more complete description of the liquidation of Dorchester Hugoton.

Q: When and where are the meetings of limited partners?

A: The special meeting of Dorchester Hugoton depositary receipt holders will be held on , 2002, at a.m. at , Dallas, Texas. The special meeting of Spinnaker limited partners will be held on , 2002, at a.m. at , Dallas, Texas. No meeting of Republic partners will be held, but Republic partners are being asked to execute and return the enclosed consent card in order to vote for the combination.

Q: What do I need to do now?

A: After reading this document, please fill out and sign your proxy card (or consent card, as applicable), then mail your signed proxy card (or consent card, as applicable) in the enclosed return envelope as soon as possible. Your interests will be voted at the applicable special meeting in accordance with your instructions.

Q: What does my general partner recommend I do?

A: The general partner(s) of your partnership recommends that you vote "FOR" adoption and approval of the Combination Agreement and the transactions contemplated by it. The general partner(s) of your partnership has agreed to vote all of its partnership interests in favor of the combination.

1

Q: What happens if I do not return a proxy card or consent card?

A: The failure to return your proxy card or consent card will have the same effect as voting against the combination for each partnership in which you own an interest.

Q: May I vote in person?

A: Yes, in the case of Dorchester Hugoton and Spinnaker. You may attend the applicable special meeting for each partnership in which you own an interest and vote your partnership interests in person, rather than signing and mailing your proxy card. No meeting will be held for Republic.

Q: Can Dorchester Hugoton and Spinnaker limited partners change their vote after they have mailed their signed proxy card?

A: Yes. You may revoke your vote at any time before your proxy is voted at the special meeting for each partnership in which you own an interest by following the instructions on page 73 . You then may either change your vote by sending in a new proxy card or by attending the special meeting for each partnership in which you own an interest and voting in person.

Q: Can Republic limited partners revoke their approval once the consent card is mailed?

A: Yes. Any Republic limited partner can revoke his or her consent, or any withholding of consent, at any time prior to the requisite Republic limited partner approval of the combination. Republic limited partner approval of the combination will occur as soon as consents representing the requisite Republic limited partner approvals are delivered to Republic, but no sooner than 60 calendar days after the date this document is mailed to Republic limited partners.

You can revoke your consent by following the instructions on page 73. You may then change your vote by sending in a new consent card.

Q: If my Dorchester Hugoton depositary receipts are held in "street name," will my broker vote my depositary receipts for me?

A: No. You must instruct your broker how to vote your interests or else your broker will not vote your interests.

Q: Should I send in my certificates for my partnership interest now?

A: No. If the mergers of Republic and Spinnaker are completed, your certificates representing your partnership interests in those partnerships, if any, will be cancelled without further action by you. We will mail certificates representing our common units issued to you on completion of the merger of that partnership. Depositary receipt holders of Dorchester Hugoton will receive a letter of transmittal and instructions to use in getting certificates representing our common units and the limited partner's proportionate share of the liquidating distribution of Dorchester Hugoton. Limited partners of all combining partnerships will receive a transfer application, which you must complete and deliver in order to be admitted as a limited partner of Dorchester Minerals.

Q: What are the tax consequences of the combination?

A: For federal income tax purposes, the combination will be treated as a transfer of the assets and liabilities of each combining partnership to Dorchester Minerals in exchange for common units, followed by the distribution of the common units to the partners of the combining partnerships, and should be tax free to you, unless you elect to exercise dissenters' rights, if available. However, part or all of any cash

2

distributions by a combining partnership could be taxable to you if the distribution exceeds your tax basis in your partnership interest. You should consult your tax advisor concerning federal and other tax consequences of the combination. See "Material United States Federal Income Tax Consequences" for a more complete discussion of the tax consequences of the combination.

Q: Am I entitled to dissenters' rights of appraisal?

A: Limited partners of Dorchester Hugoton and Spinnaker may, subject to the conditions provided in the Combination Agreement elect to receive, in lieu of a final cash distribution and common units, cash in an amount determined by an independent appraisal conducted at the direction of Dorchester Minerals or Dorchester Hugoton or Spinnaker, as applicable. The combination requires 100% approval by the Republic limited partners, so there will not be Republic dissenters if the combination occurs. See page 68 for a more complete discussion of the dissenters' process.

Q: What happens to my future cash distributions?

A: Since your partnership interests in the combining partnerships will be cancelled upon completion of the combination, you will not receive any future distributions on those interests. Dorchester Minerals contemplates making quarterly cash distributions following the completion of the combination. See page 161 for a more complete discussion of cash distributions Dorchester Minerals will make following the completion of the combination.

Q: Who can help answer my questions?

A: If you have any questions about the combination, please call Dorchester Minerals' information agent, D. F. King & Co. at [phone number to be assigned].

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SUMMARY

This summary highlights selected information in this document. To understand the combination and the related transactions and to obtain a more detailed description of the legal terms, you should carefully read this entire document, the related partnership supplements, and the documents described in "Where You Can Find More Information" on the inside front cover page of this document. For definitions of oil and natural gas terms used in this document, see "Glossary of Certain Oil and Natural Gas Terms" beginning on page 181.

In the remainder of this document, when we use the term "Dorchester Minerals," "our partnership," "we," "us," or "our," we are referring to Dorchester Minerals, L.P. as if the transactions contemplated by the combination agreement had already occurred. Except where the context otherwise requires, references to the limited partners of the combining partnerships include the depositary receipt holders of Dorchester Hugoton.

The Parties

Dorchester Minerals, L.P.
3738 Oak Lawn Avenue, Suite 300
Dallas, Texas 75219
(214) 559-0300

We are a Delaware limited partnership formed in connection with the combination. We prepared this document to offer our common units to you. If your partnership approves the combination, you will receive our common units.

Our general partner is Dorchester Minerals Management LP.

Dorchester Hugoton, Ltd.
1919 S. Shiloh Road, Suite 600-LB 48
Garland, Texas 75042
(972) 864-8610

Dorchester Hugoton is a publicly traded limited partnership that owns, produces, gathers and sells natural gas almost exclusively from wells in the Hugoton gas field in western Oklahoma and Kansas. Sales are currently made primarily to two customers under short-term contracts that provide for prices based on the field market price.

Dorchester Hugoton's principal operating assets consist of working interests and support facilities for properties that produce natural gas from the Hugoton field. Most of Dorchester Hugoton's current working interest wells were drilled and have been producing since prior to 1954. Dorchester Hugoton has operated most of its properties since July 1, 1984. Dorchester Hugoton owns total proved developed producing reserves of 48,302 MMcf of natural gas as of December 31, 2001 with SEC PV-10 present value of $44,726,000.

Depositary receipts for units of Dorchester Hugoton limited partnership interest are traded on the Nasdaq National Market System under the symbol "DHULZ." Dorchester Hugoton files annual, quarterly and special reports and other information with the Securities and Exchange Commission. You may obtain these SEC filings from the SEC to read and copy. See "Where You Can Find More Information" on the inside front cover of this document.

The general partners of Dorchester Hugoton are P. A. Peak, Inc. and James E. Raley, Inc.

See "Information Concerning Dorchester Hugoton" beginning on page 102 of this document for more information on Dorchester Hugoton.

Republic Royalty Company, L.P.
3738 Oak Lawn Avenue, Suite 300
Dallas, Texas 75219
(214) 559-0300

Republic was formed in 1993 as a Texas general partnership to acquire oil and natural gas properties from multiple sellers. Republic's properties consist primarily of producing and non-producing royalty and mineral interests located in 392 counties and parishes in 23 states. Republic funded the acquisition of its properties with the proceeds of the sale of overriding royalty interests, which we refer to as the Republic ORRIs. The Republic ORRIs receive a portion of all net proceeds from all of Republic's properties. However, immediately prior to or

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simultaneous with the combination, Republic will complete a reorganization in which:

. Republic will convert from a general partnership to a limited partnership; and

. the owners of the Republic ORRIs burdening Republic's properties will contribute their Republic ORRIs to Republic in exchange for limited partnership interests in Republic.

Republic is privately held. As a result of the Republic reorganization, Republic's partnership interests will be held by two general partners and a total of 11 limited partners, each of whom are industry or institutional investors.

Republic's business objective prior to the reorganization is to receive payment of oil and natural gas production revenue, lease bonus and all other sources of income and to pay all of its expenses. Republic determines the payments under the Republic ORRIs and distributes that amount to the Republic ORRI owners monthly.

Republic owns total proved reserves of 3,401,083 Bbl of oil and 20,154 MMcf of natural gas, as of December 31, 2001 with SEC PV-10 present value of $50,090,627.

SAM Partners, Ltd. and Vaughn Petroleum, Ltd. are currently the general partners of Republic.

See "Information Concerning Republic" beginning on page 115 of this document for more information on Republic.

Spinnaker Royalty Company, L.P.
3738 Oak Lawn Avenue, Suite 300
Dallas, Texas 75219
(214) 559-0300

Spinnaker was formed in 1996 as a Texas general partnership to purchase oil and natural gas properties. Proceeds from a private offering were used to capitalize Spinnaker upon its formation, to fund the acquisition of the properties and for general partnership business purposes. Spinnaker was reorganized as a Texas limited partnership in August 1997 in connection with the acquisition of properties from SASI Minerals Company.

Spinnaker is privately held. As of January 1, 2002, Spinnaker's partnership interests are held by one general partner and a total of 15 limited partners, each of whom are industry or institutional investors.

Spinnaker's properties consist primarily of producing and non-producing royalty and mineral interests located in 353 counties and parishes in 21 states.

Spinnaker owns total proved reserves equivalent to 973,680 Bbl of oil and 14,537 MMcf of natural gas, as of December 31, 2001 with SEC PV-10 present value of $26,826,911.

Smith Allen Oil & Gas, Inc. is currently the general partner of Spinnaker.

See "Information Concerning Spinnaker" beginning on page 128 of this document for more information on Spinnaker

The Combination

The combination involves the following steps:

. Creation of ORRIs. Dorchester Hugoton will transfer all of its oil and natural gas properties to Dorchester Minerals Operating LP, in exchange for retention of 96.97% net profits overriding royalty interests in the properties conveyed, referred to as the Dorchester Hugoton ORRIs. On or about the closing of the combination, each of Republic and Spinnaker will convey minor working interest properties to Dorchester Minerals Operating LP (an affiliate of our general partner), in exchange for 96.97% net profits overriding royalty interests in those properties on substantially similar terms. We refer to the Dorchester Hugoton ORRIs and the overriding royalty interests received by Republic and Spinnaker as the Operating ORRIs.

. Asset Sale and Liquidation, and Mergers. Immediately following, or simultaneously with, the creation of the Operating ORRIs described above the following will occur:

Dorchester Hugoton will transfer all of its remaining operating assets to either us or

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Dorchester Minerals Operating LP and then liquidate, distributing to its partners remaining cash and our common units. The transfers will be made as follows:

* to Dorchester Minerals Operating LP, its management and remaining operating assets, in exchange for a promissory note and the assumption of certain obligations; and

* to us, the Dorchester Hugoton ORRIs created as described above, certain other non-cash assets and cash to fund certain obligations, all in exchange for our common units and the assumption of Dorchester Hugoton's remaining obligations.

Republic, after completing an internal reorganization, will merge into our partnership, with the Republic limited partners receiving our common units and the Republic general partners receiving general partner interests.

Spinnaker, after completing an internal reorganization, will merge into our partnership, with the Spinnaker limited partners receiving our common units and the Spinnaker general partner receiving general partner interests

As a result of the combination, our common units will initially be held in approximately the following proportions:

. 40.51% by former limited partners of Republic;

. 39.73% by former limited partners of Dorchester Hugoton; and

. 19.76% by former limited partners of Spinnaker.

Business After Completion of the Combination

If the combination is consummated, our business plan is to own and hold the Operating ORRIs and the properties acquired from Republic and Spinnaker, which will generally consist of producing and non-producing mineral, royalty, overriding royalty, net profits and leasehold interests and which we refer to as the royalty properties. We will distribute on a quarterly basis all cash that we receive from the ownership of those interests 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. One of our objectives will be to avoid unrelated business taxable income for federal income tax purposes.

We may acquire oil and natural gas properties in the future after the combination, but under our Partnership Agreement our ability to do so for consideration other than our limited partnership interests will be limited, unless we obtain majority approval of our common unit holders. See "The Partnership Agreement--Issuance of Additional Securities."

On a pro forma basis as of December 31, 2001, our proved reserves consisted of 81,530,409 Mcf of natural gas and 4,374,768 Bbl of oil, with SEC PV-10 present value of $120,288,700.

Structure and Management of the Combining Partnerships Prior to the Combination

The chart on page 7 illustrates the ownership structure of the combining partnerships prior to the combination.

Structure and Management of Dorchester Minerals After the Combination

The chart on page 8 illustrates our ownership structure, as well as that of our general partner and the entity that will own overriding royalty interests burdening certain of our properties.

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[FLOW CHART]

Structure Prior to the Combination flow chart.

7

[FLOW CHART]

Structure After the Combination flow chart.

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Our General Partner (see the discussion beginning on page 139)

Following the combination, our general partner will own a general partner interest in us that will entitle it to:

. a 1% partnership interest and sharing percentage in each of the Operating ORRIs conveyed to us in connection with the combination, and in any similar overriding royalty interests created in the future; and

. 4% partnership interest and sharing percentage in all of our other assets, properties, obligations and liabilities and all our other items of revenue, cost and expense.

Our general partner will not receive any management fee or compensation in connection with its management of our business, but will be reimbursed for direct and indirect expenses incurred on our behalf, subject to certain limitations. See "Management--Absences of Management Fees; Reimbursement of General Partner" for a description of the reimbursement of expenses.

The executive officers of Dorchester Minerals Management LP are: William Casey McManemin, Chief Executive Officer; James E. Raley, Chief Operating Officer; and H.C. Allen, Jr., Chief Financial Officer.

Dorchester Minerals Management GP LLC (see the discussion beginning on page 141)

Dorchester Minerals Management GP LLC, a Delaware limited liability company, is the general partner of our general partner and is owned by the five current general partners of the combining partnerships. A Board of Managers consisting of five managers appointed by its members, and at least three independent managers, will govern Dorchester Minerals Management GP LLC. Certain governance matters will be handled through committees of managers.

Each member of Dorchester Minerals Management GP LLC has the power to appoint one manager. The initial appointed managers will be:

. H.C. Allen, Jr., appointed by SAM Partners, Ltd.;

. Robert C. Vaughn, appointed by Vaughn Petroleum, Ltd.;

. William Casey McManemin, appointed by Smith Allen Oil & Gas, Inc.;

. Preston A. Peak, appointed by P.A. Peak Holdings LP; and

. James E. Raley, appointed by James E. Raley General Partnership.

By virtue of the ownership structure of our partnership, Dorchester Minerals Management LP and Dorchester Minerals Management GP LLC, the Board of Managers of Dorchester Minerals Management GP LLC will exercise the effective control of our partnership.

The executive officers of Dorchester Minerals Management GP LLC are: William Casey McManemin, Chief Executive Officer; James E. Raley, Chief Operating Officer; and H.C. Allen, Jr., Chief Financial Officer.

Dorchester Minerals Operating LP (see the discussion beginning on page 144)

Our general partner owns, directly or indirectly, 100% of Dorchester Minerals Operating LP, and its general partner, Dorchester Minerals Operating GP LLC. After the consummation of the combination, Dorchester Minerals Operating LP will hold the working interests and most of the other operational assets now owned by Dorchester Hugoton, Republic and Spinnaker and will also provide day-to-day operational support and services to us and to our general partner, such as accounting, land and tax services. Actual and reasonable costs incurred by Dorchester Minerals Operating LP in performing the services will be reimbursed by us, subject to certain limitations with respect to those matters outside the scope of the Operating ORRIs.

The executive officers of Dorchester Minerals Operating LP are: William Casey McManemin, Chief Executive Officer; James E. Raley, Chief Operating Officer; H.C. Allen, Jr., Chief Financial Officer; and Kathleen A. Rawlings, Controller.

Recommendations of the Combination

Background and Reasons for the Combination

Prior to their introduction, the general partners of each of the combining partnerships were each actively exploring various strategic alternatives available to their partnerships. Among the common objectives of the general partners was the objective to

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pursue a transaction that could be accomplished without triggering a taxable event and would result in the limited partners of the combining partnerships holding publicly traded securities in a partnership or a similar flow-through entity for tax purposes. Although each of the combining partnerships engaged in discussions with other potential strategic transaction participants, the general partners of each of the combining partnerships have concluded that the combination will best serve the interests of their respective partnerships and limited partners.

Alternatives to the Combination

The general partners of each of the combining partnerships have considered various alternatives to the combination, including the continued operation of each of their partnerships under their existing business plans. The general partners of the combining partnerships also considered various transaction structures which could be accomplished on a non-taxable basis, as well as certain structures that would trigger a taxable event for their partners, including transactions involving cash consideration.

See "Background and Reasons for the Combination--Background of the Combination" beginning on page 33 for a more detailed description of the alternatives to the combination considered by the general partners of each of the combining partnerships.

Fairness of the Combination

The general partners of each of the combining partnerships have both approved the combination and believe that the combination is fair and in the best interests of the applicable combining partnership and its limited partners. The general partners of the combining partnerships considered various factors in determining that the combination is fair to their partnerships and limited partners. Some of the factors that are common to all of the general partners of the combining partnerships include:

. a larger and more diversified asset base;

. improved capital efficiencies; and

. the opportunity for future growth from both unleased, undeveloped property and from acquisitions.

See "Background and Reasons of the Combination--Reasons for the Combination" beginning on page 44 for a more detailed discussion other factors considered by the general partners of the combining partnerships.

The general partners of Dorchester Hugoton and its Advisory Committee also considered the fairness opinion from Bruce E. Lazier, P.E.

As described below under the heading "Methods of Determining Combination Exchange Ratios," the combination exchange ratios were determined as the result of arm's-length negotiations considering multiple factors.

Fairness Opinion of Financial Advisor

Bruce E. Lazier, P.E. has issued a fairness opinion dated December 13, 2001, updating an earlier opinion dated July 30, 2001, that, subject to the qualifications expressed in the opinion, the combination is fair from a financial point of view to Dorchester Hugoton and its depositary receipt holders. The full text of the written opinions of Lazier are attached as Appendix A-1 and A-2 to this document. Neither Republic nor Spinnaker has received a fairness opinion in connection with the combination.

Methods of Determining Combination Exchange Ratios

The general partners of the combining partnerships have agreed in the Combination Agreement to the manner in which interests in our partnership will be allocated to the partners of the combining partnerships. These agreements were reached as the result of arm's-length negotiations.

During those negotiations, the parties did not assign a value to each combining partnership or to categories of their assets, but considered multiple factors, which are described in more detail under "Background and Reasons for the Combination--Background of the Combination." As described in more detail in "Background and Reasons for the Combination--Combination Exchange Ratios and Consideration Allocated to General Partner Interests" on page 42, our common units will initially be held in approximately the following proportions as a result of the combination:

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. 40.51% by former limited partners of Republic;

. 39.73% by former limited partners of Dorchester Hugoton; and 19.76% by former limited partners of Spinnaker.

Our common units will initially be held in approximately the following amounts as a result of the combination, based on 27,040,431 common units to be issued in the combination:

. 10,953,078, by the former limited partners of Republic;

. 10,744,380, by the former limited partners of Dorchester Hugoton; and

. 5,342,973, by the former limited partners of Spinnaker.

Risk Factors

You should carefully consider the risks associated with the combination described in "Risk Factors" beginning at page 14 of this document. These include:

. The combination exchange ratios for each combining partnership were negotiated based in part upon reserve estimates that may vary significantly from the quantities of oil and natural gas actually recovered by that partnership, and consequently future net revenues may be materially different from the estimates used in the negotiation of the combination exchange ratio for a particular partnership.

. The combination exchange ratio for a combining partnership will not be adjusted for changes in oil and natural gas prices before the completion of the combination.

. No appraisals or valuations, other than the reserve reports, have been done for any of the combining partnerships.

. You were not independently represented in establishing the terms of the combination.

. The consideration limited and general partners receive and the terms of the combination were determined by the general partners of the combining partnerships, which have inherent conflicts of interest.

. Cash distribution policies will be dependent on oil and natural gas prices which have historically been very volatile.

. Our partnership will not control operations or development.

. There has been no prior market for our common units.

Combination Agreement

We have entered into a Combination Agreement with the combining partnerships, Dorchester Minerals Management LP, Dorchester Minerals Management GP LLC and Dorchester Minerals Operating LP relating to the terms and conditions of the combination.

Conditions to the Combination

The consummation of the combination is conditioned upon, among other things:

. the approval of the combination by the holders of more than 50% of the depositary receipts of Dorchester Hugoton, by all of the partners of Republic (including the Republic ORRI owners, who will become limited partners upon Republic's reorganization) and by the limited partners owning at least 85.9883% of the sharing percentages of Spinnaker;

. the completion of the reorganizations of Republic and Spinnaker and the conveyance of their working interests to Dorchester Minerals; and

. the absence of any material adverse change in the financial conditions of the combining partnerships (other than changes due to changes in oil and natural gas prices or general economic conditions).

Dissenters' Rights; Investor Lists

As a condition to being listed on the Nasdaq National Market System, the NASD requires that limited partners in transactions such as the combination must be provided with dissenters' rights. Accordingly, limited partners of Dorchester Hugoton and Spinnaker are entitled to such rights. The combination requires the approval of all of the

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Republic limited partners, so there will not be Republic dissenters if the combination occurs. See the discussion at "The Combination--Dissenters' Rights" beginning on page 68 of this document.

A limited partner may obtain a list of limited partners in his partnership by making a written request to the general partner(s) of his partnership at the address shown for each partnership in "The Parties" section of this Summary.

Regulatory Approvals

No federal or state regulatory approvals are required in connection with the consummation of the combination by any of the combining partnerships, except filing certificates of merger with Secretary of State of the State of Delaware and the Secretary of State of the State of Texas with respect to the mergers of Republic and Spinnaker with and into Dorchester Minerals.

Partner Vote Required to Approve the Combination

Approval requires the favorable vote of the holders of more than 50% of the depositary receipts of Dorchester Hugoton, of all of the partners of Republic (including the Republic ORRI owners, who will become limited partners upon Republic's reorganization) and of the limited partners owning at least 85.9883% of the sharing percentages of Spinnaker. The general partners of the combining partnerships are generally entitled under the respective partnership agreements to vote partnership interests they hold as limited partners at the special meetings or, in the case of Republic, by returning the consent card. The general partners of the combining partnerships plan to vote all of their partnership interests for the combination. The voting interests that each of the general partners hold in the respective combining partnerships is found in "Information Concerning Dorchester Hugoton--Security Ownership," "Information Concerning Republic--Security Ownership" and "Information Concerning Spinnaker--Security Ownership."

Comparison of Rights of Partners

For a comparison of the rights of our partners under Delaware law and our Partnership Agreement with the rights of the partners of each of the combining partnerships under Texas law and in the respective partnership agreements, see "Comparison of Rights of Partners" beginning on page 168 of this document.

Resales of Common Units

Our common units to be issued in connection with the combination have been registered under the Securities Act. All units will be freely tradable after completion of the combination, except for common units issued to (i) any partner of a combining partnership that is an "affiliate" of a combining partnership, as applicable, for purposes of Rule 145 of the Securities Act or
(ii) any partner that becomes an "affiliate" of our partnership after the combination. See the discussion at "The Combination Agreement--Resales of Common Units" on page of this document.

Other Information

Summary of United States Income Tax Consequences

For federal income tax purposes, the combination will be treated as a transfer of the assets and liabilities of each combining partnership to Dorchester Minerals in exchange for common units, followed by the distribution of the common units to the partners of the combining partnerships. These transfers should be tax free to you unless you elect to exercise dissenters' rights, if available to you. In addition, if you receive a cash distribution from one of the combining partnerships prior to or in connection with the combination, this distribution could be taxable to you depending on your basis in your partnership interest. See "Material United States Federal Income Tax Consequences" for a more complete discussion of the tax consequences of the combination.

Tax matters are very complicated. You should consult your tax advisor for a full understanding of the particular tax consequences of the combination to you.

Accounting Treatment

The combination will be accounted for using purchase accounting. Dorchester Hugoton has been

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designated the acquiror for purchase accounting purposes. See "The Combination Agreement--Accounting Treatment" on page 69 of this document.

Comparative per Unit Market Price Information

On August 1, 2001, the last full trading day before the public announcement of the combination, Dorchester Hugoton's depositary receipts closed at $13.00 per unit. On , 2002, Dorchester
Hugoton's depositary receipts closed at $ . No liquid market currently exists for interests in our partnership or in Republic or Spinnaker.

Certain Pro Forma Financial Data

The following table sets forth summary unaudited pro forma financial date for our partnership. It should be read in conjunction with the unaudited pro forma financial information and related notes included in this document beginning on page P-1, and with the historical financial statements of the combining partnerships and related notes included in this document beginning on page F-1.

                                                                                    Year ended December 31, 2001
                                                                                 (in thousands except per unit data)
                                                                                 -----------------------------------
Total operating revenues........................................................              $ 49,725
Operating expenses, excluding depreciation, depletion and amortization and asset
  impairment....................................................................                 4,517
Depreciation, depletion and amortization........................................                21,413
Impairment of assets............................................................                73,101
Total operating expenses........................................................                99,031
Other income....................................................................                    44
Net loss........................................................................               (49,262)
Net loss per unit--basic and diluted............................................                 (1.73)
Cash distributions..............................................................                39,148
Cash distributions per unit.....................................................                  1.40
Net cash provided by operating activities.......................................                50,261
Total assets....................................................................               124,006
Total liabilities...............................................................                    --
Partners' capital...............................................................               124,006

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RISK FACTORS

You should carefully consider the following risk factors, together with other information contained in this document and the information we have incorporated by reference, in determining whether to vote in favor of the combination.

Risks Related to Our Business

Cash distributions will be highly dependent on oil and natural gas prices, which have historically been very volatile.

Our partnership's quarterly cash distributions will 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:

. the worldwide and domestic supplies of oil and natural gas;
. the ability of the members of the Organization of Petroleum Exporting Countries, referred to as "OPEC," to agree to and maintain oil price and production controls;
. political instability or armed conflict in oil-producing regions;
. the price and level of foreign imports;
. the level of consumer demand;
. the price and availability of alternative fuels;
. the availability of pipeline capacity;
. weather conditions;
. domestic and foreign governmental regulations and taxes; and
. the overall economic environment.

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.

Our partnership will not control operations and development.

Essentially all of the producing properties we will acquire from Republic and Spinnaker are royalty interests. As a royalty owner, we will 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.

Most of the nonproducing properties we will acquire from Republic and Spinnaker are mineral and royalty interests. As the owner of a fractional undivided mineral or royalty interest, our ability to influence development of these nonproducing properties will be 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.

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Our unitholders will not be 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 will be unable to influence significantly the operations or future development of properties that it does not operate. Dorchester Minerals Operating LP (as successor to Dorchester Hugoton) and the other current operators of the properties underlying the Operating ORRIs will be 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. Our unitholders will not have the right to replace an operator.

Our lease bonus revenue will depend in significant part on the actions of third parties.

A significant portion of the nonproducing properties to be acquired from Republic and Spinnaker are mineral interests. With limited exceptions, we will 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 will be 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 will be subject to the Operating ORRIs.

Although it has no current intention of selling any of the underlying properties, our general partner, through Dorchester Minerals Operating LP, may at any time transfer all or part of the properties underlying the Operating ORRIs. You will not be entitled to vote on any transfer, and our partnership will not receive any proceeds of the transfer. Following any material transfer, the underlying properties will continue to be subject to the Operating ORRIs, but the net proceeds from the transferred property would be calculated separately and paid by the transferee. The transferee would be responsible for all of Dorchester Minerals Operating LP's obligations relating to the Operating ORRIs on the portion of the underlying properties transferred, and Dorchester Minerals Operating LP would have no continuing obligation to our partnership for those properties.

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 will be affected by production and other costs.

The cash available for distribution that will come from our royalty and mineral interests, including the Operating ORRIs, will be directly affected by increases in production costs and other costs. Some of these costs will be outside our control, including costs of regulatory compliance and severance and other similar taxes. Other expenditures will be 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 will 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.

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The timing and size of any maintenance, development or exploration projects will depend 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 that we acquire from Republic or Spinnaker, 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 units 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.

Although it is not contemplated that we will be directly engaged in the drilling of wells, 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:

. pressure or irregularities in formations;
. equipment failures or accidents;
. disputes with drill site landowners;
. unexpected drilling conditions;
. shortages or delays in the delivery of equipment;
. adverse weather conditions; and
. disputes with drill-site owners.

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 will be subject to the Operating ORRIs will reduce amounts payable to us under the Operating ORRIs by 96.97%, although we will never have liability to pay costs relating to those properties in excess of the amounts payable under the Operating ORRIs.

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

Our Partnership Agreement will limit our ability to acquire oil and natural gas properties in the future, especially for consideration other than our limited partnership interests. See "Business of Dorchester Minerals After the Combination--General" and "The Partnership Agreement--Issuance of Additional Securities." 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 also will obligate 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

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unrelated business taxable income in a manner similar to the treatment of Dorchester Hugoton's properties in the combination. Although such arrangements are possible as a condition to our acquisition of interests, 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 will be limited, including pursuant to the terms of the 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 will 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.

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 you 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 cannot assure you that we will be able to successfully integrate any oil and natural gas properties that we acquire into our operations or that we will 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 on 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 will not carry business interruption insurance.

The properties currently held by Dorchester Hugoton that will be subject to the Operating ORRIs will be geographically concentrated.

The properties currently held by Dorchester Hugoton and that will be 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.

Despite having two pipelines available and numerous buyers on each pipeline, the number of prospective natural gas purchasers and methods of delivery are considerably less than would otherwise exist from a more

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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.

We will generally not be responsible to third parties for costs that would be charged to a working interest owner, and we will not be obligated to make any payments to Dorchester Minerals Operating LP if its costs exceed revenues from the properties that will be subject to the Operating ORRIs. However, 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 will bear 96.97% of the costs of the working interest properties, and if costs exceed revenues, we will 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 will own and operate the gathering system and compression facilities that will be 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.

Most of Dorchester Hugoton's current working interest wells were drilled and have been producing since prior to 1954. Dorchester Hugoton's 132-mile Oklahoma gas pipeline gathering system 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 owned by Dorchester Hugoton prior to the consummation of the combination, which, as production costs, would reduce our cash flow from these properties.

We are not fully insured against operating hazards.

While we will maintain insurance coverage that we consider reasonable and that will be similar to that maintained by peer companies in the oil and natural gas industry and we expect that Dorchester Minerals Operating LP will do the same, neither we nor Dorchester Operating Minerals LP will be 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 will be 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 would 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 us.

Our business and the properties in which we hold interests will be 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 will be subject to the Operating ORRIs are located, have the ability, directly or indirectly, to limit production from those properties, and, although limitations on production do not currently affect those properties in either state, 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 in the field in which Dorchester Hugoton's wells are located 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 will be 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, even though we will not own working interests in oil and natural gas properties, the costs associated with environmental compliance or remediation could reduce the amount we would receive from our properties. The properties in which we will 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.

We will be subject to currently pending litigation of Republic and Dorchester Hugoton after the combination.

Republic and Dorchester Hugoton are currently involved in legal proceedings arising in the ordinary course of their businesses. Republic is a party to various proceedings, including the Salinas litigation described under "Information Concerning Republic--Legal Proceedings" beginning at page 126. Dorchester Hugoton is a party to a case pending in the District Court of Texas County, Oklahoma, referred to as the RRNGR litigation, which is described under "Information Concerning Dorchester Hugoton--Legal Proceedings" beginning at page 112.

As a result of the combination, we will assume any liabilities relating to these legal proceedings and the costs of defense of such proceedings. Upon consummation of the combination, we will be entitled to indemnification from a limited partnership affiliated with Republic for liabilities and expenses relating to the Salinas litigation, but will not be indemnified with respect to the RRNGR litigation. Our financial position and ability to make distributions could be materially and adversely affected due to losses relating to such legal proceedings if we are not fully indemnified or if losses that might be suffered in the Salinas litigation exceed the value of the assets of the indemnifying limited partnership, which will consist of approximately 984,750 of our common units.

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Numerous uncertainties exist in estimating our quantities of proved reserves and future net revenues.

Estimates of proved reserves and related future net revenues are based on various assumptions, which may prove to be inaccurate. Therefore, those estimates should not be construed as being accurate as being accurate estimates of the current market value of our proved reserves. Although Dorchester Hugoton is affected only by changes in natural gas prices, Republic and Spinnaker are affected by changes in both oil and natural gas prices. Oil and natural gas prices may not experience corresponding price changes.

Risks Related to the Combination

The combination exchange ratios for each combining partnership were negotiated based in part upon reserve estimates that may vary significantly from the quantities of oil and natural gas actually recovered by that partnership, and consequently future net revenues may be materially different from the estimates used in the negotiation of the combination exchange ratio for a particular partnership.

The calculations of each combining partnership's estimated reserves of oil and natural gas, and future net revenues from those reserves, considered in the negotiation of combination exchange ratios were only estimates. Actual prices, production, operating expenses and quantities of recoverable oil and natural gas reserves may vary significantly from those assumed in the estimates. Any such variance from the assumptions used could result in a material variance between the actual quantity of each combining partnership's reserves and future net revenues and the estimates used in the negotiation of the combination exchange ratio for that partnership. The use of these estimates in determining the combination exchange ratios could therefore result in an undervaluation or overvaluation of your combining partnership in determining the common units you will receive in the combination.

The combination exchange ratio for a combining partnership will not be adjusted for changes in oil and natural gas prices before the completion of the combination.

The combination exchange ratio for the combining partnership in which you own an interest determines the number of our common units that you will receive in the combination. See "Background and Reasons for the Combination--Combination Exchange Ratios and Consideration Allocated to General Partner Interests" for a discussion of these combination exchange ratios. While oil and natural gas prices have fluctuated significantly in recent years and may continue to do so, the combination exchange ratio for a subject partnership will not be adjusted as of the combination closing to reflect any general changes in oil and natural gas prices, or any other matter generally affecting the oil and natural gas industry, occurring after the date of the Combination Agreement and prior to the combination closing date.

No appraisals or valuations, other than the reserve reports, have been done for any of the combining partnerships.

The combination exchange ratios for the combining partnerships used to determine the common units you will receive were determined by arm's-length negotiations among the combining partnerships. Other than the reserve reports described in this document, there were no independent valuations or appraisals performed on the assets of the combining partnerships, and the general partners did not have any such valuations or appraisals available to them as they negotiated the terms of the combination. The combination exchange ratios determined by negotiation may be different from the combination exchange ratios that would result if the combining partnerships' assets were appraised and the combination exchange ratios determined by formula based on that factor alone.

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The fairness opinion to Dorchester Hugoton was issued before the most recent reserve reports became available for the combining partnerships.

Dorchester Hugoton engaged Bruce E. Lazier, P.E. to render an opinion as to the fairness, from a financial point of view, of the combination to Dorchester Hugoton and its limited partners. Mr. Lazier's latest opinion, which was issued on December 13, 2001, was based in part upon reserve information through only December 31, 2000, and therefore is not based upon the latest reserve information now available. Reserve information for Dorchester Hugoton, Republic and Spinnaker as of December 31, 1999, 2000 and 2001 is set forth in this document.

You were not independently represented in establishing the terms of the combination.

Representatives of the general partners of the combining partnerships determined the terms of the combination, including the combination exchange ratio of each combining partnership, the type and amount of interests in our partnership to be received by the general partners and limited partners of each of the combining partnerships, the terms of the Operating ORRIs and other terms as to which the general partners may be deemed to have interests different from the interests of the limited partners. The general partners of the combining partnerships did not seek recommendations about the type of transaction or the terms or prices from any independent underwriter, financial advisor or other securities professional, except that Dorchester Hugoton engaged Bruce E. Lazier, P.E. to assess the fairness of the combination to the depositary receipt holders of Dorchester Hugoton from a financial point of view. Mr. Lazier's opinion addressed the fairness of terms that had already been negotiated, and he did not participate in those negotiations. The only independent representatives in the combination were the Advisory Committee members of Dorchester Hugoton. However, the Advisory Committee members reviewed the combination only from the standpoint of fairness to Dorchester Hugoton's depositary receipt holders, not from the standpoint of fairness to limited partners of Republic and Spinnaker. In addition, while the Advisory Committee did give input to the general partners of Dorchester Hugoton concerning certain terms of the combination while those terms were being negotiated, they did not participate in the negotiation of the combination exchange ratios. Therefore, no representative group of limited partners and no outside experts or consultants, such as investment bankers, legal counsel, accountants or financial experts, were engaged solely to represent the independent interests of the limited partners of any partnership in structuring and negotiating the terms of the combination for any partnership. If you had been separately represented, the terms of the combination might have been different and possibly more favorable to you.

The consideration limited and general partners receive and the terms of the combination were determined by the general partners of the combining partnerships, which have inherent conflicts of interest.

The interests of the general partners of the combining partnerships and their officers may differ from your interests. For example, each general partner has a duty to manage the applicable combining partnership in the best interests of its limited partners, but also has a duty to operate its business for the benefit of its owners. See "Conflicts of Interest and Fiduciary Duties--Interests of Certain Persons in the Combination."

Some common management and ownership exists between one of the Republic general partners and the general partners of Spinnaker.

H.C. Allen, Jr., Frederick M. Smith, II and William Casey McManemin each serve as an officer of SAM Partners, Ltd., one of the general partners of Republic, and of Smith Allen Oil & Gas, Inc., the general partner of Spinnaker. As a result of this common management, these representatives participated in the negotiation of the combination exchange ratios for both Republic and Spinnaker. These management representatives or their family members own both SAM Partners, Ltd. and Smith Allen Oil & Gas, Inc. and own some limited partner interests in both Republic and Spinnaker. Vaughn Petroleum, Ltd., a general partner of Republic that is not otherwise affiliated with SAM Partners, Ltd. or Smith Allen Oil & Gas, Inc., was involved in negotiating the combination exchange ratios on behalf of Republic. Vaughn Petroleum, Ltd. is also the general partner of a limited partnership that is a limited partner of Spinnaker. However, if no common management or ownership existed between the

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general partners of Republic and Spinnaker, the terms of the combination might have been different and possibly more favorable to the limited partners of either of Republic or Spinnaker.

It is not certain what the market demand is for any combining partnership or its assets or that the terms of the combination are as favorable as could be obtained in a third party sale.

Except for the internal review of strategic alternatives by the general partners of Dorchester Hugoton and their contacts with potential parties to a strategic transaction discussed under "Background and Reasons for the Combination--Background of the Combination" beginning at page 33, the combining partnerships have not actively solicited bids from third parties. An invitation for third party bids could result in a better price to the partners than the terms of the combination. While the contacts by Dorchester Hugoton described under "Background of the Combination" produced no other offer consistent with what the general partners believed its depositary receipt holders' objectives to be, and no alternative transaction for any of the combining partnerships was proposed by any third party after the non-binding letter of intent was publicly announced, we cannot be certain of the market demand for any combining partnership or its assets, individually or as a whole with the other combining partnerships, or what a third party might offer for any combining partnership if additional efforts to market the combining partnerships had occurred.

The alternatives to the combination could potentially be more beneficial to limited partners than the combination.

You should also note that, instead of entering into the combination, any given combining partnership could have continued its independent operations and possibly achieved greater success than it will under the combination, or with the approval of its partners, sought to liquidate the partnership's assets and distributed the liquidation proceeds in accordance with the provisions of the respective partnership agreement. This would have enabled limited partners to reinvest proceeds from the asset sales and avoid the market risks associated with the ownership of our common units, but would have resulted in a taxable event.

Potential litigation challenging the combination may delay or prevent the transaction and your receipt of the common units.

It is possible that one or more of the partners of the combining partnerships could oppose the combination and initiate legal action to stop the combination or to seek damages for certain alleged violations of federal or state laws. Litigation challenging the combination may delay or prevent the closing. If any lawsuits are filed by governmental agencies or if injunctive relief were issued in any private litigation, the combination could be terminated. If the action of a combining partnership required to complete the combination is delayed or terminated, the issuance of the common units that you would otherwise receive will be delayed or terminated.

Partners of Dorchester Hugoton and Spinnaker could be bound by the Combination Agreement even if they do not vote in favor of the combination.

If you are a limited partner in Dorchester Hugoton or Spinnaker, you will be bound by the Combination Agreement if the necessary percentage of the partners in each of the partnerships vote in favor of the combination, even if you vote against the combination or do not vote. If the combination occurs, you will be entitled to receive only a cash distribution and an amount of common units based on the combination exchange ratio of your partnership interests in the partnership in which you own an interest unless you exercise your dissenters' rights.

If the combination is not consummated, all or a portion of the transaction costs will be borne by the combining partnerships.

The combination is a very complex transaction, and the transaction costs associated with regulatory compliance will be significant. Most of the costs will be incurred throughout the course of the transaction, and a

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risk exists that the transaction could be terminated prior to its estimated completion but after the incurrence of substantial costs. In this event, the combining partnerships generally will bear their respective separate costs and a portion of common costs as described in "The Combination Agreement--Expenses and Fees." In accordance with the partnership agreements of the combining partnerships, but subject to certain terms of the Combination Agreement and undertakings of the general partners, the limited partners of each combining partnership will bear a portion of the transaction costs. See "The Combination Agreement--Expenses and Fees" for more information.

Our general partner may experience difficulties in integrating the former businesses and management operations of the combining partnerships.

Our general partner will endeavor to integrate the businesses and operations of the combining partnerships to operate in an efficient manner, but we may experience inefficiencies, costs and demands upon management resources that may adversely affect our business.

A significant portion of Dorchester Hugoton's management operations have been focused on operating its gas properties. Those operations will have to be divided between managing the working interests to be owned by Dorchester Minerals Operating LP and managing the Operating ORRIs and other interests, and the latter management operations will have to be coordinated with the management of the former Republic and Spinnaker properties. Republic and Spinnaker have operated as privately held entities and their operations and practices will have to be adjusted to operating as a publicly held concern. The Dorchester Hugoton and Republic and Spinnaker management operations are in separate locations and will remain so for an indefinite time after the combination. Having two separate office locations may lead to inefficiencies in operations.

Dissenters' rights of appraisal will not be available for Republic and are limited for Spinnaker and Dorchester Hugoton.

Under the terms of the Combination Agreement, limited partners in Dorchester Hugoton and Spinnaker are given certain contractual dissenters' rights of appraisal. However, these dissenters' rights are not available to the limited partners of either Dorchester Hugoton or Spinnaker if that partnership receives approval of the Combination Agreement by holders of 75% or more of the limited partnership interests, based on the percentage interests in profits at the time of the applicable partnership vote, including limited partnership interests held by the general partners. Therefore, you will not have the opportunity to receive appraised value for your limited partnership interests if more than 75% of the partners in your partnership approve the combination and you may be forced to receive our common units in exchange for your limited partnership interests.

Because the combination will not be consummated by Republic unless 100% of its partners approve the transaction, the holders of limited partnership interests in Republic will not have dissenters' rights.

If the Combination Agreement is terminated under certain circumstances, a termination fee payable by your partnership may result.

In certain circumstances, your combining partnership may owe a termination fee of up to $3,000,000. If a termination fee were payable in the situation of an acquisition proposal, there can be no assurance that an alternative transaction would actually be consummated, or, if consummated, that it would be on more favorable terms. In that case, a partnership obligated to make all or a portion of the termination payment would bear the entire cost from its own assets without the receipt of consideration from a third party by it or its partners. See "The Combination Agreement--Termination Fee" for a detailed description of the termination fee.

The termination fee is limited to $3,000,000, and transaction expenses are not separately payable. Therefore, it is possible that the costs incurred by a recipient of a termination payment in connection with the combination might absorb a large portion of the payment or even that the termination fee might not cover all costs incurred by

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the recipient during the course of the combination. In that case, the recipient would not be compensated or compensated fully for its lost opportunity.

Our reserves will be more geographically concentrated than those of Republic or Spinnaker.

There are certain business risks associated with the increased concentration of reserves as a result of the combination, when viewed from the perspective of current limited partners of Republic and Spinnaker. Currently, the business properties and reserves of Republic and Spinnaker are scattered throughout the United States. Upon the consummation of the combination, approximately 40% of our business, properties and assets will have a concentration in the Hugoton field in Kansas and Oklahoma. As a result, a current investor in Republic or Spinnaker will face investment risks associated with a heavier geographic concentration of reserves which will characterize our business following the consummation of the combination.

The larger size of the combined company may expose us to increased liabilities.

We will assume all liabilities and obligations of Dorchester Hugoton, Republic and Spinnaker except to the extent previously assumed by Dorchester Minerals Operating LP. These will include any unknown liabilities, any undisclosed liabilities and any disclosed but contingent liabilities of the combining partnerships. The increased size of the combined company may make it more likely that we will be exposed to these liabilities, which may include claims for title defects, claims relating to environmental matters or other liabilities associated with operations or ownership of oil and natural gas properties. Except in connection with one pending litigation proceeding involving Republic, none of the general partners of the combining partnerships or their affiliates will have any obligation to indemnify us against any such liabilities.

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 you.

Prior to making any distribution on the common units, we will 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 you. Our general partner has sole discretion to determine the amount of these expenses, subject to the annual limit described under "Management--Absence of Management Fees; Reimbursement of General Partner," which 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 will be presented on an accrual basis in accordance with generally accepted accounting practices. Unitholder K-1 tax statements will be calculated based on applicable tax conventions. Distributions, however, will be 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.

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You will have limited voting rights and will not control our general partner, and your ability to remove our general partner will be limited.

You will have only limited voting rights on matters affecting our business. The general partner of our general partner, whose managers you do not elect, manages our activities. You will have no right to elect these managers 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 will not own sufficient common units upon completion of the combination to be able to prevent its removal as general partner, but they will own sufficient common units to make the removal of our general partner by other unitholders difficult. See "The Partnership Agreement--Withdrawal or Removal of the General Partner." Furthermore, any common units held by a person or group (other than the general partner and its affiliates or a direct transferee of the general partner or its affiliates) that owns 20% or more of our common units cannot be voted on any matter.

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 will 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. Furthermore, although the owners of our general partner have agreed among themselves to some transfer restrictions 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 interest and limited fiduciary responsibilities, 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 will 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 will not 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 will have similar duties to them and will 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 you, on the other, or between us or you 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, even though various affiliates of the general partner and its executive officers will own a significant number of common units upon completion of the combination and therefore will also have interests aligned with unitholders in general. The nature of these conflicts include the following considerations.

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. We have renounced certain business opportunities in the Business Opportunities Agreement for the benefit of affiliates of our general partner. Except for limited contractual commitments of certain affiliates in the Business Opportunities Agreement, our general partner's affiliates are not prohibited from engaging in other business or activities, including those in direct competition with us. The businesses of many of these affiliates are substantially similar to that of our partnership, and some of these affiliates have well established relationships in the oil and natural gas industry and access to significant resources.

. Our general partner and its affiliates may limit their liability and reduce their fiduciary duties, while also restricting the remedies available to unitholders for actions that might, without the limitations, constitute breaches of fiduciary duty. Unitholders are deemed to have consented to some actions and conflicts of interest that might otherwise be deemed a breach of fiduciary or other duties under applicable state law.

. Our general partner is allowed to take into account the interests of parties in addition to our partnership in resolving conflicts of interest, thereby limiting its fiduciary duties to our unitholders.

. Our general partner determines the amount and timing of asset purchases and sales, capital expenditures and cash reserves, each of which can affect the amount of cash that is distributed to unitholders.

. Our general partner is not restricted from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf.

. Our Partnership Agreement requires us to indemnify our general partner and various affiliates of the general partner to the fullest extent permitted by law, which could result in us indemnifying our general partner for negligent acts.

There has been no prior public market for our common units.

There has been no prior market for the common units. While we intend to include the common units for quotation on the Nasdaq National Market System, we do not know the extent to which investor interest in the common units will lead to a the development of a trading market or how the common units will trade in the future. The price at which the common units will trade will be established by the market, and there is no assurance that such price will be equal to the value of the depositary receipts or limited partnership interests exchanged.

We may issue additional securities, diluting your 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, for any amount and on any terms and conditions established by our general partner. Unitholders will have not rights to approve such issuances, unless, after giving effect to such issuance, such newly issued partnership securities would represent over 20% of the outstanding limited partner interests.

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

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

Under Delaware law, you 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. See "The Partnership Agreement--Limited Liability" for a discussion of the implications of the limitations on liability to a unitholder.

Because we will conduct our business in various states, the laws of those states may pose similar risks to you. To the extent to which we conduct business in any state, you might be held liable for our obligations as if you were a general partner 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 will 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.

Our continued success will depend 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.

Sales of common units after the combination may cause the price of our common units to drop.

It is possible that a significant amount of our common units could be offered for sale immediately after the closing date for various reasons, including the liquidity that the combination will afford to limited partners of Spinnaker and Republic, who have not previously had access to a trading market for their partnership interests. Sales by these limited partners, or the perception that they may occur, may tend to lower the market price for our common units. Except for the one-year lock-up agreements that the general partners of the combining partnerships, the managers of our general partner's general partner and the officers of our general partner's operating subsidiary will enter into, it is not anticipated that any unitholders will be subject to lock-up agreements following the combination. See "The Partnership Agreement--Registration Rights" for information regarding registration rights of our general partner and its affiliates.

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

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

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Tax Risks

For a general discussion of the anticipated material United States federal income tax consequences of transactions occurring prior to the combination, the combination itself, and owning and disposing our common units after the combination, see "Material United States Federal Income Tax Consequences" beginning on page 74.

We have not received a ruling or assurances from the IRS or any state or local taxing authority on any matters affecting us.

We have not requested, and will not request, any ruling from the Internal Revenue Service, or IRS, or any state or local taxing authority with respect to the consequences of transactions occurring prior to the combination, the combination itself, owning and disposing of our common units following the combination or any other matter. Accordingly, the IRS or other taxing authority may propose positions that differ from the conclusions expressed by our counsel in this document or the positions taken by us in the absence of an opinion of counsel. It may be necessary to resort to administrative or court proceedings in an effort to sustain some or all of those conclusions or positions, and some or all of those conclusions or positions ultimately may not be sustained. Our unitholders and general partner will bear, directly or indirectly, the costs of any contest with the IRS or other taxing authority.

The federal income tax treatment of Dorchester Hugoton's conveyance of its working interest in mineral properties to Dorchester Minerals Operating LP may not be respected by the IRS.

Prior to the combination, Dorchester Hugoton will convey its working interest in its mineral properties to Dorchester Minerals Operating LP and retain an overriding royalty interest in the properties. This transfer should be treated, for federal income tax purposes, as a lease of the working interest from Dorchester Hugoton to Dorchester Minerals Operating LP and should not cause the Dorchester Hugoton unitholders to recognize taxable gain or loss at the time of the transfer. There is no assurance that the IRS will not challenge this position. Such a challenge, if successful, could cause the Dorchester Hugoton unitholders and general partners to recognize more taxable income or to recognize taxable loss as a result of the combination.

Dorchester Hugoton's depositary receipt holders may recognize gain or loss as a result of a pre-combination sale of stock by Dorchester Hugoton.

Prior to the combination, Dorchester Hugoton intends to sell 128,000 shares of Exxon Mobil stock with an average cost basis of $19.67 per share. As a result, Dorchester Hugoton will recognize long term capital gain in an amount equal to the difference between the amount realized in the sale and Dorchester Hugoton's adjusted tax basis in the stock. This gain will be allocated among Dorchester Hugoton's depositary receipt holders and general partners and will be includible in their gross income for federal income tax purposes. However, as a result of Dorchester Hugoton's section 754 election, a depositary receipt holder who purchased its Dorchester Hugoton units from a current or former Dorchester Hugoton depositary receipt holder may be allocated more or less gain than other depositary receipt holders holding the same number of units, or may be allocated a loss, from the sale of the Exxon Mobil stock.

Dorchester Hugoton's depositary receipt holders may not be able to use passive activity losses that are suspended until they sell our common units.

We do not anticipate that we will generate any material amount of passive activity income. As a result, all or substantially all suspended passive activity losses that a Dorchester Hugoton depositary receipt holder has at the time of the combination will remain suspended until that partner disposes of our common units in a fully taxable transaction with an unrelated third party. However, a partner will be entitled to recognize otherwise suspended passive activity losses to the extent the partner receives a distribution of money upon the liquidation of Dorchester Hugoton in excess of the partner's basis in his partnership interests in Dorchester Hugoton.

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Limited partners of the combining partnerships may recognize gain as a result of certain distributions of cash.

Prior to the combination, Republic and Spinnaker intend to distribute cash to their partners in proportion to their partnership interests. As part of its transfer of assets to us and subsequent liquidation, Dorchester Hugoton will make a cash distribution to its depositary receipt holders. Limited partners of the combining partnerships will recognize gain for federal income tax purposes to the extent that any cash received exceeds the partner's adjusted tax basis in its partnership interest.

The combination will result in a closing of the taxable years of each of the combining partnerships, which may result in adverse tax consequences to you.

The termination of Republic and Spinnaker for federal income tax purposes, and the dissolution and liquidation of Dorchester Hugoton, will result in a closing of the taxable years of each of the combining partnerships as of the date of the combination (for Republic and Spinnaker) or the liquidation of Dorchester Hugoton. As a result, if you have a taxable year that ends after the date of the combination or liquidation, as applicable, but before December 31, 2002, you will be required to include in the same taxable year your allocable share of income, gain, loss, deduction, credits and other items of Republic, Spinnaker or Dorchester Hugoton from both the taxable year ending December 31, 2001 and the short taxable year ending at the time of the combination (in the case of Republic and Spinnaker) or the liquidation of Dorchester Hugoton.

Post-combination transactions may cause you to recognize all or a part of your taxable gain, if any, deferred through the combination.

Even if you are not required to recognize taxable gain at the time of the combination, a subsequent sale of our assets could cause you to recognize part or all of such gain. If we sell an asset that a combining partnership held prior to the combination, the former partners of the partnership that originally contributed the property to us will be allocated, for federal income tax purposes, the portion of the gain from the sale that is attributable to any remaining unrealized gain that existed when the asset was contributed to us. Those former partners that are specially allocated gain under these rules would report the additional gain on their own federal income tax returns, but would not be entitled to any special distributions from us. As a general rule, our general partner is not required to take into account the tax consequences to, or obtain the consent of, our unitholders in deciding whether to cause us to undertake specific transactions that could have adverse tax consequences to our unitholders. Our general partner has not made any commitment to any of the combining partnerships or any of their partners not to undertake transactions that will cause the former partners of the combining partnerships to recognize all or part of the taxable gain that was deferred through the combination.

Our tax treatment depends on our classification as a partnership.

Based upon the continued accuracy of the representations of the combining partnerships set forth in "Material United States Federal Income Tax Consequences - Consequences of Ownership of Our Common Units After The Combination--Classification of Our Partnership as a Partnership for Federal Income Tax Purposes" on page 80, our counsel believes that under current law and regulations we will be classified as a partnership and will not be taxed as a corporation for federal income tax purposes. However, as stated above, we have not requested, and will not request, any ruling from the IRS as to this status, and our counsel's opinion is not binding on the IRS. In addition, you cannot be sure that those representations will continue to be accurate. If the IRS were to challenge our federal income tax status, such a challenge could result in an audit of your entire tax return and adjustments to items on that tax return that are unrelated to your ownership of our common units. In addition, you would bear the cost of any expenses incurred in connection with an examination of your personal tax return.

If we were taxable as a corporation for federal income tax purposes in any taxable year, our income, gain, losses and deductions would be reflected on our tax return rather than being passed through proportionately to

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you, and our net income would be taxed at corporate rates. In addition, some or all of the distributions made to you would be treated as dividend income without offset for depletion, and distributions would be reduced as a result of the federal, state and local taxes paid by us.

We will use a monthly convention of allocating items of our income, gain, deduction and loss between transferors and transferees, which may not be accepted by the IRS.

In general, each of our items of income, gain, loss and deduction will be, for federal income tax purposes, determined at least on a quarterly basis and, if quarterly, one third of each quarterly amount will be allocated to those unitholders who hold common units on the last business day of each month in that quarter. In certain circumstances we may make these allocations in connection with extraordinary or nonrecurring events on a more frequent basis. As a result, transferees of our common units may be allocated items of our income, gain, loss and deduction realized by us prior to the date of their acquisition of our common units. There is no specific authority addressing the utilization of this method of allocating items of income, gain, loss and deduction by a publicly traded partnership such as us between transferors and transferees of its common units. If this method is determined to be an unreasonable method of allocation, our income, gain, loss and deduction would be reallocated among our unitholders and our general partner. Our general partner is authorized to revise our method of allocation between transferors and transferees, as well as among our other unitholders whose common units otherwise vary during a taxable period, to conform to a method permitted or required by the Internal Revenue Code and the regulations or rulings promulgated thereunder.

You may not be able to deduct losses attributable to your common units.

Any losses relating to your common units will be losses related to portfolio income and your ability to use such losses may be limited.

Your partnership tax information may be audited.

We will furnish you with a Schedule K-1 tax statement that sets forth your allocable share of income, gains, losses and deductions. In preparing this schedule, we will use various accounting and reporting conventions and various depreciation and amortization methods we have adopted. You cannot be sure that this schedule will yield a result that conforms to statutory or regulatory requirements or to administrative pronouncements of the IRS. Further, our tax return may be audited, and any such audit could result in an audit of your individual income tax return as well as increased liabilities for taxes because of adjustments resulting from the audit. An audit of your return also could be triggered if the tax information relating to your common units is not consistent with the Schedule K-1 that we are required to provide to the IRS.

Our method for determining the adjusted tax basis of your common units may not be respected by the IRS.

In general, we intend to adopt a reporting convention that will enable you to track the basis of your individual common units or unit groups and use this basis in calculating your basis adjustments under section 743 of the Internal Revenue Code and gain or loss on the sale of common units. Although we believe this method is reasonable, it does not comply with an IRS ruling that requires a portion of the combined tax basis of all common units to be allocated to each of the common units owned by you upon a sale or disposition of less than all of the common units. No assurance can be given that this method will not be challenged. If such a challenge is successful, you may have to recognize more taxable income or less taxable loss with respect to common units disposed of and common units you continue to hold.

We cannot assure tax-exempt investors that they will recognize no unrelated business taxable income.

Generally, unrelated business taxable income, or UBTI, can arise from a trade or business unrelated to the exempt purposes of the tax-exempt entity that is regularly carried on by either the tax-exempt entity or a

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partnership in which the tax-exempt entity is a partner. However, UBTI does not apply to interest income, royalties (including overriding royalties) or net profits interests, whether the royalties or net profits are measured by production or by gross or taxable income from the property. Pursuant to the provisions of our Partnership Agreement, our general partner shall use all reasonable efforts to prevent us from realizing income that would constitute UBTI. However, there is no assurance that we will not incur UBTI.

You may not be entitled to deductions for percentage depletion with respect to our oil and natural gas interests.

You will be entitled to deductions for the greater of either cost depletion or (if otherwise allowable) percentage depletion with respect to the oil and natural gas interests owned by us. However, percentage depletion is generally available to you only if you qualify under the independent producer exemption contained in the Internal Revenue Code. For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, natural gas, or derivative products or the operation of a major refinery. If you do not qualify under the independent producer exemption, you generally will be restricted to deductions based on cost depletion. Also, if you are a Dorchester Hugoton partner who is currently restricted from using percentage depletion with respect to some or all of Dorchester Hugoton's properties by transfer rules in effect at the time you acquired your Dorchester Hugoton units, you may continue to be restricted from using percentage depletion with respect to your share of our income attributable to these properties.

We will employ a method of allocating depletion deductions that may not be accepted by the IRS.

The Internal Revenue Code requires that income, gain, loss and deduction attributable to appreciated or depreciated property that is contributed to a partnership in exchange for a partnership interest in the partnership must be allocated so that the contributing partner is charged with, or benefits from, respectively, the unrealized gain or unrealized loss associated with the property at the time of its contribution to the partnership. Our Partnership Agreement provides that the adjusted tax basis of the oil and natural gas properties contributed to us will be allocated to the partners of the combining partnership that contributed the properties for the purpose of separately determining depletion deductions. Any gain or loss recognized by us on the disposition of any oil and natural gas property contributed to us will be allocated to the partners of the combining partnership that contributed the property, in proportion to their percentage interest in the combining partnership, to the extent of the difference between the property's fair market value and its adjusted tax basis at the time of its contribution, referred to as "Built-in Gain" and "Built-in Loss," respectively. Although this method of allocating Built-in Gain and Built-in Loss is not specifically permitted by the Treasury regulations, we believe that the above method should be respected as reasonable and consistent with the underlying purposes of section 704(c) of the Internal Revenue Code. However, there is no assurance that the IRS will not challenge the method to be used by us. Such a challenge, if successful, could cause you to recognize more taxable income or less taxable loss on an ongoing basis in respect of your common units.

We will use a method of determining a common unitholder's share of the basis of partnership property for common units purchased after the combination that may not be accepted by the IRS.

With respect to common units purchased after the combination, our general partner intends to utilize a method of calculating each unitholder's share of the basis of partnership property which will result in an aggregate basis for depletion purposes that reflects the purchase price of common units as paid by the unitholder. The method the general partner intends to utilize is not specifically authorized under applicable Treasury regulations, but we believe it is a reasonable method of determining a unitholder's net income or loss. However, there is no assurance that the IRS will not challenge the method to be used by us. Such a challenge, if successful, could cause you to recognize more taxable income or less taxable loss on an ongoing basis in respect of your common units.

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The ratio of the amount of taxable income that will be allocated to you to the amount of cash that will be distributed to you is uncertain.

The amount of taxable income realized by you will be dependent upon a number of factors including: (i) the amount of taxable income recognized by us; (ii) the amount of any gain recognized by us that is attributable to specific asset sales that may be wholly or partially attributable to Built-in Gain and the resulting allocation of such gain to you, depending on the asset being sold;
(iii) the amount of basis adjustment pursuant to the Internal Revenue Code available to you based on the purchase price for any common units and the amount by which such price was greater or less than your proportionate share of inside tax basis of our assets attributable to the common units when the common units were purchased; and (iv) the method of depletion available to you. Therefore, it is not possible for us to predict the ratio of the amount of taxable income that will be allocated to you to the amount of cash that will be distributed to you.

You may lose your status as a partner of our partnership for federal income tax purposes if you lend our common units to a short seller to cover a short sale of such common units.

If you loan your common units to a short seller to cover a short sale of common units you may be considered as having disposed of your ownership of those common units for federal income tax purposes. If so, you would no longer be a partner of our partnership for tax purposes with respect to those common units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period, any of our income, gain, loss or deduction with respect to those common units would not be reportable by you, and any cash distributions received by you for those common units would be fully taxable and may be treated as ordinary income. Our counsel is not rendering an opinion regarding the treatment of a unitholder whose common units are loaned to a short seller. Therefore, if you desire to assure your status as a partner for federal income tax purposes and avoid the risk of gain recognition you should modify any applicable brokerage account agreements to prohibit your broker from loaning your common units.

Assignees of common units who fail to execute and deliver transfer applications may not be treated as partners of our partnership for federal income tax purposes.

As there is no direct authority addressing assignees of our common units who fail to execute and deliver transfer applications, our counsel is unable to opine whether such assignees will be treated as partners for federal income tax purposes. A purchaser or other transferee of common units who does not execute and deliver a transfer application may not receive some federal income tax information or reports furnished to record unitholders unless the common units are held in a nominee or street name account with a qualified securities broker. Income, gain, deduction or losses would not be reportable by a unitholder who is not a partner of our partnership for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner of our partnership for federal income tax purposes would, therefore, be fully taxable as ordinary income.

A sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period could result in adverse tax consequences to you.

We will terminate for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. A termination would result in the closing of our taxable year for you. As a result, if you have a different taxable year than we have, you may be required to include your allocable share of our income, gain, loss, deduction, credits and other items from both the taxable year ending prior to the year of our termination and the short taxable year ending at the time of our termination in the same taxable year. A termination also could result in penalties if we were unable to determine that the termination occurred.

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You should also consider the potential foreign, state and local tax consequences of owning our common units.

You may be required to file tax returns and be subject to tax liability in the foreign, state or local jurisdictions where you reside and in each state or local jurisdiction in which we have assets or otherwise do business. We also may be required to withhold state income tax from distributions otherwise payable to you. For example, withholding will be required with respect to properties located in Louisiana. As a result of reduced concentration of revenues in two states, a smaller number of former Dorchester Hugoton depositary receipt holders may be subject to income taxes in those states but could become subject to income taxes in other states.

BACKGROUND AND REASONS FOR THE COMBINATION

Background of the Combination

Investigation of Strategic Alternatives by Dorchester Hugoton

From its inception, Dorchester Hugoton's business was adversely affected by governmental price controls on natural gas and by related litigation. By 1993, however, price controls were no longer in effect and by 1996 the related litigation had been resolved, and Dorchester Hugoton commenced a number of previously deferred production enhancements to its properties.

The favorable preliminary results of those production enhancements combined with (i) the absence of litigation, (ii) the awareness of Dorchester Hugoton's general partners of numerous mergers and other transactions that were occurring in the natural gas and energy industry, and (iii) a favorable market price for natural gas, caused the general partners of Dorchester Hugoton to decide to review strategic alternatives that might be available to Dorchester Hugoton.

In early February 1998, Dorchester Hugoton included the following paragraph in its 1997 Annual Report on Form 10-K:

"The Partnership is reviewing its strategic alternatives in light of the various mergers and other business transactions occurring in the natural gas and energy industry. Although no decision to sell or combine the Partnership's business with others has been made, the Partnership anticipates possible discussions with third parties which could result in such a decision. The Partnership has no timetable for any such discussions, and there is no assurance that any such discussions will lead to a transaction.

The Partnership expects to adopt a severance policy for its employees during the first quarter of 1998 which would provide up to approximately $2.8 million of severance payments if such obligation occurs."

A severance policy was adopted later in February 1998. Its purpose was to act as an employee retention program and to avoid the departure of skilled personnel during the period of time required to review possible transactions.

Following this announcement, over the next two years the general partners of Dorchester Hugoton reviewed and analyzed publicly available information concerning between 60 and 70 parties, mostly in the oil and natural gas industry, including some publicly traded limited partnerships. In the judgment of the general partners, potential transactions with many of these parties did not appear to offer mutual benefits. In addition, a number of the parties reviewed were engaged in divestiture programs concerning oil and natural gas properties or had some other characteristics that in the judgment of Dorchester Hugoton's general partners made them unsuitable candidates for a potential transaction.

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In their review of strategic alternatives, the general partners of Dorchester Hugoton considered a number of alternatives, including:

. a taxable business combination;

. a non-taxable business combination in which the holders of depositary receipts would continue to own or would receive equity interests in the surviving entity;

. a partially non-taxable business combination in which the holders of depositary receipts would receive partly cash consideration and partly equity in the surviving corporation;

. a sale of Dorchester Hugoton's assets for cash and a liquidation of Dorchester Hugoton; and

. a continuation of Dorchester Hugoton under its existing business plan.

The general partners felt that, in general, these were the most likely strategic alternatives that would be available but were open to consider other alternatives that might be proposed by interested parties.

The general partners believed that any potential combination would need to be with another partnership or the transaction would be a taxable event. If a combination were taxable, then it would need to be at a premium over prevailing market prices for Dorchester Hugoton's depositary receipts to cover taxes and create an incentive for the transaction to occur.

As a procedural matter, a sale of Dorchester Hugoton's properties for cash and a liquidation of Dorchester Hugoton could be accomplished by the general partners without a vote of the depositary receipt holders. Because its properties are closely related geographically and are served by a common gathering system, a sale of the properties as a whole is more practical than a sale of individual wells or interests in wells and, in the judgment of the general partners, would command a higher price. However, during the exploration of strategic alternatives no potential buyer emerged who expressed an interest in a cash purchase of Dorchester Hugoton's properties. A sale for cash and a liquidation would be a taxable event for Dorchester Hugoton's depositary receipt holders and would not give holders a choice to remain an equity holder and continue to maintain an interest in the business without paying tax on the sale of properties. If properties were not sold as a whole or in a limited number of major transactions, the process could last for a considerable period until all properties were disposed of, during which time the administrative overhead would have to be borne by a decreasing asset base as properties were sold. For these reasons, the general partners felt that the combination was a better course to pursue than to attempt to sell Dorchester Hugoton's properties for cash and to liquidate.

The general partners also considered the alternative of continuing Dorchester Hugoton in accordance with its current business plan. However, Dorchester Hugoton is severely constrained by limitations on its activities in its partnership agreement and by the high vote required to amend its partnership agreement to change those restrictions. As a result of those restrictions and regulatory requirements in Oklahoma and Kansas, Dorchester Hugoton's ability to grow is restricted to replacement of existing wells and fracture treatments and other production enhancements of existing wells. Consequently, for the long term, Dorchester Hugoton's asset base could continue to decline as its existing properties are produced.

During the period between March 1998 and December 2000, the general partners of Dorchester Hugoton contacted 12 parties and were contacted by representatives of a total of nine other parties (in addition to the representatives of Spinnaker and Republic) regarding a possible transaction. Most of the persons contacted by or contacting Dorchester Hugoton were in the upper executive levels in their respective organizations. Some of the 21 parties with whom contacts were established were in the oil and natural gas business, and these seemed to offer the potential for possible operating efficiencies and other enhancements of Dorchester Hugoton's business operations. The remainder were in unrelated businesses. Of the 21 parties, 15 were considerably larger than

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Dorchester Hugoton. During the 1998-2000 period, two of the parties executed confidentiality agreements and performed preliminary due diligence investigations, and one of them toured Dorchester Hugoton's field operations. After this initial interest, neither of these two parties pursued a strategic transaction with Dorchester Hugoton any further. Discussions did not progress with the remainder of the 21 parties for a variety of reasons. As a result, the combination is the only currently active alternative available other than continuing Dorchester Hugoton's current business.

Although there is no compelling necessity for Dorchester Hugoton to engage in a strategic transaction at the present time, the general partners felt that the environment created by the cessation of price controls, the absence of price-related litigation and generally higher market prices for gas make this a favorable time to engage in a strategic transaction, and for the reasons above believe that the combination will serve the interests of the Dorchester Hugoton depositary receipt holders better than continuing its business under its present business plan.

Investigation of Strategic Alternatives by Republic

Since its formation in 1993, the general partners of Republic have pursued numerous strategic alternatives with the goal of achieving the following objectives:

. operation as a partnership or similar flow-through entity for tax purposes;

. increases in oil and natural gas reserves and cash flow without increased administrative cost;

. exposure to public market valuations for oil and natural gas companies;

. elimination or avoidance of unrelated business taxable income for investors;

. increased liquidity for investors; and

. the ability to accomplish an alternative without triggering a taxable event.

In connection with their investigation of strategic alternatives, the general partners investigated and analyzed various business analogues, including publicly and privately held partnerships, master limited partnerships, royalty trusts and real estate investment trusts. Although potential strategic transaction participants were generally attracted to the high quality and geographic diversification of Republic's properties, the general partners of Republic found those potential participants to be unwilling to engage in negotiations because of Republic's current ownership structure and the existence of the Republic ORRIs. Furthermore, most owners of complementary assets are private entities and have tax and liquidity objectives similar to those stated above and, as a result, have been interested in receiving publicly traded securities in exchange for their interests.

The general partners considered the alternative of selling Republic's properties subject to the Republic ORRIs for cash and liquidating the partnership. As a procedural matter, the sale of properties and liquidation of Republic would generally require the consent of the Republic ORRI owners. A sale of its properties for cash and a liquidation would be a taxable event for Republic's general partners and would not give the general partners a choice to remain an equity holder and continue to maintain an interest in the business without paying tax on the sale of the properties. Because of the geographic diversity of Republic's properties, the sale of those properties might not command a higher price than if the properties were closely related geographically. In addition, if the properties were not sold as a whole or in a limited number of major transactions, the process could last for a considerable period of time until all properties were disposed of, during which time the administrative overhead would have to be borne by a decreasing asset base as properties were sold. The existence of the Republic ORRIs might also have an adverse impact on the general partners' ability to sell the Republic properties. For these reasons, the general partners of Republic felt that the combination was a better course to pursue than to attempt to sell Republic's properties for cash and to liquidate.

The general partners also considered the alternative of continuing Republic in accordance with its current business plan. Although the Republic ORRI owners would continue to receive the monthly payout under the Republic ORRIs, neither the general partners nor the Republic ORRI owners would own a liquid interest in

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Republic. In addition, without adding new reserves, production and cash flow are likely to decline. General and administrative expenses as a percentage of cash flow would increase, thereby reducing net operating margins.

In considering both the liquidation and continuation of Republic, the general partners also considered that the Republic ORRI owners currently do not have the benefit of an agreement similar to the Business Opportunities Agreement, which after the Republic reorganization and the combination will allow the Republic ORRI owners to participate indirectly as a unitholder of our partnership in certain acquisition opportunities subject to the Business Opportunities Agreement.

Due to the diversity of tax perspectives and operating strategies of the Republic general partners and Republic ORRI owners, the general partners believe that reorganization as a limited partnership followed by a tax-deferred exchange of Republic partnership interests for publicly traded securities of a partnership, such as the combination, would be the most likely transaction structure acceptable to both the general partners and the Republic ORRI owners.

Investigation of Strategic Alternatives by Spinnaker

Since its formation in 1996, the general partner of Spinnaker has pursued numerous strategic alternatives with the goal of achieving the following objectives:

. diversification of the geographic and geologic distribution of its properties;

. increases in oil and natural gas reserves and cash flow without increased administrative cost;

. exposure to public market valuations for oil and natural gas companies;

. increased liquidity for investors; and

. the ability to accomplish an alternative without triggering a taxable event.

In connection with its investigation of strategic alternatives, the general partner investigated and analyzed various business analogues, including publicly and privately held partnerships, master limited partnerships, royalty trusts and real estate investment trusts. Although potential strategic transaction participants were generally attracted to the high quality and geographic diversification of Spinnaker's properties, the general partner of Spinnaker found those potential participants to be unwilling to engage in negotiations because Spinnaker's status as a privately held partnership. Furthermore, most owners of complementary assets are private entities and have tax and liquidity objectives similar to those stated above and, as a result, have been interested in receiving publicly traded securities in exchange for their interests.

The general partner engaged in extended negotiations with three parties with respect to a strategic transaction designed to achieve some or all of these objectives. These negotiations resulted in one completed transaction in which Spinnaker reorganized as a limited partnership in connection with the non-taxable contribution of properties. Please read "Information Concerning Spinnaker--General" for more information regarding this transaction.

The general partner considered the alternative of selling Spinnaker's properties for cash and liquidating the partnership. As a procedural matter, the sale of properties and liquidation of Spinnaker would require the approval of limited partners holding at least 85.9883% of the sharing percentages of Spinnaker. A sale of its properties for cash and a liquidation would be a taxable event for Spinnaker's partners and would not give the partners a choice to remain an equity holder and continue to maintain an interest in the business without paying tax on the sale of the properties. Because of the geographic diversity of Spinnaker's properties, the sale of those properties might not command a higher price than if the properties were closely related geographically. In addition, if the properties were not sold as a whole or in a limited number of major transactions, the process could last for a considerable period of time until all properties were disposed of, during which time the

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administrative overhead would have to be borne by a decreasing asset base as properties were sold. For these reasons, the general partner of Spinnaker felt that the combination was a better course to pursue than to attempt to sell Spinnaker's properties for cash and to liquidate.

The general partner also considered the alternative of continuing Spinnaker in accordance with its current business plan. While Spinnaker's properties are relatively diverse geographically, a significant portion of those properties are located in a relatively small area in south Texas and Louisiana. As a result, the continuation of Spinnaker in accordance with its current business plan involves significant reliance on the performance of this group of properties, while the combination would mitigate the reliance on one or a few groups of properties. Further, although the Spinnaker partners would continue to receive monthly cash distributions to the extent determined by the general partner, the Spinnaker partners would not own a liquid interest in Spinnaker. In addition, without adding new reserves, production and cash flow are likely to decline. General and administrative expenses as a percentage of cash flow would increase, thereby reducing net operating margins.

In considering both the liquidation and continuation of Spinnaker, the general partner also considered that the Spinnaker limited partners currently do not have the benefit of an agreement similar to the Business Opportunities Agreement, which after the combination will allow the Spinnaker limited partners to participate indirectly as a unitholder of our partnership in certain acquisition opportunities subject to the Business Opportunities Agreement.

Due to the diversity of tax perspectives and operating strategies of the Spinnaker partners, the general partner believes that a tax-deferred exchange of Spinnaker partnership interests for publicly traded securities of a partnership, such as the combination, would be the most likely transaction structure acceptable to all of Spinnaker's partners.

Discussions Between Dorchester Hugoton, Republic and Spinnaker

On March 1, 2000, Messrs. Peak and Raley, representing the general partners of Dorchester Hugoton, met with William Casey McManemin, who represented Republic and Spinnaker. Neither Mr. Raley nor Mr. Peak had met Mr. McManemin previously or were familiar with Spinnaker or Republic, but upon inquiry learned that both Republic and Spinnaker were private partnerships that owned extensive oil and natural gas mineral and royalty interests. Mr. McManemin was generally familiar with Dorchester Hugoton although his familiarity with Dorchester Hugoton's business and operations was limited to publicly available information. During the meeting the participants discussed in general terms the businesses and assets of their partnerships and their objectives. Based on these discussions the parties expressed a mutual interest in pursuing further discussions.

On March 14, 2000, Messrs. Peak, Raley and McManemin met again to further explore their objectives. Mr. McManemin indicated that the goals of Republic and Spinnaker were to become a publicly traded entity, such as a partnership, that could:

. use partnership units to acquire additional royalty interests;

. have a life of 25 years or more;

. distribute a large portion of its revenues to its unitholders; and

. use Republic's and Spinnaker's large, undeveloped acreage to fuel growth of royalty and bonus income.

The parties exchanged and reviewed certain information concerning revenues and property ownership and locations. Based on these conversations and the review of this information, the parties' representatives executed confidentiality agreements on March 19, 2000 and April 6, 2000. During May 2000, lists of documents to be reviewed for due diligence purposes were prepared and exchanged, and representatives of the parties had several meetings concerned with their respective due diligence investigations.

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On May 17, 2000, Republic and Spinnaker presented Dorchester Hugoton with an analysis they had prepared of a possible basis for determining the shares allocable to the combining partnerships in a combined enterprise. That analysis used reserve studies of Republic and Spinnaker dated January 1, 2000 by Huddleston & Co., Inc. and of Dorchester Hugoton dated January 1, 2000 by Calhoun, Blair and Associates for a portion of the analysis. The analysis prepared by Republic and Spinnaker considered various factors. Republic and Spinnaker did not present the analysis as a proposal, and Dorchester Hugoton did not respond to either the method used or the resulting ownership ratios.

Following this, Dorchester Hugoton engaged Calhoun, Blair and Associates to review the reserve studies of Republic and Spinnaker done by Huddleston & Co., Inc. and met with its attorneys concerning how a business combination might be structured and to discuss the analysis presented by Republic and Spinnaker. In addition, during June 2000, the parties continued to meet and to perform their respective due diligence investigations, exchanging records and documents and engaging petroleum landmen to review title and payment matters and accountants to review financial and other records.

In July 2000, the parties agreed, for purposes of further analysis, to adjust their January 1, 2000 reserve studies using a common set of market prices for natural gas and crude oil equal to their average prices quoted on the New York Mercantile Exchange on July 1, 2000 through the last future date for which prices were quoted and then escalated 3% per year. Each party was responsible for additional adjustments to the common set of prices to more accurately reflect price adjustments for transportation and quality. The January 2000 Republic and Spinnaker reserve studies had separately stated probable and possible reserves as well as proved developed producing reserves and proved undeveloped reserves. Dorchester Hugoton's January 2000 reserve study had included only proved developed producing reserves. Because its general partners felt that Dorchester Hugoton's reserves potentially would be enhanced by additional fracture treatments, the reserve study was also adjusted to separately estimate the potential increase in reserves from the successful fracture treatment program then underway. The results of the adjusted reserve studies were provided by Republic and Spinnaker on August 22, 2000 and by Dorchester Hugoton on October 9, 2000.

During the Summer of 2000 discussions continued between the parties and their attorneys with respect to how the possible transaction might be structured. By September 2000, the parties' landmen and accountants had concluded their reviews and reported their findings. None of the combining partnerships viewed the findings as raising any serious deficiencies.

On October 13, 2000, Dorchester Hugoton prepared a further analysis, based upon the adjusted January 1, 2000 adjusted reserve reports by Calhoun Blair and Associates with respect to Dorchester Hugoton's reserves and by Huddleston & Co., Inc. with respect to Republic's and Spinnaker's reserves, which included all categories of reserves, including probable and possible, and the results of fracture treatments on certain of Dorchester Hugoton's properties. The agreed upon New York Mercantile Exchange oil and natural gas pricing assumptions were used for all properties. Using the same factors as used in the May 17, 2000 analysis discussed above, this revised analysis produced an allocation of ownership in a combined entity of Dorchester Hugoton - 38%, Republic - 41% and Spinnaker 21%. The results of this analysis were provided to representatives of Republic and Spinnaker for comparative purposes, but were not presented as a proposal.

In November 2000, Messrs. Peak and Raley met with Mr. Frederick M. Smith, II and Mr. H.C. Allen, Jr., principals with Mr. McManemin in Smith Allen Oil & Gas, Inc., the general partner of Spinnaker, and in SAM Partners, Ltd., a co-general partner of Republic, and with Mr. Robert C. Vaughn, a principal in Vaughn Petroleum, Inc., the other co-general partner of Republic, to review the overall status of the discussions and to become acquainted. Later in November 2000, the October 13, 2000 analysis was further revised by Dorchester Hugoton to use only proved developed producing reserves and to exclude proved non-producing, proved undeveloped and possible reserves and to exclude the projected effect of fracture treatment increases. The pricing assumptions and other factors were not changed. This analysis produced the same ownership percentages in a combined entity that the October 13, 2000 analysis had produced. The results of this further analysis were also provided to representatives of Republic and Spinnaker, but it was not presented as a proposal.

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Subsequently, the combining partnerships had their two reservoir engineering firms re-review the other engineering firm's work. Based on those reviews, on December 4, 2000, two different sets of modifications were made to the October 13, 2000 analysis for comparative purposes. Both used the same factors as the previous analyses. One of the December 4, 2000 analyses assumed no change to the Republic and Spinnaker reserves, which included all categories of reserves, and reduced Dorchester Hugoton's projected reserves from facture treating by one-third. This resulted in an allocation of ownership in a combined entity of Dorchester Hugoton--37%, Republic--42% and Spinnaker--21%. The other December 4, 2000 analysis assumed no change to Dorchester Hugoton's reserves, which included additional reserves based on anticipated fracture treatments, and reduced Republic's and Spinnaker's combined discounted future net reserves by 12% in order to allow for the possibility of greater than anticipated production declines in some areas. This resulted in an allocation of 40% to Dorchester Hugoton and 60% to Republic and Spinnaker combined. The results of these analyses were shared, but no party presented either of these analyses as a proposal. All parties recognized that none of the analyses done to date had included a value attributable to Dorchester Hugoton's status as a public company.

On December 8, 2000, an additional analysis was prepared by Dorchester Hugoton that suggested a methodology of determining the value to a new entity of succeeding to Dorchester Hugoton's status as a public company. That methodology considered the value of avoiding a 9% underwriting fee on a company with a projected market capitalization equal to Spinnaker's and Republic's projected percentage ownership of the combined entity. Dorchester Hugoton used a 9% assumed underwriting fee, which it believed was typical of underwriting fees in initial public offerings. The other factors were unchanged. Based on these assumptions, the ownership ratio produced was Dorchester Hugoton--41% and Republic and Spinnaker combined--59%.

In reviewing the various analysis that had been done, the parties observed that varying the weighting assigned to the various factors considered in these analyses seemed to make only minor differences in the results. Other factors considered by the parties in addition to the December 8, 2000 analysis included the unassigned value of potential land surface value and timber sales, exploitation potential on producing properties, value of gas gathering, dehydration and compression facilities, potential lease bonus receipts from undeveloped property, possible lower per unitholder costs of Scheduled K-1 tax statement preparation, acquisition possibilities (especially using publicly traded units as currency), no indebtedness, broader geographic basis, large undeveloped, unleased acreage holdings in numerous locations and certain pending litigation of Republic. The parties assigned no specific weights to any of these factors and the parties considered them generally along with the analyses discussed above.

Reviewing all of the analyses that had been conducted to date and considering the other factors discussed above, the representatives of the combining partnerships concluded that a relative percentage ownership of the combined entity on the basis of Dorchester Hugoton--39%, Republic 41% and Spinnaker--20% would be acceptable, if all other issues concerning the combination could be resolved, including the transaction not being a taxable event, agreement upon an appropriate structure for the combined entity and its general partner and depletion amounts for various unitholders in the combined entity being acceptable. The parties decided to attempt to arrive at a definitive agreement that satisfied these objectives.

Throughout the process of their discussions, the representatives of the combining partnerships from time to time discussed strategic considerations in the context of various other business analogues, including publicly and privately traded limited partnerships, master limited partnerships, royalty trusts and real estate investment trusts, in order to further refine the structure of a proposed transaction and the business model of the resulting company.

During April 2001, Messrs. McManemin, Allen, Raley and Mr. John L. Dannelley, Dorchester Hugoton's production manager, met in Guymon, Oklahoma and toured Dorchester Hugoton's facilities.

The Letter of Intent

During June and July 2001, representatives of the combining partnerships negotiated the terms of a non-binding letter of intent for the proposed combination. On July 5, 2001, following interviews with other

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candidates, Dorchester Hugoton engaged Mr. Bruce Lazier, a Dallas, Texas investment banker, to examine any proposed transaction from the standpoint of its fairness from a financial point of view to the depositary receipt holders of Dorchester Hugoton. Also, on July 5, 2001, Dorchester Hugoton concluded a review of the January 1, 2001 reserve studies of Republic and Spinnaker by Huddleston & Co., Inc., which had recently become available, and compared those results with Dorchester Hugoton's reserve study prepared as of January 1, 2001 by Calhoun, Blair and Associates. Only proved developed producing reserves were compared as the Dorchester Hugoton reserve study contained only that category.

The results of the comparison showed that there were no material shifts in the relative reserves of the combining partnerships. Accordingly, in the judgment of the general partners of Dorchester Hugoton the January 1, 2001 reserve status did not warrant a re-evaluation of the shares of the combined entity to be held by Dorchester Hugoton, Republic and Spinnaker.

Between July 10 and 26, 2001, the members of Dorchester Hugoton's Advisory Committee and Mr. Lazier were furnished with material concerning the proposed combination, including a draft of the proposed letter of intent and a number of updated revisions, a memorandum concerning the negotiation of the letter of intent, a booklet containing the analyses of the reserve studies and the resulting new entity ownership percentages by the combining partnerships, copies of the reserve studies, an analysis of Dorchester Hugoton's general partners' compensation before and after the proposed combination, information concerning Republic and Spinnaker and information concerning Mr. Bruce E. Lazier for their review as the negotiations between Dorchester Hugoton, Republic and Spinnaker progressed.

On July 27, 2001, the Advisory Committee of Dorchester Hugoton met to consider the non-binding letter of intent. The Advisory Committee heard presentations from and asked questions of:

. Mr. Raley, regarding the proposed combination, how the proposed ownership percentages of the combining partnerships were determined and the general partners' compensation before and after the combination;

. Mr. McManemin, regarding the assets, operations, business plans and philosophies of Republic and Spinnaker;

. Messrs. Raley and McManemin, regarding the business plan and philosophy contemplated for the proposed combined entity;

. Tax counsel to Dorchester Hugoton, regarding the tax aspects of the proposed combination and the proposed combined entity; and

. Counsel to Dorchester Hugoton, regarding the role of the Advisory Committee, the legal aspects of the proposed transaction and those aspects of it that might be deemed to involve conflicts of interest on the part of the general partners of Dorchester Hugoton.

In addition, at the July 27, 2001 meeting, Mr. Lazier made an oral presentation concerning his fairness opinion and furnished a draft of his opinion for review by the Advisory Committee. The Advisory Committee then excused all other participants from the meeting so that they could discuss the matters presented. The Advisory Committee then recessed the meeting for the weekend to further consider the matters that had been presented. The Advisory Committee reconvened the meeting by conference telephone call on Monday, July
30. Mr. Lazier's fairness opinion dated July 30, 2001 was delivered in substantially the same form as the draft previously presented. After further discussion, the Advisory Committee adopted resolutions:

. finding the proposed combination to be fair to and in the best interests of the depositary receipt holders and Dorchester Hugoton;

. approving the proposed combination, including those elements of it that might be deemed to be with affiliates of the general partners or in which the general partners may be deemed to have an interest,

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subject to the further approval of definitive agreements with respect to the combination by the Advisory Committee;

. approving the proposed form of the letter of intent; and

. ratifying the appointment of Mr. Lazier to render the fairness opinion.

The general partners of Dorchester Hugoton then adopted resolutions approving the proposed combination and the non-binding letter of intent.

The general partners of Republic then adopted resolutions approving the proposed combination and the non-binding letter of intent.

The general of Spinnaker then adopted resolutions approving the proposed combination and the non-binding letter of intent.

All parties executed the non-binding letter of intent on July 30, 2001. Although it was contemplated that the definitive agreements would contain provisions restricting the ability of the parties to solicit and respond to alternative acquisition proposals and for the payment of a termination fee in certain circumstances involving an alternative acquisition proposal, the letter of intent contained no such provisions that would be effective prior to the execution of definitive agreements. On August 2, 2001 Dorchester Hugoton issued a news release with respect to the signing of the letter of intent and the proposed transaction and filed reports with the Securities and Exchange Commission with the news release and a copy of the letter of intent as exhibits.

The Definitive Agreements

Counsel for Dorchester Hugoton and for Republic and Spinnaker resumed preparation of definitive transaction documentation, and the parties and their counsel participated in a number of meetings to negotiate the terms of the definitive agreements. On October 25 and then again on December 2, 2001, the parties extended the term of the letter of intent to permit the completion of negotiations.

During the period from the announcement of the letter of intent on July 30, 2001 to the date the definitive agreements were signed on December 13, 2001, none of the combining partnerships were contacted by any third parties with respect to any acquisition proposal or any request for information in connection with a possible acquisition proposal, although Dorchester Hugoton did receive on September 6, 2001, one unsolicited form letter sent by a third party to a number of public companies seeking to determine if there was interest in a reverse merger. No additional contacts with the party occurred.

During November and December 2001 drafts of the definitive agreements and projections of general and administrative costs, using a 5% limitation on management expenses, memoranda regarding projected directors' and officers' insurance costs and tax matters were furnished to the members of the Advisory Committee of Dorchester Hugoton for their review. On November 27, 2001 the Advisory Committee of Dorchester Hugoton met to review and discuss the definitive agreements in draft form. The Advisory Committee heard presentations from and asked questions of:

. Mr. Raley, with respect to general and administrative cost projections and directors' and officers' liability insurance cost projections;

. Counsel to Dorchester Hugoton, with respect to the role of the Advisory Committee, the structure of the proposed combination, a description of the principal terms of each of the definitive agreements, a description of those elements of the definitive agreement and the combination in which the general partners or their affiliates might be deemed to have an interest;

. Tax counsel to Dorchester Hugoton, regarding the tax aspects of the proposed combination agreement and the proposed combined entity; and

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. Mr. Lazier, who made an oral presentation regarding an update of his fairness opinion and delivered a copy of his revised/updated draft opinion to the Committee members.

The Advisory Committee took no action at this meeting pending finalization of the definitive agreements. As the definitive agreements were negotiated, revised drafts were circulated to the Advisory Committee members and to Mr. Lazier for their review.

On December 13, 2001 the Advisory Committee met again to consider the definitive agreements, which were in substantially final form. Mr. Raley and counsel to Dorchester Hugoton outlined the principal changes in the definitive agreements from the drafts reviewed at the November 27, 2001 meeting and responded to questions from the members of the Committee. Mr. Lazier delivered his written fairness opinion concerning the fairness from a financial point of view of the combination to the holders of depositary receipts. The Advisory Committee then unanimously adopted resolutions:

. finding the proposed combination to be fair to and in the best interests of the depositary receipt holders and Dorchester Hugoton;

. approving the proposed combination, including those elements of it that might be deemed to be with affiliates of the general partners or in which the general partners may be deemed to have an interest; and

. approving the proposed form of the definitive agreements, including the Combination Agreement, our Partnership Agreement, the Business Opportunities Agreement, the conveyances to us and Dorchester Minerals Operating LP, the Contribution Agreement and the partnership agreement of Dorchester Minerals Management LP and the limited liability company agreement of Dorchester Minerals Management GP LLC.

The general partners of Dorchester Hugoton then adopted resolutions approving the proposed combination and the definitive agreements on December 13, 2001.

The general partners of Republic adopted resolutions approving the proposed combination and the definitive agreements on December 13, 2001.

The general partner of Spinnaker adopted resolutions approving the proposed combination and the definitive agreements on December 13, 2001.

The parties executed the Combination Agreement, the Business Opportunities Agreement and the Contribution Agreement on December 13, 2001, and on December 14, 2001, Dorchester Hugoton issued a news release and filed reports with the Securities and Exchange Commission with the news release and definitive agreements as exhibits.

Combination Exchange Ratios and Consideration Allocated to General Partner Interests

General

As described above under "--Background of the Combination," the general partners of the combining partnerships have agreed in the Combination Agreement to the manner in which interests in our partnership will be allocated to partners in the combining partnerships. These agreements were reached as a result of arm's-length negotiations. Each general partner of a combining partnership, or in the case of Dorchester Hugoton and Republic, both general partners acting together, independently assessed the relative merits of the proposed combination and considered the combination exchange ratios from the perspective of its partnership. Although there is overlap in the ownership and management of the general partner of Spinnaker and one of the general partners of Republic, the other general partner of Republic is not so affiliated and participated in the negotiations. However, the other general partner is the general partner of a limited partnership that is a limited partner of Spinnaker.

During such negotiations, the parties did not assign a value to each combining partnership or to categories of their assets, but considered multiple factors, which are described above under "--Background of the

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Combination." As described in that section, the representatives of the combining partnerships agreed that the consideration to be paid in the consideration would reflect that Republic as an enterprise represented 41% of the combined company's value, Dorchester Hugoton as an enterprise represented 39% of the combined value and Spinnaker as an enterprise represented 20% of the combined value. Below, we refer to these percentages as the "preliminary allocations." As described in more detail below, starting from these preliminary allocations, our common units will initially be held in approximately the following proportions as a result of the combination:

. 40.51% by former limited partners of Republic;

. 39.73% by former limited partners of Dorchester Hugoton; and

. 19.76% by former limited partners of Spinnaker.

Below, we refer to this allocation of common units to be received by the limited partners of each of the combining partnerships as the "combination exchange ratios."

The combination exchange ratios are not affected by any combining partnership's liabilities. Each combining partnership has agreed in the Combination Agreement to use its reasonable best efforts to determine the amounts of and satisfy any undisputed liabilities accrued through the closing of the combination which are due and payable in the ordinary course of the combining partnership's business. See "The Combination--Certain Covenants" on page 63 for a more complete description of the combining partnerships obligations.

Derivation of Combination Exchange Ratios from Preliminary Allocations

In deriving the combination exchange ratios from the preliminary allocations, the general partners of the combining partnerships assumed that in the Republic and Spinnaker mergers into our partnership, the limited partners of Republic and Spinnaker should receive common units representing 96% of the respective enterprise
values of those two partnerships in respect of their limited partnership interests, with general partners receiving general partnership interests representing the remaining 4% of the enterprise value. The 4% interest of the general partners of Republic and Spinnaker is approximately the same as the interest of the general partners of Dorchester Hugoton in the net income of Dorchester Hugoton, taking into account their 1% general partner interest and the approximately 3% interest in the revenues of Dorchester Hugoton's working interest properties through the receipt of management and other fees. See "The Combination--Preparatory Steps" for information regarding the reorganizations of Republic and Spinnaker that will result in this 96% and 4% split.

The general partners also assumed in the derivation that in Dorchester Hugoton's sale of its assets to our partnership and liquidation, since the general partners of Dorchester Hugoton would be treated the same as limited partners in the liquidation, common units representing 100% of the Dorchester Hugoton enterprise value would need to be issued to Dorchester Hugoton. In order for the general partners of Dorchester Hugoton to receive general partnership interests in the combined entity, the common units those general partners received in liquidation in respect of their general partner interests in Dorchester Hugoton, which would represent approximately one percent of the common units issued to Dorchester Hugoton, would have to be contributed to our general partner and converted into general partnership interests in us. See "The Combination--Transfer of Assets by Dorchester Hugoton and Liquidation--Transfer of Dorchester Hugoton ORRIs and Liquidation" for more information regarding the liquidation provisions of the Dorchester Hugoton partnership agreement.

Using the preliminary allocations as substitutes for actual enterprise values, the combination ratios were mathematically derived after giving effect to the issuances of common units in the Republic and Spinnaker mergers and in the Dorchester Hugoton sale and liquidation, as well as the effect of the conversion of 1% of those initially-issued common units to general partnership interests.

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Consideration Allocated to General Partners

At the time of the combination, the general partner or partners of Republic and Spinnaker will collectively own a 4% interest in each of those combining partnerships' capital and profits; accordingly, in the mergers of those combining partnerships, the general partner or partners of each partnership will initially receive in the aggregate a 4% interest, in our partnership's capital and profits, relating solely to the assets previously owned by that combining partnership. At the time of the combination, the general partners of Dorchester Hugoton will own a 1% interest in the capital and profits of Dorchester Hugoton; accordingly, the common units they receive in the liquidation in respect of their general partnership interests will be converted into an aggregate 1% interest, in our partnership's capital and profits, relating solely to the assets previously owned by Dorchester Hugoton. As a result of the transactions described under "The Combination--Contributions to Dorchester Minerals Management LP," these interests will be consolidated in our general partner.

The general partners of the combining partnerships also will receive common units in the combination in respect of any limited partnership interests in the combining partnerships that they may own, on the same terms as other limited partners.

Reasons for the Combination

Dorchester Hugoton's Reasons for the Combination.

The general partners of Dorchester Hugoton have both approved the combination and believe that the combination is fair to and in the best interests of Dorchester Hugoton and its depositary receipt holders. Dorchester Hugoton's Advisory Committee has reviewed the terms of the combination, including, specifically, those in which the general partners or their affiliates may be deemed to have an interest, and has found such terms to be fair to and in the best interests of Dorchester Hugoton and its depositary receipt holders.

The general partners recommend that the holders of Dorchester Hugoton's depositary receipts vote "FOR" the approval of the combination.

The principal reasons for the general partners' recommendation are:

. opportunities for growth--both from the large amount of unleased undeveloped property and acquisition of minerals and royalties using partnership units;

. the diversification of risk--lessening exposure to changes by a single state or in a single field;

. the ability of pension funds, IRAs and other tax exempt investors to invest without exposure to unrelated business taxable income;

. maintenance of current tax advantages of being a partnership;

. the proposed combination can be accomplished generally without triggering a taxable event;

. potential gains in efficiency in such areas as Schedule K-1 tax statement preparation and in preparation costs for public company filings; and

. addition of complementary skills to management, including broader areas of expertise and advice from the management group.

The reasons stated above are the principal reasons the general partners are recommending the combination, but in their review of strategic alternatives and of the combination in particular, the general partners of Dorchester Hugoton considered a number of factors, including the following.

. The general partners considered the proved, developed producing reserves held by Republic and Spinnaker and the large number of wells and the diverse locations of those properties which they believe

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.will diversify the risk of concentration of property ownership in one general location that presently applies to Dorchester Hugoton.

. The general partners considered the significant amount of proved undeveloped reserves and probable and possible reserves, which include large amounts of unleased undeveloped mineral acreage, held by Republic and Spinnaker, and the possible future growth potential for the combined businesses from these existing properties without significant cash outlays due to the nature of the royalty interests held by Republic and Spinnaker.

. The general partners considered the reserve reports of Huddleston & Co., Inc. and Calhoun Blair and Associates on the proved, developed producing properties of Republic, Spinnaker and Dorchester Hugoton as well as with respect to other categories of reserves.

. The general partners considered our partnership's potential for additional growth through the acquisition of additional properties, which Dorchester Hugoton is presently restricted from doing except in very limited circumstances. The general partners also considered the restrictions on future acquisitions in our Partnership Agreement due to the limit on the amount of common units that may be used for acquisitions without the need for unitholder approval and due to the limit on the amount of cash that may be used for acquisition purposes.

. The general partners considered that our partnership would be structured so as to permit investment in our common units by certain types of investors such as pension funds and IRAs who presently may be unwilling to invest in Dorchester Hugoton because of unrelated business taxable income issues.

. The general partners considered that the combination would add to the management of our partnership additional executive management with skills that complement those of Dorchester Hugoton's management.

. The general partners considered the fact that the combination could be structured as a non-taxable transaction as compared to some other transactions such as a sale of Dorchester Hugoton's properties for cash and a liquidation.

. The general partners considered the fact that litigation presently affects certain of Republic's properties and that Dorchester Minerals would be indemnified with respect to that litigation.

. The general partners considered that a method of depletion was available for our partnership that, in the opinion of the general partners, would not materially disadvantage any particular group of limited partners.

. The general partners considered that two factors which they believe adversely affected the market price for Dorchester Hugoton depositary receipts in the past--governmental price controls and related litigation--no longer affect Dorchester Hugoton.

. The general partners considered the ability of persons affiliated with Dorchester Minerals Management LP, our general partner, to engage in the oil and natural gas business in potential competition with our partnership and that certain of such persons are subject to the Business Opportunities Agreement.

. The general partners considered that certain aspects of the combination and the ownership structure of our partnership, its general partner and their affiliates will involve potential conflicts of interest with the general partners or their affiliates and the fact that the Advisory Committee has reviewed and approved the combination and the matters presenting a potential for such a conflict.

. The general partners considered that the total compensation received by the general partners under the provisions of the existing Dorchester Hugoton partnership agreement has been greater than or equal to the compensation that Dorchester Hugoton would have paid the general partners under a formula like that used to compensate our general partners.

. The general partners considered the fairness opinion of Bruce E. Lazier, P.E. that the combination was fair to Dorchester Hugoton and to the holders of depositary receipts from a financial viewpoint.

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. The general partners considered the current and long term market environment for Dorchester Hugoton's and our partnership's businesses, perceived industry trends and anticipated oil and natural gas price volatility.

. The general partners also recognized the potential for a single state's income or severance tax policy to affect Dorchester Hugoton more than our partnership due to the latter's more diverse holdings but also recognized the potential for us to have to file tax returns and pay taxes in a larger number of states than Dorchester Hugoton.

. The general partners considered the terms of each of the definitive agreements, including the conditions to the obligations of each of the parties to consummate the combination, and the rights of termination of the parties.

. The general partners considered that holders of Dorchester Hugoton's depositary receipts would be given voting rights on the proposed combination, as well as contractual dissenters' rights and the opportunity to receive an appraised value for their depositary receipts.

. The general partners considered historical and recent market prices for the depositary receipts and that Dorchester Hugoton has essentially no debt and, consequently, no urgency to engage in a transaction.

. The general partners considered the reciprocal restrictions on soliciting or cooperating with proposals for alternative transactions and for the payment of a termination fee in connection with terminations related to alternative transactions, as well as the ability of the general partners of the combining partnerships to terminate the definitive agreements for fiduciary reasons. The general partners recognized that these provisions could decrease the likelihood that a third party would offer to acquire Dorchester Hugoton. However, the general partners believed that the provisions included in the definitive agreements were not likely to preclude an interested party from making a proposal to Dorchester Hugoton. The general partners also considered that prior efforts to find a third party interested in pursuing a strategic transaction with Dorchester Hugoton consistent with what the general partners believed the depositary receipt holders' objectives to be had not proved to be successful, and that no third party had presented a specific interest since the announcement of the non-binding letter of intent.

. The general partners considered that the receipt of our common units potentially exposes the depositary receipt holders to the potential benefits and to the risk of fluctuations in market prices instead of having a fixed liquidated amount of consideration as would be the case in a taxable cash transaction. The general partners also considered that a cash transaction would preclude its depositary receipt holders from participating in potential future growth of the combined enterprise.

. The general partners also considered other possible alternatives to the combination, such as a merger with an unrelated party, a cash sale and liquidation, and remaining independent and continuing its business, and the potential value to depositary receipt holders of such alternate transactions.

. The general partners considered the fact that even though Dorchester Hugoton has publicly indicated since 1998 that it is reviewing strategic alternatives and has contacted a number of potential partners for a strategic transaction, there has been limited interest by others in such a transaction by others consistent with what the general partners believed the depositary receipt holders' objectives to be, and Dorchester Hugoton has not been successful in pursuing any other opportunities that would yield similar benefits to its depositary receipt holders.

The foregoing discussion of the factors and information considered by the general partners is not meant to be exhaustive, but the general partners believe that it includes all material factors considered by them. The general partners did not find it practical to, and did not, quantify or otherwise attempt to assign relative weights to the specific factors considered in reaching its determination. Rather the general partners considered their determinations and recommendation as being based upon the totality of the information presented to and reviewed by them.

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Opinion of Dorchester Hugoton's Financial Advisor

Pursuant to an engagement letter signed July 5, 2001, Dorchester Hugoton retained Bruce E. Lazier, P.E. to assist Dorchester Hugoton with the evaluation of the combination and to provide his opinion as to the fairness, from a financial viewpoint, of the combination to Dorchester Hugoton and the holders of its depositary receipts. At the meeting of the Advisory Committee of Dorchester Hugoton on July 27, 2001, prior to execution of the non-binding letter of intent with respect to the combination, Mr. Lazier gave his oral opinion, subsequently confirmed in writing on July 30, 2001, to Dorchester Hugoton, its general partners, members of the Advisory Committee and depositary receipt holders, that as of that date and on the basis of the matters described in that opinion, the combination was fair, from a financial viewpoint, to Dorchester Hugoton and its depositary receipt holders. In addition, at the meetings of the Advisory Committee on November 27, 2001 and December 13, 2001, prior to the execution of the definitive agreements with respect to the combination, Mr. Lazier gave his oral opinions, subsequently confirmed and updated in writing on December 13, 2001, to Dorchester Hugoton, its general partners, members of the Advisory Committee and depositary receipt holders, that as of that date and on the basis of the matters described in that opinion, the combination was fair, from a financial point of view, to Dorchester Hugoton and its depositary receipt holders.

The number and ratio of our common units to be received by the holders of depositary receipts of Dorchester Hugoton was determined through negotiations among the general partners of Dorchester Hugoton, Republic and Spinnaker. Mr. Lazier was not asked to, and did not recommend to, Dorchester Hugoton that any specific amount of our common units constituted the appropriate amount of consideration in the combination.

The full text of the written opinions of Bruce E. Lazier, P.E. dated July 30 and December 13, 2001, which set forth the assumptions made, matters considered and limits on the review undertaken, are attached as Appendix A-1 and A-2 to this document. Mr. Lazier has consented to the use of his written opinion in this document. No limitations were placed by Dorchester Hugoton's general partners on Mr. Lazier with respect to the investigations made or procedures followed by him in furnishing his opinion. The general partners of Dorchester Hugoton encourage you to read the opinion carefully and in its entirety.

Mr. Lazier's opinion is addressed to Dorchester Hugoton, its general partners, its Advisory Committee and its depositary receipt holders and is limited to the fairness, from a financial viewpoint, of the combination to Dorchester Hugoton and its depositary receipt holders, and Mr. Lazier expressed no opinion as to the merits of the underlying decision by Dorchester Hugoton to engage in the combination. Mr. Lazier's opinion does not constitute a recommendation to any holder of a depositary receipt as to how to vote with respect to the combination. The summary of Mr. Lazier's opinion set forth in this document is qualified in its entirety by reference to the full text of the opinion.

In arriving at his opinion dated December 13, 2001, Mr. Lazier reviewed, among other things:

. the current state of the domestic and international oil and natural gas industry;

. the present relative value of the net assets, reserves, future production and anticipated future cash flow of the combining partnerships;

. sensitivities and revised sensitivities of gas prices, reserves, Dorchester Hugoton's assets and discount rates to the value of our partnership;

. "Estimates of Gas Reserves," with respect to Dorchester Hugoton dated January 17, 2001 and prepared by Calhoun, Blair & Associates;

. "Republic Royalty Company and Spinnaker Royalty Company, L.P., Estimated Reserves and Future Net Revenue, as of January 1, 2001" prepared by Huddleston & Co., Inc.;

. the revised reserve study by Calhoun, Blair and Associates, dated August 14, 2001, accounting for the acquisition of the production payment by Dorchester Hugoton;

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. summary of reserves of Republic and Spinnaker received from Dorchester Hugoton, dated July 5, 2001;

. opening calculations prepared by Republic and Spinnaker, based on January 1, 2000 SEC type reserve studies and projected year 2000 income;

. Republic and Spinnaker reserve studies, dated July 1, 2000, at agreed upon escalated prices;

. Dorchester Hugoton reserve study, dated July 1, 2000, at agreed upon escalated prices;

. various reserve studies and analyses prepared by Dorchester Hugoton;

. rework of May 17, 2000 calculation by Dorchester Hugoton using July 1, 2000 reserve studies including probable and possible reserves;

. rework of May 17, 2000 calculation by Dorchester Hugoton using July 1, 2000 reserve studies including proved producing reserves only;

. two reworks of October and November 2000 calculations by Dorchester Hugoton;

. adjustment of October 2000 calculations by Dorchester Hugoton for the value of already being publicly traded;

. 2000 Net Cash Flow Comparison--revised February 21, 2001;

. Annual Report of Dorchester Hugoton on Form 10-K for the year ended December 31, 2000, Quarterly Reports of Dorchester Hugoton on Form 10-Q for the quarters ended March 31, 2001, June 30, 2001 and September 30, 2001 and other publicly-available information concerning Dorchester Hugoton;

. balance sheets and income statements, dated June 30, 2001 and September 30, 2001, of Republic and Spinnaker;

. draft letter of intent;

. the draft of our Partnership Agreement;

. the draft Combination Agreement pursuant to which the combining partnerships will combine;

. the draft Contribution Agreement pursuant to which the general partners of the combining partnerships will contribute certain limited and/or general partner interests received in the combination by the generals partner of Dorchester Hugoton, Republic and Spinnaker;

. drafts of the assignments, conveyances and assumption agreements from Dorchester Hugoton to our partnership and Dorchester Minerals Operating LP;

. the draft Amended and Restated Limited Partnership Agreement of Dorchester Minerals Management LP;

. the draft Amended and Restated Limited Liability Company Agreement of Dorchester Minerals Management GP LLC;

. the draft Transfer Restriction Agreement of Dorchester Minerals Management LP and Dorchester Minerals Management GP LLC which governs the transfer of interests therein;

. The draft Business Opportunities Agreement that sets forth the rights and responsibilities of Dorchester Minerals, Dorchester Minerals Management LP and related parties with respect to business opportunities; and

. various transactions involving acquisitions of oil and natural gas properties through merger and/or purchase and the trading history of public companies subsequent to such acquisitions.

In addition, Mr. Lazier has held discussions with the general partners of Dorchester Hugoton with respect to certain aspects of the combination, the past and current operations of Dorchester Hugoton, the financial condition

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and future prospects of Dorchester Hugoton and certain other matters Mr. Lazier believed necessary or appropriate to his inquiry. Mr. Lazier reviewed and considered such other information as he deemed appropriate for purposes of his opinion.

In giving his opinion, Mr. Lazier relied upon and assumed, without independent verification, the completeness, accuracy and fair presentation of all financial and other information, data, advice, opinions and representations obtained by him from public sources or otherwise pursuant to his engagement, and his opinion is conditional upon such completeness, accuracy and fair presentation. In connection with his opinion, Mr. Lazier received the representations of the general partners of Dorchester Hugoton, among other things, that the information, data, opinions and other materials provided to him on behalf of Dorchester Hugoton are complete and correct in all material respects at the date the information was provided, and that since the date of the information, there had been no material change, financially or otherwise, in the position of the combining partnerships or in their collective assets, liabilities, businesses or operations and that there has been no change of any material fact of a nature to render the information untrue or misleading in any material respect. Mr. Lazier did not conduct any appraisal or valuation or any reserve study of any assets or liabilities of Dorchester Hugoton nor were any such valuations, appraisals or reserve studies provided to him other than those cited above. In his analysis and in connection with the preparation of his opinion, Mr. Lazier has made a number of assumptions with respect to industry performance, general business, market and economic conditions and other matters, which assumptions Mr. Lazier believes are reasonable to make in the context of the combination.

Mr. Lazier based his opinion on securities market, economic and general business and financial conditions prevailing on the dates of the opinions and the condition and prospects, financial and otherwise, of Dorchester Hugoton as reflected in the information reviewed by him and as represented to him in discussions with the general partners of Dorchester Hugoton. Mr. Lazier's opinions were based upon market, economic and other conditions as they existed and could be evaluated on the dates thereof, and Mr. Lazier assumes no responsibility to update or revise either of his opinions based upon circumstances or events occurring after the date thereof.

In accordance with customary investment banking practices, Mr. Lazier employed generally accepted valuation methods in rendering his opinion. The principal method used by Mr. Lazier was a comparison of the proved oil and natural gas reserves of Spinnaker, Republic and Dorchester Hugoton as each was estimated by independent petroleum engineers and then comparing those results with the resultant ownership of the former owners of Spinnaker, Republic and Dorchester Hugoton in the new entity. Using the engineering reports, Mr. Lazier also evaluated the reserves on the basis of current cash flow, categories of reserves and reserve to production ratios, in order to determine how commensurate the different reserves were. Among other approaches, Mr. Lazier treated the transaction as a purchase of assets by Dorchester Hugoton and compared a putative price per equivalent barrel of reserves purchased from Spinnaker and Republic with the purchase price per barrel of oil equivalent in other transactions during the past two years. Finally, Mr. Lazier reviewed the effects of the transaction on the financial strength of the new entity as compared with the financial strength of Dorchester Hugoton as it currently stands.

The summary set forth above is not a complete description of the analyses or data utilized by Mr. Lazier. In arriving at his opinion, Mr. Lazier considered the results of all the analyses as a whole. No single factor or analysis was determinative of his fairness determination. Rather, the totality of the factors considered and analyses performed operated collectively to support his determination. Mr. Lazier based his analyses on assumptions that he deemed reasonable, including assumptions concerning general business and economic conditions and industry specific factors.

Mr. Lazier has a degree in petroleum engineering and a Master in Business Administration from Stanford University and has worked in his career both as a petroleum engineer and investment banker. In the course of his 40 year career, Lazier has been frequently engaged in the valuation of oil and natural gas companies, their properties and securities in connection with mergers and acquisitions, negotiated underwritings, secondary distributions of listed and unlisted securities, private placements, and valuations for estate, corporate and other

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purposes. The general partners of Dorchester Hugoton selected Mr. Lazier to render the fairness opinion on the basis of such experience and his specific experience with respect to the oil and natural gas industry.

The amount of fees paid to Mr. Lazier in connection with his engagement was negotiated with Dorchester Hugoton and set forth in his engagement letter. Mr. Lazier has received fees of $35,000 for his services. In addition, Dorchester Hugoton will indemnify Mr. Lazier against certain liabilities, including liabilities under the federal securities laws. Mr. Lazier has had no other engagement or relationship with Dorchester Hugoton, Republic or Spinnaker or their respective affiliates.

Republic's Reasons for the Combination

The general partners of Republic have both approved the combination and believe that the combination is fair to and in the best interests of Republic and its limited partners.

The general partners recommend that the limited partners of Republic vote "FOR" the approval of the combination.

The primary reason for the general partners' recommendation of the combination is that the combination will, among other things, create the opportunity for liquidity while preserving the economic relationship of the general partners and the Republic ORRI owners. Because of the varying tax and strategic perspectives of the Republic general partners and the Republic ORRI owners, Republic's ability to sell its properties or otherwise engage in a transaction such as the combination is generally limited. Consequently, each general partner's or Republic ORRI owner's interest is, absent the combination, a highly illiquid asset that would likely experience a discount in valuation because of the illiquidity.

The other principal reasons for the general partners' recommendations are:

. diversification of risk--lessening exposure to changing operating conditions or performance by any single producing well;

. exposure to a broader geographic distribution of undeveloped and nonproducing properties, which may offer the potential for growth and addition to reserves and cash flow;

. exposure to public market valuations for oil and gas producing entities;

. exposure to acquisition opportunities on participation terms more favorable than those generally available to individual and institutional investors;

. the benefit of the Business Opportunities Agreement, which will allow the Republic partners to participate indirectly in certain acquisition opportunities subject to the Business Opportunities Agreement;

. increased exposure to acquisition opportunities from sellers seeking non-taxable divestiture of similar assets; and

. the addition of complementary skills to management, including broader areas of expertise, industry contacts and advice from the management group.

The foregoing discussion of the factors and information considered by the general partners is not meant to be exhaustive, but the general partners believe that it includes all material factors considered by them. The general partners did not find it practical to, and did not, quantify or otherwise attempt to assign relative weights to the specific factors considered in reaching its determination. Rather the general partners considered their determinations and recommendation as being based upon the totality of the information presented to and reviewed by them.

Republic will not receive a fairness opinion in connection with the combination. The general partners of Republic concluded that a fairness opinion is not necessary in order to permit Republic limited partners to make

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an informed decision on the combination because each of the parties that will become Republic limited partners after the Republic reorganization is a sophisticated institutional or industry investor.

Spinnaker's Reason for the Combination

The general partner of Spinnaker has approved the combination and believes that the combination is fair to and in the best interests of Spinnaker and its limited partners.

The general partner recommends that the limited partners of Spinnaker vote "FOR" the approval of the combination.

The primary reason for the general partner's recommendation of the combination is that the combination will, among other things, create the opportunity for liquidity for the Spinnaker limited partners. Because of the varying tax and strategic perspectives of the Spinnaker partners, Spinnaker's ability to sell its properties or otherwise engage in a transaction such as the combination is generally limited. Consequently, each partner's interest is, absent the combination, a highly illiquid asset that would likely experience a discount in valuation because of the illiquidity.

The other principal reasons for the general partner's recommendations are:

. diversification of risk--lessening exposure to changing operating conditions or performance by any single producing well;

. exposure to a broader geographic distribution of undeveloped and nonproducing properties, which may offer the potential for growth and addition to reserves and cash flow;

. exposure to public market valuations for oil and gas producing entities;

. exposure to acquisition opportunities on participation terms more favorable generally available to individual and institutional investors;

. the benefit of the Business Opportunities Agreement which will allow the Spinnaker partners to participate indirectly in certain acquisition opportunities subject to the Business Opportunities Agreement;

. increased exposure to acquisition opportunities from sellers seeking non-taxable divestiture of similar assets; and

. the addition of complementary skills to management, including broader areas of expertise, industry contacts and advice from the management group.

The foregoing discussion of the factors and information considered by the general partner is not meant to be exhaustive, but the general partner believes that it includes all material factors considered by them. The general partner did not find it practical to, and did not, quantify or otherwise attempt to assign relative weights to the specific factors considered in reaching its determination. Rather the general partner considered their determinations and recommendation as being based upon the totality of the information presented to and reviewed by it.

Spinnaker will not receive a fairness opinion in connection with the combination. The general partner of Spinnaker concluded that a fairness opinion is not necessary in order to permit Spinnaker limited partners to make an informed decision on the combination because each of the Spinnaker limited partners is a sophisticated institutional or industry investor.

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Reasons for Structure Adopted for the Combination

The combination has been structured so as to be a non-taxable transaction. This is accomplished, in the case of Republic and Spinnaker, by a merger of those two partnerships with our partnership. Dorchester Hugoton's partnership agreement in its present form does not contemplate or permit a merger transaction. Amendment to permit a merger would require a vote of the holders of more than 80% of the depositary receipts, which the general partners believe would be difficult to achieve even if a strong majority of its holders favored such a transaction. Dorchester Hugoton's partnership agreement permits the transfer of all of its assets by action of the general partner and requires liquidation if oil and natural gas assets are no longer owned. To give its depositary receipt holders a voice in the decision to engage in the combination, the general partners have agreed not to proceed with the combination unless the holders of more than 50% of the depositary receipts approve the combination. Dissenters' rights have been afforded to comply with Nasdaq National Market System requirements.

A principal goal of our partnership is to own only properties that do not generate unrelated business taxable income so that our common units will be an appropriate investment for certain non-taxpaying entities such as pension funds and IRAs. Dorchester Hugoton's properties consist almost exclusively of working interests, which if owned by our partnership would generate large amounts of unrelated business taxable income. As a result, the combination provides that we will receive a 96.97% overriding royalty interests in those properties, because such an interest will not generate unrelated business taxable income.

Prior to the combination, Republic will reorganize as a limited partnership as described in "The Combination--Preparatory Steps--Reorganization of Republic." The principal reason for the Republic reorganization is to convert the interests of the Republic ORRI owners into limited partner interests so that the merger of Republic into our partnership can be effected as part of the combination. Another reason for the Republic reorganization is to convert a portion of the Republic general partners' general partner interests into limited partner interests such that they will collectively own a 4% general partner interest in Republic.

Prior to the combination, Spinnaker will reorganize as described in "The Combination--Preparatory Steps--Reorganization of Spinnaker." The principal reason for the Spinnaker reorganization is to convert a portion of the Spinnaker general partner's general partner interests into limited partner interests such that it will own a 4% general partner interest in Spinnaker.

THE COMBINATION

Overview of the Combination

The combination involves the following steps:

. Creation of Operating ORRIs. Dorchester Hugoton will transfer all of its oil and natural gas properties to Dorchester Minerals Operating LP, in exchange for retention of a 96.97% net profits overriding royalty interest in the properties conveyed, referred to as the Dorchester Hugoton ORRIs. On or at the closing of the combination, each of Republic and Spinnaker will convey minor working interest properties to Dorchester Minerals Operating LP, in exchange for 96.97% net profits overriding royalty interests on substantially similar terms. We refer to the Dorchester Hugoton ORRIs and the overriding royalty interests received by Republic and Spinnaker as the Operating ORRIs.

. Asset Sale and Liquidation, and Mergers. Immediately following, or simultaneously with, the creation of the Operating ORRIs described above the following will occur:

. Dorchester Hugoton will transfer all of its remaining assets to either us or Dorchester Minerals Operating LP (an affiliate of our general partner) and then liquidate, distributing to its partners its remaining cash and our common units. The transfers will be made as follows:

. to Dorchester Minerals Operating LP, its management and remaining operating assets, in exchange for a promissory note and the assumption of certain obligations; and

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. to us, the Dorchester Hugoton ORRIs created as described above, certain other non-cash assets, including the promissory note described in the preceding bullet, and cash to fund certain obligations, all in exchange for our common units and the assumption of Dorchester Hugoton's remaining obligations.

. Republic, after completing an internal reorganization, will merge into our partnership, with the Republic limited partners receiving our common units and the Republic general partners receiving general partner interests.

. Spinnaker, after completing an internal reorganization, will merge into our partnership, with the Spinnaker limited partners receiving our common units and the Spinnaker general partner receiving general partner interests.

Prior to the consummation of the combination, in addition to the creation of the Operating ORRIs described above, the following preparatory steps must occur in order for the combination to occur:

. the reorganization of Republic;

. the reorganization of Spinnaker; and

. the distribution of excess cash by Republic and Spinnaker to their partners.

As a result of the combination, our common units will initially be held in approximately the following proportions:

. 40.51% by former limited partners of Republic;

. 39.73% by former limited partners of Dorchester; and

. 19.76% by former limited partners of Spinnaker.

Our common units will initially be held in approximately the following amounts as a result of the combination, based on 27,040,431 common units to be issued in the combination:

. 10,953,078, by the former limited partners of Republic;

. 10,744,380, by the former limited partners of Dorchester Hugoton; and

. 5,342,973, by the former limited partners of Spinnaker.

Following the combination, including the transactions described under "--Contributions to Dorchester Minerals Management LP," our general partner will own a general partner interest in us that will entitle it to:

. a 1% partnership interest and sharing percentage in each of the Operating ORRIs conveyed to us in connection with the combination, and in any similar overriding royalty interests created in the future; and

. 4% partnership interest and sharing percentage in all our other assets, properties, obligations and liabilities and all our other items of revenue, cost and expense.

Preparatory Steps

Creation of Overriding Royalty Interests

In connection with the combination, and following approval by the limited partners of the combining partnerships and the satisfaction or waiver of the other conditions to the combination, Dorchester Hugoton will transfer all of its oil and natural gas properties to Dorchester Minerals Operating LP, in exchange for retention of the Dorchester Hugoton ORRIs in the properties conveyed to Dorchester Minerals Operating LP. Dorchester Minerals Operating LP will assume all of the obligations of a working interest owner with respect to these

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properties that are incurred after the date of transfer or relate to the post-transfer period or that were incurred prior to the transfer but are payable in the ordinary course of business after the transfer.

Republic and Spinnaker own unleased or otherwise participating mineral interests in a total of 49 properties located in eight states that may be deemed to be working interests and therefore may generate unrelated business taxable income. These properties, which are sometimes referred to as expense bearing interests, generated in the aggregate less than 2% of Republic and Spinnaker's combined net cash flow during 2001. On or at the closing of the combination, Republic and Spinnaker will convey these properties to Dorchester Minerals Operating LP in exchange for retention of an overriding royalty interest on substantially the same terms as the Dorchester Hugoton ORRIs. We contemplate that if working interests are acquired in the future, or, if the status of any of Republic or Spinnaker's properties change such that they are deemed to be working interests, they will also be conveyed periodically to Dorchester Minerals Operating LP in exchange for overriding royalty interests on substantially similar terms.

The terms of the Operating ORRIs in the working interest properties currently held by Dorchester Hugoton, Republic and Spinnaker will be substantially the same, and we will own 100% of the 96.97% net profits overriding royalty interests.

Under the terms of the Operating ORRIs, each month Dorchester Minerals Operating LP will determine the net proceeds actually received during that month from the properties that are subject to the Operating ORRIs, and, on the tenth day of the following month, will pay us 96.97% of those net proceeds. The net proceeds equal:

. the gross proceeds actually received by Dorchester Minerals Operating LP for the month from these properties; minus

. production costs paid during the month; and minus

. excess production costs, if any, resulting from previous net proceeds determinations, and not yet recouped, as of the end of the prior month.

Gross proceeds are the amounts received by Dorchester Minerals Operating LP as the working interest owner of the properties subject to the Operating ORRIs, generally on the cash method of accounting, from the sale or other disposition of oil, gas, other hydrocarbons and other minerals produced from the properties, and generally include amounts:

. as to which Dorchester Minerals Operating LP is an overproduced or underproduced party under any gas balancing agreement as and when paid to Dorchester Minerals Operating LP, except that amounts that may, in the judgment of Dorchester Minerals Operating LP, exceed future net proceeds and may be subject to cash balancing are excluded from gross proceeds if suspended or deposited in an interest-bearing escrow account, and interest earned on monies received from an interest bearing account will not be accounted for as gross proceeds; and

. received as bonuses for oil, gas and/or other mineral leases after the effective date of the Operating ORRIs.

Gross proceeds do not include amounts:

. subject to controversy and either deposited in an interest bearing escrow account or withheld from payment to Dorchester Minerals Operating LP or received but held in suspense by Dorchester Minerals Operating LP until both such controversy is resolved and Dorchester Minerals Operating LP is in possession of such gross proceeds, and interest earned on monies received from an interest bearing account will not be accounted for as gross proceeds;

. not actually received but which instead are withheld by others for non-consenting operations under the relevant operating agreement, unit agreement or other agreement providing for the non-consent operations;

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. lost or used in the production or transportation of minerals in conformity with prudent industry practices (and not reimbursed by others);

. that offset production costs under other provisions of the Operating ORRIs;

. received from third parties as a result of cash balancing obligations relating to underproduced positions affecting the properties; and

. attributable to the interests of third parties in the properties and production payments, royalties and overriding royalties to third parties.

Production costs are generally all costs, to the extent properly attributable to the properties subject to the Operating ORRIs, incurred, paid or discharged during the month, on the cash method of accounting (except for certain specific accruals), whether capital or non-capital in nature, and generally include the following, among other things:

. maintenance, drilling, completing and operating costs for the month and all other costs for the month incurred and paid by Dorchester Minerals Operating LP as the working interest owner applicable to the properties;

. all taxes (other than income taxes) relating to the properties, the Operating ORRIs, production from the properties, equipment on the properties, or processing, gas exchange or marketing of production, attributable to both the working interest owner's share and the Operating ORRIs;

. general and administrative costs deemed necessary by Dorchester Minerals Operating LP to operate and manage the properties, using cents-per-mile and dollars-per-well-per-month methods customary in the industry;

. amounts borne by the working interest owner during the month relating to payments to third parties in connection with drilling or deferring or refraining from drilling of wells (including dry hole and bottom hole payments), rent and other consideration for the use of or damage to the surface, direct charges for lease renewals, geological and geophysical, seismic, engineering and preparation for drilling; and

. all other costs, expenses and liabilities relating to operating wells on the properties, including producing, gathering, compressing, processing, selling and marketing minerals from the properties.

Production costs exclude depletion, depreciation and other non-cash deductions.

Excess production costs are the excess of production costs over gross proceeds for the period beginning with the end of the last period in which there were net proceeds and ending as of the end of the month prior to the month for which net proceeds are being determined.

Production costs and excess production costs are reduced by amounts received by Dorchester Minerals Operating LP that are attributable to the properties subject to the Operating ORRIs and include the following, among other things:

. delay rentals, shut-in gas well royalty or payments and dry hole and bottom hole payments;

. amounts received from the sale or lease of fixtures and equipment located on the properties;

. amounts received in respect of pooling or unitization;

. advance payments and payments pursuant to take-or-pay and similar contracts; and

. to the extent not otherwise included in gross proceeds, the excess of revenues from processing minerals over the costs of processing.

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Any amount not paid by Dorchester Minerals Operating LP to us when due will bear interest at the weighted average prime interest rate in effect during the period of nonpayment. If at any time Dorchester Minerals Operating LP pays us more than the amount due, we will not be obligated to return the overpayment, but the amount otherwise payable for any subsequent month will be reduced by the amount of the overpayment.

All payments made to us will be made exclusively out of amounts received from the sale or other disposition of minerals produced from the properties conveyed to Dorchester Minerals Operating LP, and in no event will payments exceed 100% of the value of production at the wellhead before the application of any processing. Should the payments due us ever exceed that amount, the resulting overage will be suspended and accrued. At such time as the payments are less than 100% of the value of the production at the wellhead before processing, the overage will be added to subsequent payments but not in an amount which would then cause payments to exceed 100% of the value of the production at the wellhead before processing.

We will not be liable or responsible in any way for payment of any production costs or any other costs or liabilities incurred by Dorchester Minerals Operating LP or other lessees.

Reorganization of Republic

The combination will not occur unless Republic completes a reorganization immediately prior to or simultaneously with the combination. In this reorganization:

. Republic will convert from a general partnership to a limited partnership; and

. the owners of the overriding royalty interests burdening Republic's properties, which we refer to as the Republic ORRIs, will contribute their Republic ORRIs to Republic in exchange for limited partnership interests in Republic.

In a private transaction, the Republic general partners are proposing to the Republic ORRI owners that they agree to the Republic reorganization and consummate the reorganization in connection with the combination. As a result of the proposed Republic reorganization, at the time of the combination:

. Republic's properties will no longer be burdened by the Republic ORRIs;

. SAM Partners, Ltd. and Vaughn Petroleum, Ltd. will remain the general partners of Republic; and

. the limited partners of Republic will be SAM Partners, Ltd. and Vaughn Petroleum, Ltd.; the Republic ORRIs owners; and a new partnership, which we refer to as the APO Partnership in this document, owned by SAM Partners, Ltd., Vaughn Petroleum, Ltd. and the former Republic ORRIs owners.

The purpose of the APO Partnership is to preserve after the combination, through the APO Partnership's ownership of our common units received in the combination, the variable interests of the Republic general partners and the Republic ORRI owners that currently exist in the Republic ORRIs documentation. See the discussion of the Republic ORRIs under "Information Concerning Republic--General" for more information about these variable interests. The APO Partnership will also indemnify us for any losses that we incur and receive any recovery obtained in connection with certain litigation matters involving Republic described under "Information Concerning Republic--Legal Proceedings."

The principal reason for the Republic reorganization is to convert the interests of the Republic ORRIs owners into limited partner interests so that the merger of Republic into our partnership can be effected as part of the combination. Another reason for the Republic reorganization is to convert a portion of SAM Partners, Ltd.'s and Vaughn Petroleum, Ltd.'s general partner interests into limited partner interests such that they will collectively own a 4% general partner interest in Republic.

All of the Republic ORRI owners must agree to the Republic reorganization in order for it to occur. In addition to this private investment decision, the parties who would become Republic limited partners as a result

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of the Republic reorganization must vote on whether to approve the combination. Consequently, this document is being provided to the parties who would become Republic limited partners in the Republic reorganization.

In the Combination Agreement, each of the Republic general partners has agreed to use its reasonable best efforts to solicit from the Republic ORRI owners written agreements effecting the Republic reorganization.

Reorganization of Spinnaker

The combination will not occur unless Spinnaker completes a reorganization immediately prior to or simultaneously with the combination. In this reorganization, Spinnaker's partnership agreement will be amended so that Smith Allen Oil & Gas, Inc., its general partner, will hold a 4% interest in Spinnaker and the limited partners of Spinnaker will hold interests aggregating a 96% interest in Spinnaker. Currently, Smith Allen Oil & Gas, Inc. holds slightly greater than a 4% interest in Spinnaker. The Spinnaker reorganization is necessary to convert a portion of Smith Allen Oil & Gas, Inc.'s general partner interests into limited partner interests such that it will own a 4% general partner interest in Spinnaker.

In the Combination Agreement, Spinnaker's general partner has agreed to use its reasonable best efforts to solicit from the Spinnaker limited partners written agreements effecting the Spinnaker reorganization.

Contribution of Assets by Smith Allen Oil & Gas, Inc.

Smith Allen Oil & Gas, Inc., the general partner of Spinnaker, will contribute its management and operating assets to Dorchester Minerals Operating LP. The management and operating assets will include the following:

. leases for Smith Allen Oil & Gas, Inc.'s Dallas, Texas home office;

. all tangible personal property owned or leased by it located at or used in connection with those offices or Smith Allen Oil & Gas, Inc.'s business;

. computer equipment;

. contract rights and claims that relate to other items included in the assets being conveyed;

. licenses and permits;

. books and records; and

. intellectual property rights relating to other assets transferred.

Transfer of Assets by Dorchester Hugoton and Liquidation

Transfer of Management and Remaining Operating Assets to Dorchester Minerals Operating LP

Dorchester Hugoton will transfer its management assets and the remaining operating assets not included in the Dorchester Hugoton ORRIs to Dorchester Minerals Operating LP in exchange for a promissory note in a principal amount equal to the appraised value of such assets and the assumption of certain related obligations.

The management and remaining operating assets will include the following:

. leases for Dorchester Hugoton's Garland, Texas home office and its field office in Amarillo, Texas;

. all tangible personal property owned or leased by it located at or used in connection with those offices or Dorchester Hugoton's business;

. computer equipment;

. trucks and vehicles;

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. contract rights and claims that relate to other items included in the assets being conveyed;

. items paid for but not delivered;

. bonds and deposits;

. licenses and permits;

. books and records; and

. intellectual property rights relating to other assets transferred.

The assets will also include cash to fund certain accrued expenses to the extent not paid prior to closing and ownership of certain bank accounts. Prior to closing, Dorchester Hugoton will pay, to the extent practicable, its undisputed obligations that are quantifiable as to amount.

Dorchester Minerals Operating LP will assume certain pre- and post-transfer liabilities relating to these assets and certain unpaid royalties to the extent not otherwise assumed by Dorchester Minerals Operating LP in connection with the creation of the Operating ORRIs.

An appraisal of the management and remaining operating assets transferred in exchange for the promissory note will be performed as of a date within 10 days of closing by an independent appraiser selected by Dorchester Hugoton and approved by Republic and Spinnaker. The promissory note will be unsecured, will bear interest at 6% per annum and will be payable in quarterly installments over a five year amortization schedule.

Transfer of Dorchester Hugoton ORRIs and Liquidation of Dorchester Hugoton

Dorchester Hugoton will convey to us the Dorchester Hugoton ORRIs and all its other remaining assets, including the goodwill associated with Dorchester Hugoton's business, if any, the rights to the Dorchester Hugoton trade name and service mark, the promissory note received from Dorchester Minerals Operating LP and cash in an amount sufficient to pay dissenting Dorchester Hugoton depositary receipt holders, if any, to fund its share of combination costs and other accrued expenses assumed by us, but excluding all other cash (including proceeds of sales of marketable securities) which is to be distributed to its depositary receipt holders. In exchange, we will issue to Dorchester Hugoton a number of common units that, after completion of the transactions described under "--Contributions to Dorchester Minerals Management LP," will provide the depositary receipt holders of Dorchester Hugoton in the aggregate with common units representing approximately 39.73% of the total amount outstanding immediately following the combination. We will also assume all of the obligations and liabilities of Dorchester Hugoton, including contingent liabilities, whether known and unknown, except for those assumed by Dorchester Minerals Operating LP.

Dorchester Hugoton will sell 128,000 shares of Exxon Mobil Corporation stock held by it prior to the closing and, at or prior to closing, will make all required payments under its severance plan which are estimated to be up to approximately $2.7 million. Immediately following Dorchester Hugoton's sale of its assets, the remaining assets of Dorchester Hugoton will consist of our common units and cash, and it will have no remaining obligations or liabilities. Because Dorchester Hugoton will no longer own any oil or gas properties, an event of dissolution will occur under its partnership agreement, and it will be liquidated. Dorchester Hugoton will distribute the common units and its remaining cash to its depositary receipt holders and its general partners in liquidation of the partnership interests represented by their holdings.

Under Dorchester Hugoton's partnership agreement, amounts to be distributed in liquidation are distributed in accordance with of capital accounts of the partners after all allocations and adjustments have been made. The capital accounts of the general partners are slightly less than 1% of the total of all capital accounts. As a result, the general partners will receive slightly less than 1% of the common units and cash distributed in the liquidation, and the limited partners will receive slightly more than 99%.

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By formula under the Combination Agreement, the number of common units that will be delivered to the holders of Dorchester Hugoton's depositary receipts will equal the number of outstanding depositary receipts, and the numbers of common units to be delivered to the general partners will be derived from that number. The common units that will be distributable to the holders of depositary receipts of Dorchester Hugoton will represent 39.73% of the total number of common units outstanding immediately following the combination.

After the liquidation and the distribution are completed, Dorchester Hugoton will be terminated and will cease to exist.

Merger of Republic with Dorchester Minerals

Following completion of its reorganization, Republic will merge with and into our partnership, with our partnership as the surviving entity, with:

. Republic's limited partners receiving in the aggregate a number of common units that, after completion of the transactions described under "--Contributions to Dorchester Minerals Management LP," will represent 40.51% of the total amount outstanding immediately following the combination; and

. each of Republic's general partners receiving a general partnership interest in us, representing a 2% interest, or a 4% interest in the aggregate, in our capital and profits, relating solely to the assets previously owned by Republic (see " --Contributions to Dorchester Minerals Management LP" below for the subsequent treatment of this interest).

The separate existence of Republic will cease as of the effective time of the merger, and we will succeed to all of the assets, liabilities, rights and obligations of Republic.

Prior to this merger, Republic will make the required payments under the terms of the Republic ORRIs and will distribute to the partners of Republic in proportion to their respective interests all cash not needed to fund its share of combination costs and other accrued expenses for which payments by Republic may be necessary.

Merger of Spinnaker with Dorchester Minerals

Following completion of its reorganization, Spinnaker will merge with and into our partnership, with our partnership as the surviving entity, with:

. Spinnaker's limited partners receiving in the aggregate a number of common units that, after completion of the transactions described under " --Contributions to Dorchester Minerals Management, LP," will represent 19.76% of the total amount outstanding immediately following the combination; and

. Spinnaker's general partner receiving a general partnership interest in us, representing a 4% interest in our capital and profits, relating solely to the assets previously owned by Spinnaker (see "--Contributions to Dorchester Minerals Management LP" below for the subsequent treatment of this interest).

The separate existence of Spinnaker will cease as of the effective time of the merger, and we will succeed to all of the assets, liabilities, rights and obligations of Spinnaker.

Prior to this merger, Spinnaker will distribute to the partners of Spinnaker in proportion to their respective interests all cash not needed to fund its share of combination costs, payments to limited partners who dissent, if any, and other accrued expenses for which payments by Spinnaker may be necessary.

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Contributions to Dorchester Minerals Management LP

Contributions to Dorchester Minerals Management LP

The general partners of each of Republic and Spinnaker will contribute the general partner interests in us they receive as a result of the mergers described above to Dorchester Minerals Management LP in exchange for limited partnership interests in Dorchester Minerals Management LP. The general partners of Dorchester Hugoton will contribute cash and the common units they receive as a result of its liquidation to Dorchester Minerals Management LP in exchange for limited partnership interests in Dorchester Minerals Management LP.

The cash amount to be contributed by the general partners of Dorchester Hugoton will be equal to the amount that would have had to have been added to their capital accounts in Dorchester Hugoton immediately prior to the closing of the combination in order for the combined balance of their capital accounts to equal 1% of the aggregate capital account balances of all partners of Dorchester Hugoton after the making of such an addition.

Conversions of Partnership Interests

Following the receipt of these contributions, Dorchester Minerals Management LP will contribute the cash received from the general partners of Dorchester Hugoton to us as an additional capital contribution, and our common units contributed to Dorchester Minerals Management LP by the Dorchester Hugoton general partners will, under the terms of our Partnership Agreement, be converted into a general partner interest in our partnership constituting a 1% interest in our capital and profits, relating solely to the assets conveyed to us by Dorchester Hugoton.

Then, under the terms of our Partnership Agreement, the general partner interests in our partnership held by Dorchester Minerals Management LP will be converted into:

. a 1% partnership interest and sharing percentage in the Operating ORRIs to be held by us in the working interest properties contributed by the combining partnerships to Dorchester Minerals Operating LP and any similar overriding royalty interests created in the future, and

. a 4% partnership interest and sharing percentage in all our other assets, properties, obligations and liabilities and all our other items of revenue, cost and expense.

Ownership Structure of Dorchester Minerals

Upon completion of the steps described above:

. Dorchester Minerals Management LP will own the general partnership interest in our partnership described in the preceding section, and

. the holders of common units will then own our units constituting the balance of our partnership interests in approximately the following proportions:

.   Common units held by former depositary receipt holders of Dorchester Hugoton 39.73%

.   Common units held by former limited partners of Republic.................... 40.51%

.   Common units held by former limited partners of Spinnaker................... 19.76%

THE COMBINATION AGREEMENT

On December 13, 2001, we entered into a Combination Agreement with the combining partnerships, Dorchester Minerals Management LP, Dorchester Minerals Management GP LLC and Dorchester Minerals Operating LP. The principal terms of the Combination Agreement that are not included in the discussion above

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are summarized below. This discussion is only a summary and you should also refer to the full text of the Combination Agreement, a copy of which is attached as an exhibit to the registration statement, of which this document is a part.

Effective Time of the Combination

Unless the combining partnerships otherwise agree, the closing of the combination will occur on the day which is five business days after the date on which the last of the closing conditions set forth in the Combination Agreement have been fulfilled or waived.

Upon the closing, certificates of merger for the merger of Republic and Spinnaker into our partnership will be filed with the Secretaries of State of the States of Delaware and Texas, and the mergers will be effective at the time the certificates are so filed or at such later time as is specified in the certificates of merger.

Conditions

The obligations of the combining partnerships to effect the combination are subject to the following conditions, among others:

. the approval of the combination by the holders of more than 50% of the depositary receipts of Dorchester Hugoton, by all of the partners of Republic (including Republic ORRI owners, who will become limited partners upon Republic's reorganization) and by the limited partners owning at least 85.9883% of the sharing percentages of Spinnaker;

. none of the combining partnerships' being subject to any order, injunction or ruling of any court or other governmental entity, or any statute, rule, regulation or order of a governmental entity, which restrains, enjoins, prohibits or makes illegal the combination, and the absence of any legal proceeding by any governmental entity seeking to prevent or challenge the combination;

. the receipt of all necessary governmental approvals and third party consents;

. the effectiveness of the registration statement of which this document is a part, and the absence of any Securities Exchange Commission stop order suspending the effectiveness of the registration statement;

. the approval for listing of our common units on the Nasdaq National Market System;

. the completion of the reorganizations of Republic and Spinnaker and the conveyance of their working interests to Dorchester Minerals Operating LP;

. the satisfaction of the conditions precedent to the closing of the transactions under the agreement providing for the capitalization of Dorchester Minerals Management LP and Dorchester Minerals Management GP LLC and the simultaneous closing of the transactions covered by that agreement;

. the receipt of comfort letters of the independent auditors of our partnership and each of the combining partnerships;

. the execution by the general partners of each of the combining partnerships, the managers of Dorchester Minerals Management LP and each officer of Dorchester Minerals Operating LP of lock-up agreements with respect to our common units, with a duration of one year;

. the continued accuracy in all material respects of all representations and warranties of each of the combining partnerships and our partnership contained in the Combination Agreement and in any related agreements and documents;

. compliance in all material respects by all of the combining partnerships and our partnership with the agreements and covenants contained in the Combination Agreement;

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. the absence of any material adverse change in the financial conditions of the combining partnerships and our partnership (other than changes due to changes in oil and natural gas prices or general economic conditions);

. the contemporaneous occurrence of the mergers of Republic and Spinnaker into our partnership and the transfer of the assets of Dorchester Hugoton to us;

. the determination of the amounts of dissenters' payments for each of Dorchester Hugoton and Spinnaker, and the funding of such amounts by each of them;

. the payment by Dorchester Hugoton of all amounts required under its severance plan and the receipt of releases from each participant in that severance plan;

. as a condition to the obligations of Dorchester Hugoton only, the entry by Dorchester Minerals Operating LP into employment agreements with Kathleen A. Rawlings and John L. Dannelley, employees of Dorchester Hugoton;

. as a condition to the obligations of Dorchester Hugoton only, the contribution by Smith Allen Oil & Gas, Inc. to Dorchester Minerals Operating LP of management assets relating to the management of Republic and Spinnaker; and

. as a condition to the obligations of Republic and Spinnaker only, the transfer of the working interests and management and operating assets of Dorchester Hugoton to Dorchester Minerals Operating LP.

Representations and Warranties

The Combination Agreement contains representations and warranties by the combining partnerships as to themselves concerning, among other things:

. organization, good standing and authority;

. capital structure;

. authorization to enter into the Combination Agreement and all related transactions;

. absence of conflicts or defaults caused by execution and delivery of the Combination Agreement or consummation of the combination;

. required governmental approvals;

. accuracy of financial statements;

. absence of undisclosed liabilities;

. absence of material adverse changes since the date of the most recent financial statements;

. payment of taxes and compliance with laws;

. possession of and compliance with government permits;

. absence of undisclosed litigation;

. employee benefit plan matters and labor matters;

. compliance with environmental and safety regulations;

. accuracy of information provided to consulting engineers for preparation of reports on proved reserves as of January 1, 2001 and the absence of adverse title claims;

. absence of brokers' or finders' fees;

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. material agreements; and

. accuracy of information provided for the registration statement.

The representations and warranties of the parties will expire at the closing of the combination.

Certain Covenants

The Combination Agreement contains various agreements of each of the combining partnerships regarding actions to occur from the date of the agreement to the closing date, including, among other things, agreements with respect to the following:

. the conduct of their respective businesses only in the ordinary course of business consistent with past practice;

. restrictions on certain material actions;

. the payment prior to closing of trade payables and known undisputed claims and liabilities incurred or accrued through the date of closing and provision for funding unpaid amounts and dissenters' claims, and, in the case of Republic and Spinnaker, the distribution of excess cash, if any;

. the holding of partnership meetings, voting, the preparation and filing of this document, and recommendations of the general partners;

. reciprocal access to information, and the confidentiality of confidential information;

. reciprocal notification obligations of facts that would cause any representation or warranty to be untrue or inaccurate, and of any material failure to comply with any covenant, condition or agreement under the Combination Agreement;

. reciprocal notification obligations of any proposals or requests for information relating to an acquisition proposal by a third party; and

. the repayment of all outstanding indebtedness for borrowed money (other than oil and gas industry arrangements required in connection with oil and gas operations).

Republic and Spinnaker have each agreed to (i) use their reasonable best efforts to obtain approval of their respective reorganizations and (ii) convey their working interests to Dorchester Minerals Operating LP prior to the combination.

Dorchester Hugoton has agreed to (i) the purchase of continuing directors and officers liability coverage covering the general partners, officers and Advisory Committee of Dorchester Hugoton and (ii) to pay quarterly distributions of cash in accordance with, and in amounts not materially in excess of, past practice.

Acquisition Proposals

The combining partnerships have agreed that they will not, and will not permit any of their representatives to, directly or indirectly, solicit, initiate or knowingly encourage or take any other action to facilitate the making of any acquisition proposal. Restricted actions with respect to an acquisition proposal include (i) soliciting, initiating, knowingly encouraging or taking any action facilitating the making of an acquisition proposal, (ii) entering into any agreement, (iii) engaging in any discussions or negotiations or providing any nonpublic information relating to any person. Each combining partnership is required to (i) notify the other combining partnerships of any acquisition proposal or a request to initiate discussions in connection with any acquisition proposal and (ii) keep the other combining partnerships informed of any contact by a third party concerning an acquisition proposal.

However, if a combining partnership determines that an acquisition proposal is a superior acquisition proposal, then the combining partnership may (i) furnish information about itself to the party making the superior

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acquisition proposal pursuant to a confidentiality agreement and (ii) participate in negotiations regarding such acquisition proposal. If a combining partnership determines it is necessary to allow the partnership to enter into an agreement with respect to a superior acquisition proposal, then it may terminate the Combination Agreement and take the actions in the preceding sentence, but only after it provides written notice to the other combining partnerships not later than (12:00) noon two business days in advance of the date it intends to enter into an agreement with respect to the superior acquisition proposal or terminate the Combination Agreement, specifying the terms of the superior acquisition proposal, identifying the person making the superior acquisition proposal and affording the other partnerships the opportunity to make a proposal that is superior to the superior acquisition proposal.

An acquisition proposal means any inquiry, proposal or offer relating to any of the following:

. an offer or proposal for a merger, consolidation or other business combination or joint venture involving a combining partnership or the acquisition of a substantial equity interest in or a substantial portion of the assets of any of the combining partnerships;

. any other proposal with respect to any recapitalization or restructuring with respect to a combining partnership; or

. a tender offer or exchange offer involving a combining partnership.

A superior proposal means a bona fide written acquisition proposal made on an unsolicited basis by a third party that the general partners of the combining partnership (and in the case of Dorchester Hugoton, its Advisory Committee) determine:

. in good faith (in the case of Dorchester Hugoton after receiving advice from financial advisors) represents a financially superior proposal to the combination from the standpoint of its limited partners; and

. in good faith, after consultation with counsel, would cause the general partners or the Advisory Committee to violate their fiduciary duties to their limited partners under applicable law if the general partners or the Advisory Committee failed to provide information or access or to engage in discussions or negotiations with such third party.

If a combining partnership terminates the Combination Agreement as described above, it must pay the other combining partnerships the termination fee that is provided for under the Combination Agreement. See "The Combination Agreement--Termination Fee" at page 65 of this document.

Termination

Prior to the consummation of the combination, the Combination Agreement may be terminated:

. by mutual consent of the parties to the Combination Agreement; or

. by any of Dorchester Minerals or the combining partnerships, if any of the following occur:

. the combination is not closed on or before January 2, 2003;

. there is a legal prohibition to closing the combination arising from any law or the issuance of an order, decree or ruling of a governmental body enjoining or prohibiting the combination by any combining partnership;

. the depositary receipt holders of Dorchester Hugoton or the limited partners of Republic or Spinnaker do not approve the combination;

. either of the general partners of Republic or Spinnaker, respectively, or the Advisory Committee of Dorchester Hugoton, withdraws, modifies or fails to reaffirm its recommendation or approval of the Combination Agreement or does not recommend that its limited partners not tender their shares in a qualifying third party tender offer or exchange offer for their partnership interests;

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. either of the general partners of Republic or Spinnaker, respectively, or the Advisory Committee of Dorchester Hugoton has recommended, approved, executed or publicly announced its intention to execute a definitive agreement for a financially superior transaction from the standpoint of the limited partners of that partnership;

. either of the general partners of Republic withdraws or modifies its recommendation or approval of, or accepts or executes a definitive agreement that would be in lieu of or prevent, the Republic reorganization; or

. there has been a material breach by any other combining partnership or our partnership of any of its representations, warranties or covenants set forth in the Combination Agreement that has not been cured within 30 days after notice by the terminating partnership or any condition to closing in the terminating partnership's favor has not been satisfied or waived.

Termination Fee

If the Combination Agreement is terminated as a result of certain actions relating to an acquisition proposal with respect to a combining partnership or the reorganization of Republic, then that partnership must promptly pay the other combining partnerships a termination fee aggregating $3,000,000.

If Dorchester Hugoton is obligated to pay the termination fee, then it must pay $2,000,000 to Republic and $1,000,000 to Spinnaker. If Republic or Spinnaker is obligated to pay the termination fee, then Republic must pay Dorchester Hugoton $2,000,000 and Spinnaker must pay Dorchester Hugoton $1,000,000. Republic and Spinnaker have entered into a contribution agreement between themselves to allocate their burden according to fault.

The termination fee is payable by a combining partnership if the combining partnership terminates the Combination Agreement in the following circumstances:

. a general partner or Advisory Committee of that combining partnership has withdrawn, modified or failed to reconfirm its recommendation or approval of the Combination Agreement in a manner adverse to the terminating partnership or has failed to recommend that its limited partners not tender their shares in a qualifying third party tender offer or exchange offer for their partnership interests;

. a general partner or Advisory Committee of that combining partnership has recommended or approved a letter of intent or definitive agreement for a superior acquisition proposal;

. that combining partnership has failed to fulfill in any material respect its material obligations under the Combination Agreement in a respect that is material to the terminating partnership and within one year that partnership consummates or enters into an agreement for a transaction which would be an acquisition proposal with respect to that partnership or any person or group has acquired beneficial ownership or the right to acquire beneficial ownership of 50% or more of the limited partnership interests of that partnership; or

. in the case of Republic, because Republic or its general partners has withdrawn, modified or failed to affirm its recommendation or approval of the Republic reorganization or has recommended that the Republic ORRI owners accept or execute a definitive agreement not approved by Dorchester Hugoton or Spinnaker that would be in lieu of or would prevent the Republic reorganization.

The termination fee is not required to be paid if the prospective payee is in material breach of its obligations under the Combination Agreement and remains in material breach after having been afforded 30 days to cure the breach after notice.

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Amendments

The Combination Agreement may be amended in writing by mutual agreement of all parties to the agreement at any time prior to its approval by the limited partners of any of the combining partnerships. After adoption by the partners of a partnership, the Combination Agreement may not be amended without the further approval of the partners of that partnership if the amendment would change the amount or kind of consideration to be received or if the change would adversely affect that partnership's partners. Waivers may be granted in writing by any affected party.

Issuance of Units; Fractional Units

Exchange Agent and Liquidating Agent

Prior to the consummation of the combination, we will designate EquiServe Trust Company, N.A., or another bank or trust company reasonably acceptable to the combining partnerships to issue the certificates representing our common units in the combination. EquiServe will serve as exchange agent in connection with the mergers of Republic and Spinnaker with our partnership, and it will serve as liquidating agent in connection with the distribution of our common units and cash to the depositary receipt holders of Dorchester Hugoton in connection with its liquidation.

Delivery of Certificates for Common Units to Republic and Spinnaker Partners

As soon as practicable after the consummation of the combination, we will make available to EquiServe, for the benefit of the limited partners of Republic and Spinnaker, certificates representing the number of whole common units issuable in exchange for their limited partnership interests in Republic and Spinnaker. Promptly after the effective time, we will send, or will cause EquiServe to send, to each non-dissenting limited partner of Republic or Spinnaker:

. a certificate representing that number of whole limited partnership units which that partner has a right to receive, and

. a transfer application, in such form as we, Republic and Spinnaker may reasonably agree, for use in admission of such partners as limited partners in our partnership.

Each holder of limited partnership interests of Republic or Spinnaker, upon delivery, or deemed delivery to us of a properly completed transfer of application, will be admitted into our partnership as a limited partner in accordance with our Partnership Agreement. Prior to being admitted, each party will have the rights of an assignee under our Partnership Agreement. See "Description of Units of Dorchester Mineral--Transfer of Common Units" beginning at page 178.

Delivery of Certificates for Common Units and Cash to Dorchester Hugoton Partners

On the first business day after the closing of the combination, Dorchester Hugoton will transfer to EquiServe the remaining cash of Dorchester Hugoton that is distributable to the non-dissenting depositary receipt holders of Dorchester Hugoton under its partnership agreement upon its liquidation, constituting approximately 99% of such cash, and will deliver to the general partners the cash that is distributable to them, constituting approximately 1% of such cash.

At the close of business on the closing date of the combination, we will deliver to EquiServe the portion of our common units to be transferred to the non-dissenting depositary receipt holders in the liquidation of Dorchester Hugoton. We will deliver to the general partners of Dorchester Hugoton the remainder of such common units, representing approximately 1% of those units. See "The Combination--Transfer of Assets by Dorchester Hugoton and Liquidation--Transfer of Dorchester Hugoton ORRIs and Liquidation of Dorchester Hugoton" for a description of how our common units will be allocated among the general partners and depositary receipt holders of Dorchester Hugoton. Promptly after the closing of the combination, we will cause EquiServe to

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mail to each non-dissenting limited partner of Dorchester Hugoton of record at the close of business on the closing date:

. a letter of transmittal, with related instructions, to be used by the limited partner in exchanging certificates which, prior to the combination, represented depositary receipts of Dorchester Hugoton; and

. a transfer application, in such form as we and the combining partnerships may reasonably agree, for use in admission of such person as a limited partner of our partnership.

After the effective time, there will be no further registration of transfers of Dorchester Hugoton depositary receipts that were outstanding immediately prior to the effective time.

Upon the surrender of a certificate representing depositary receipts of Dorchester Hugoton to EquiServe, together with other documents as may be reasonably required by EquiServe, the Dorchester Hugoton limited partner will be entitled to receive:

. a certificate representing the number of our whole common units which that limited partner has a right to receive; and

. its share of the cash distributable to the non-dissenting partners of Dorchester Hugoton in liquidation.

Upon delivery, or deemed delivery to our partnership of a properly completed transfer application, any non-dissenting limited partner of Dorchester Hugoton who has been issued a certificate representing our common units will be admitted into our partnership as a limited partner in accordance with our Partnership Agreement. Prior to being admitted, each such person will have the rights of an assignee under our Partnership Agreement.

In the event of a transfer of ownership of Dorchester Hugoton depositary receipts that has not been registered in the transfer records of Dorchester Hugoton, a certificate representing the appropriate number of our common units may be issued to a transferee if the certificate representing the Dorchester Hugoton depositary receipts is presented to EquiServe, accompanied by all documents required to evidence and effect the transfer and to evidence that any applicable stock transfer taxes have been paid, along with a letter of transmittal duly executed by the transferee.

Until a certificate representing Dorchester Hugoton units has been surrendered to EquiServe, each Dorchester Hugoton certificate will be deemed at any time after the closing of the combination to represent only the right to receive the certificate representing the number of our common units and the cash to which the Dorchester Hugoton partner is entitled. In addition, until certificates representing Dorchester Hugoton depositary receipts and a properly executed letter of transmittal have been delivered in accordance with these procedures, the holder will not receive any distribution of assets of Dorchester Hugoton. Upon delivery of the certificates and the letter of transmittal, the former Dorchester Hugoton depositary receipt holder will receive our common units and his or her share of the cash distributable in liquidation, without interest.

Termination of Duties of Exchange and Liquidating Agent

Promptly following the six months anniversary of the combination, EquiServe will, in its capacity as exchange agent and liquidating agent, deliver to us, or to our transfer agent in accordance with our instructions, all cash, certificates and other documents and instruments in its possession relating to the combination. EquiServe's duties as exchange agent and liquidating agent will then terminate. Thereafter, each holder of a limited partnership interest in the combining partnerships will look only to us (or us through our transfer agent) for receipt of common units and their share of distributable cash.

Fractional Units

No certificates or scrip evidencing fractional common units will be issued, and no payments in respect of fractional common units will be made, to former limited partners of Republic or Spinnaker. In lieu of fractional

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interests, former limited partners of Republic and Spinnaker will receive a number of common units rounded to the nearest whole unit, with half units being rounded up to the nearest whole unit. Because one common unit will be delivered for each depositary receipt of Dorchester Hugoton, no fractional common units will result.

Dissenters' Rights

The Combination Agreement provides that if either Dorchester Hugoton or Spinnaker receives approval of the combination by less than 75% of its partnership interests, the limited partners of Spinnaker or the holders of depositary receipts of Dorchester Hugoton, as applicable, will be entitled to dissenters' rights of appraisal in connection with the combination. We will be responsible for the payment of any dissenting limited partners or depositary receipt holders, but the amount payable will be funded by Dorchester Hugoton or Spinnaker or both, as applicable, and the final cash distributions to their respective depositary receipt holders or limited partners will be reduced by such amount.

In order to exercise the right to dissent, a limited partner of Spinnaker or a holder of depositary receipts of Dorchester Hugoton must deliver to the general partner of the applicable partnership, prior to the vote of the partnership to approve the combination, a written dissenter's notice advising of that limited partner's or depositary receipt holder's intention to demand a cash payment and to vote against approval of the combination. Such limited partner or depositary receipt holder must also in fact vote against the combination. A proxy or ballot voting against approval of the combination does not constitute the requisite dissenter's notice. Since a proxy returned but left blank will be voted as an approval of the combination, a limited partner or depositary receipt holder electing to exercise dissenter's rights who votes by proxy must not leave the proxy blank, but instead must vote against approval of the combination. Only the owner of record of the relevant partnership interest or depositary receipt is entitled to demand its rights as a dissenter.

In order for a dissenter's notice of a Dorchester Hugoton depositary receipt holder to be effective, the notice must include a duly executed original of an agreement of dissenter. In that agreement, the dissenting holder agrees that he or it will not be entitled to receive any of our assets or any common units, or any cash held by Dorchester Hugoton as of the closing date of the combination. The dissenting depositary receipt holder further agrees that he or it will be entitled solely to receive the amount provided in the Combination Agreement, and waives any right to any of our common units or any cash held by Dorchester Hugoton as of the closing date of the combination.

Within 10 days following the closing of the combination, we will notify any dissenting limited partners or depositary receipt holders who have properly perfected their dissenters' rights of the fact that they have perfected those rights. For a period of 30 days following the date of the dissenters' notice, either we or the dissenting limited partner or depositary receipt holder can propose and negotiate a price for the partnership interest. If agreement is not reached on a price within that 30 day period, we will choose an independent appraiser to determine the value of the dissenting limited partner's or depositary receipt holder's interest in the partnership, based on an appraisal of the applicable partnership's assets as if sold in an orderly manner in a reasonable period of time and in a manner consistent with industry practice. The independent appraiser will have 90 days to determine the value of the limited partner's or depositary receipt holder's interest in the partnership. If either Dorchester Hugoton or Spinnaker selects an independent appraiser so that the applicable partnership may make adequate provision for payments to dissenters, then we may use that appraisal for the purposes of determining the value of a depositary receipt holder's or a limited partner's interest in that partnership. The determination of the independent appraiser will be final. The amount determined by the independent appraiser will be paid by us within 15 days following the final determination, with interest from the closing date of the combination at the prime rate as published in the Wall Street Journal from time to time between the closing date of the combination and the payment date. We will pay all fees of the independent appraiser.

Each partner of Republic and the Republic ORRI owners must approve the Republic reorganization and the combination, or they will not occur. As a result, dissenters' rights are not provided for Republic.

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Nasdaq Listing

We have applied to the Nasdaq National Market System for the listing of our common units to be issued in the combination under the proposed symbol "DMLP."

Interests of Certain Persons in the Combination

The general partners of the combining partnerships, and the individuals that own or manage the general partners, may have interests in the combination that differ from the interests of the limited partners of the combining partnerships. See "Conflicts of Interest" for a detailed description of these interests.

Resales of Common Units

Our common units to be issued in connection with the combination will be registered under the Securities Act. All units will be freely tradable after completion of the combination, except for common units issued to (i) any partner of a combining partnership that is an "affiliate" of a combining partnership, as applicable, for purposes of Rule 145 of the Securities Act or
(ii) any partner that becomes an "affiliate" of our partnership after the combination. Persons that may be deemed to be "affiliates" of a combining partnership for such purposes generally include individuals or entities that control, are controlled by, or are under common control with the respective combining partnership and include the general partners of the combining partnerships as to both those partnerships and our partnership. The Combination Agreement requires each combining partnership to use reasonable efforts to cause each of its affiliates to execute a written agreement with us to the effect that they will not transfer any of our common units received in the combination, except pursuant to an effective registration statement under the Securities Act or in a transaction not required to be registered under the Securities Act.

Accounting Treatment

The combination will be accounted for using purchase accounting. Generally accepted accounting principles require that one of the companies in the combination be designated as the acquiror for accounting purposes. Dorchester Hugoton has been designated the acquiror because its depositary receipt holders are the ownership group that will receive the largest ownership interest in our partnership. The ownership interests held by the Republic ORRI owners are viewed individually for this purpose, notwithstanding that the Republic ORRI owners will contribute their overriding royalty interests to Republic in exchange for limited partner interests in connection with the Republic reorganization. The Republic reorganization is disregarded for this purpose because the Republic reorganization will occur immediately prior to or simultaneously with the combination. Republic and Spinnaker's properties will be recorded at fair value based on the market price of Dorchester Hugoton's depositary receipts immediately prior to the combination, subject to normal and customary adjustments.

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Expenses and Fees

We estimate the costs and expenses to be incurred in connection with the combination to be approximately $2,733,110 as summarized below.

                                Estimated
                                 Amount
                                ----------
SEC registration fee........... $   18,210
Voting Inspector...............      5,000
Nasdaq listing fees............    100,000
Nasdaq annual fee..............     30,000
Legal fees.....................  2,000,000
Accounting fees................    391,000
Reserve report preparation fees     55,000
Printing costs.................     81,000
Solicitation expenses..........     20,000
Transfer agent fees............     31,000
Miscellaneous other fees.......      1,900
                                ----------
   Total....................... $2,733,110
                                ==========

All fees and expenses, including fees and expenses of counsel, engineers and accountants, incurred in connection with the Combination Agreement and the transactions contemplated thereby will be paid by the combining partnership incurring such fee or expense, whether or not the combination shall have occurred. However, all fees and expenses incurred after July 31, 2001, which are properly allocable to all combining partnerships as common costs will be borne in the following proportions:

Dorchester Hugoton 39%
Republic.......... 41%
Spinnaker......... 20%.

To the extent any such transaction costs have not been paid by a combining partnership prior to the closing of the combination, that partnership must fund those costs at closing unless the other partnerships agree to allow the partnership to defer payment until after closing. In this case, if Republic or Spinnaker is the deferring partnership, it will retain and not distribute to its partners as excess cash amounts sufficient to fund those costs. If Dorchester Hugoton is the deferring partnership, it will transfer to us an amount sufficient to fund those costs.

We estimate that approximately $1,977,110 of the total costs and expenses listed above would be considered common costs. Other non-common costs included in the total given above that have been or will be borne separately by the combining partnerships are estimated to be as follows.

Dorchester Hugoton $562,000
Republic..........  130,000
Spinnaker.........   64,000
                   --------
   Total.......... $756,000
                   ========

If the combination is not approved, the general partners of Dorchester Hugoton and Spinnaker have agreed in response to the requirements of the Nasdaq National Market System to bear a portion of the transaction costs and expenses to be borne by their respective partnerships. In the case of each of Dorchester Hugoton and Spinnaker, the general partner(s) of each partnership has agreed that if the limited partners of that partnership vote to reject the combination in such amounts as would cause the combination not to be approved pursuant to

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the terms of that partnership's governing documents and applicable law, that partnership's transaction costs shall be apportioned between the general partners and limited partners of that partnership as follows:

. the general partners of that partnership bear that partnership's transaction costs in proportion to the amount of limited partner interests of that partnership voted against the combination or abstaining from the vote; and

. the limited partners of that partnership bear that partnership's transaction costs in proportion to the amount of limited partner interests of that partnership voted for the combination.

There are currently no limited partners of Republic, and the private reorganization of Republic will not occur unless all parties who would become limited partners of Republic immediately prior to the combination approve the transactions. Accordingly, if the combination does not occur, there will be no limited partners of Republic with whom the general partners would split transaction costs. Holders of Dorchester Hugoton's depositary receipts and limited partnership interests in Spinnaker will be considered to have abstained only if they provide affirmative instruction to abstain.

Additional Agreements

Each of the combining partnerships have agreed to:

. the continued post-closing indemnification of partners, affiliates of partners, directors, officers and employees of each of the combining partnerships by our partnership;

. the post-closing indemnification of our partnership by an affiliate of Republic with respect to certain litigation; and

. terminate the employment of all employees and discharge all obligations under certain employee benefit plans and cause Dorchester Minerals Operating LP to offer continued employment to terminated employees and assume any obligations under employee plans that will continue.

FAILURE TO APPROVE THE COMBINATION

If any one of the combining partnerships fails to approve the combination, the combination will not be consummated. If the combination is not consummated, each combining partnership will continue in its business as previously conducted. The general partners of each of the combining partnerships may, if the combination is not consummated, explore other alternatives, such as a sale to a third party or another business combination, but there is no assurance that they could find a third party interested in such a transaction or that the terms and conditions of any such transaction would be as favorable as the terms offered pursuant to the proposed combination. Prior efforts by the combining partnerships in respect of strategic alternatives did not produce any proposal for a transaction consistent with its partners' objectives other than the combination.

If the combination is not approved by the requisite vote of the limited partners of each of the combining partnerships, costs and expenses incurred in connection with the proposed combination will be borne by the combining partnerships as described under "The Combination Agreement--Expenses and Fees" beginning at page 70. As described in that section, the general partners of Dorchester Hugoton and Spinnaker may in some cases bear directly some of the costs allocated to their partnership.

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SPECIAL MEETINGS OF THE COMBINING PARTNERSHIPS
AND CONSENT SOLICITATION MATTERS

General

Separate special meetings of the Dorchester Hugoton and Spinnaker are being called by the applicable general partner(s) for limited partners to consider and vote to approve or disapprove of the combination agreement, and the transactions contemplated by it, and to transact such other business as may be properly presented at the special meeting or any adjournments or postponements of the meeting. The general partners of Republic are furnishing this document to all parties who, upon consummation of the Republic reorganization and immediately prior to the combination, will be limited partners of Republic, in order to solicit the approval of the combination agreement and transactions contemplated by it.

Dorchester Hugoton's special meeting will be held on , at a.m. at , Dallas, Texas .

Spinnaker's special meeting will be held on , at a.m. at , Dallas, Texas .

The consent cards relating to the Republic consent solicitation should be returned as soon as possible, but no approval will become effective until at least 60 calendar days after the date this document is mailed to the applicable Republic parties.

Voting Rights

Each limited partner appearing on the records of each of Dorchester Hugoton and Spinnaker as of , 2002 and , respectively, is entitled to notice of the applicable special meeting and is entitled to vote his partnership interests at the applicable special meeting or any adjournments of such special meeting. The general partners of Republic are soliciting consent of the parties who would become limited partners of Republic in the Republic reorganization had it occurred on , 2002.

Each partnership is voting separately on the combination. Accordingly, not all of the combining partnerships may approve the combination. The combination will not occur unless all of the combining partnerships approve the combination. Limited partners in Dorchester Hugoton and Spinnaker, and the applicable Republic parties, may vote "FOR" or "AGAINST" their respective partnership participating in the combination.

Proxy Forms and Revocation of Proxies (applies to Dorchester Hugoton and Spinnaker only)

The proxy form to be used to register your vote on the combination involving your partnership is included with this document. Please use the proxy form to cast your vote on the combination.

A limited partner or depositary receipt holder of record may grant a proxy to vote for or against, or may abstain from voting on, the combination. To be effective for purposes of granting a proxy to vote on the combination, a proxy card must be properly completed, executed and delivered to EquiServe Trust Company, N.A., in person or by mail, telegraph, telex or facsimile before the special meeting of the partnership. All partnership interests represented by properly executed proxies will, unless these proxies have been previously revoked, be voted in accordance with the instructions indicated in these proxies. If no instructions are indicated, the partnership interests will be voted for approval and adoption of the combination. A properly executed proxy marked abstain is counted as present for purposes of determining the presence or absence of a quorum at the special meeting for the applicable combining partnership, but will not be voted. Accordingly, abstentions have the same effect as a vote against the combination.

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Brokers, if any, who hold depositary receipts of Dorchester Hugoton in street name for customers have the authority to vote on "routine" proposals when they have not received instructions from beneficial owners. However, these brokers are precluded from exercising their voting discretion with respect to the approval and adoption of non-routine matters such as the combination and thus, absent specific instructions from the beneficial owner of the Dorchester Hugoton depositary receipts, brokers are not empowered to vote the Dorchester Hugoton depositary receipts with respect to the combination. These "broker non-votes" will have the effect of a vote against the combination.

You may revoke your proxy you have given at any time before that proxy is voted at the applicable special meeting by:

. giving written notice of revocation to the general partner(s) of the applicable combining partnership;

. signing and returning a later dated proxy; or

. voting in person at the special meeting.

Your notice of revocation will not be effective until the general partner(s) of the applicable combining partnerships receives it at or before the special meeting. Your presence at any special meeting will not automatically revoke your proxy in a proxy card. Revocation during any such special meeting will not affect votes previously taken. You may deliver your written notice of revocation in person or by mail, telegraph, telex or facsimile. Any written notice of revocation must specify your name and limited partner number as shown on your proxy card and the name of the combining partnership to which such revocation relates.

Action by Written Consent (applies to Republic only)

The partnership interests in Republic deemed to be represented by each executed consent submitted with respect to the proposal will be deemed to have approved and consented to the proposal. Approval of the proposal relating to the combination will be deemed to be obtained once consents have been received and not revoked from all parties who will become limited partners of Republic upon completion of the Republic reorganization, in connection with the combination. In no event will this be sooner than 60 days after the date on which the mailing of this document is complete. If a Republic party does not send in the consent card, it will have the same effect as a vote against the proposal relating to the transaction. Therefore, we urge all applicable Republic parties to complete, date, sign and return the enclosed consent card as soon as possible.

The Republic parties may revoke their consent at any time before the approval of the proposal by the applicable parties. To revoke a consent, file with the party designated below a written notice stating that you would like to revoke your consent. You can also revoke your consent, or any withholding of consent, by filing another form of written consent bearing a date later than the date of the consent. Revocations should be sent to SAM Partners, Ltd. at the following address: 3738 Oak Lawn, Suite 300, Dallas, Texas 75219.

Solicitation

The general partner(s) of the applicable combining partnerships are soliciting your proxy or written consent, as applicable, pursuant to this document. The aggregated estimated expenses and fees of the combination that have been allocated to each combining partnership include those in connection with the solicitation of the enclosed proxy as described below.

Dorchester Hugoton has retained D.F. King & Co., Inc. to assist in the solicitation of proxies from its depositary receipt holders. The total fees and expenses of D.F. King & Co., Inc. are estimated to be $20,000. In addition to solicitation by use of the mail, proxies may be solicited by D.F. King & Co., Inc. and by directors, officers and employees of the combining partnerships and by their respective general partners in person or by telephone, telegram, facsimile or e-mail. The directors, officers and employees will not be additionally compensated, but may be reimbursed for out-of-pocket expenses incurred in connection with the solicitation.

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Arrangements may also be made with other brokerage firms, banks, custodians, nominees and fiduciaries for the forwarding of proxy solicitation materials to owners of Dorchester Hugoton limited partnership interests held of record by those persons.

Voting Requirements

Approval of the combination by Spinnaker requires the approval of the general partner of Spinnaker and approval of holders of at least 85.9883% of the sharing percentages of Spinnaker. Approval of the combination by Dorchester Hugoton requires approval of both general partners and holders of more than 50% of the depositary receipts of Dorchester Hugoton. Approval of the combination by Republic requires approval of both general partners and the approval of all limited partners, after giving effect to the Republic reorganization description on page 56. If any one combining partnership fails to receive approval of the combination, the combination will not be consummated.

Procedures for Exercise of Dissenters' Rights of Appraisal

As a condition to being quoted in the Nasdaq National Market System, Nasdaq requires that limited partners in transactions such as the combination must be provided with appraisal rights under certain conditions. Accordingly, limited partners of Dorchester Hugoton and Spinnaker are entitled to such rights. The combination requires the approval of all of the Republic limited partners. Please see the discussion at "The Combination--Dissenters' Rights" beginning on page 68 of this document.

Access to Investor List/Rights of Inspection

Under the Depositary Agreement of Dorchester Hugoton, the list of depositary receipt holders of record is open at all reasonable times for inspection by record holders of depositary receipts, but such inspection may not be for the purpose of communicating with holders in the interest of a business or object other than the business of Dorchester Hugoton or a matter relating to the Depositary Agreement or the depositary receipts. In addition, under the partnership agreement of Dorchester Hugoton, the books and records of the partnership are open to inspection, audit and copying by any partner, depositary receipt holder or designated representative, at all reasonable times during any business day, at the expense of such partner.

Under the partnership agreement of Spinnaker, limited partners of Spinnaker have the right to inspect and copy a current list of the name and last known address of each partner and the percentage interests in the partnership owned by each partner. A limited partner may exercise this right on written request stating the purpose of the inspection. The inspection must be at a reasonable time and at the limited partner's expense.

MATERIAL UNITED STATES FEDERAL INCOME TAX CONSEQUENCES

In General

The following discussion is a general summary of the material United States federal income tax considerations that may be relevant to the depositary receipt holders and partners of Republic, Spinnaker and Dorchester Hugoton who are individual citizens and residents of the United States. In this discussion and unless otherwise noted, the term partner will be used to describe the partners and depositary receipt holders of Republic, Spinnaker and Dorchester Hugoton, and the term partnership interests will include partnership interest and units in Republic, Spinnaker and Dorchester Hugoton. Unless otherwise noted, this discussion expresses the opinions of both Locke Liddell & Sapp LLP, counsel to Dorchester Hugoton, and Thompson & Knight L.L.P., counsel to Republic, Spinnaker, and our partnership, insofar as they relate to legal conclusions with respect to the material United States federal income tax consequences to the partners of the combining partnerships as a result of the combination.

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In rendering these opinions, counsel has examined such documents as counsel has deemed relevant or necessary, including, but not limited to (i) the Combination Agreement, (ii) the Partnership Agreement, (iii) the provisions of this prospectus, and (iv) such other documents, records, certificates and instruments as counsel has deemed necessary or appropriate in order to enable them to render their opinions, and counsel's opinions are conditioned upon (without any independent investigation or review thereof) the truth and accuracy, at all relevant times, of the representations and warranties, covenants and statements contained therein.

The opinion of Locke, Liddell & Sapp LLP is also subject to, and conditioned upon, the receipt by counsel of certain written tax representation letters from Dorchester Hugoton, Republic, Spinnaker and us, all dated May 15, 2002, certifying as to certain factual matters relevant to the federal income tax treatment of the matters discussed in this document. The initial and continuing truth and accuracy of the representations contained in these tax representation letters constitutes an integral basis for the opinions expressed herein and these opinions are conditioned upon the initial and continuing truth and accuracy of these representations.

This discussion focuses on individual partners who are citizens or residents of the United States and, except as otherwise provided, has only limited application to corporations, partnerships, limited liability companies, estates, trusts, nonresident aliens, or other partners subject to specialized tax treatment, including, without limitation, individual retirement and other tax-deferred accounts, banks and other financial institutions, insurance companies, tax-exempt organizations, dealers, brokers or traders in securities or currencies, persons subject to the alternative minimum tax, persons who hold their partnership interests as part of a straddle, hedging, synthetic security, conversion transaction or other integrated investment consisting of the partnership interests and one or more other investments, persons whose functional currency is other than the United States dollar, persons who received their partnership interests as compensation in connection with the performance of services or on exercise of options received as compensation in connection with the performance of services and persons eligible for tax treaty benefits.

Each partner should consult its tax advisor to determine the United States federal, state, local and foreign tax consequences of the transactions applicable to it.

The discussion does not intend to be exhaustive of all possible tax considerations. For example, the discussion does not contain a description of any state, local or foreign tax considerations (except where otherwise specifically noted in this document). In addition, the summary discussion is intended to address only those United States federal income tax considerations that are generally applicable to a United States partner who holds its partnership interest (or common units after the combination) as a capital asset, and it does not discuss all aspects of United States federal income taxation that might be relevant to a specific United States partner in light of particular investment or tax circumstances.

The information in the discussion is based on the federal income tax laws as of the date of this document, which include:

. the Internal Revenue Code;

. current, temporary and proposed Treasury regulations promulgated under the Internal Revenue Code;

. the legislative history of the Internal Revenue Code;

. current administrative interpretations and practices of the Internal Revenue Service, or IRS, (including its practices and policies as expressed in private letter rulings, which are not binding on the IRS except with respect to a taxpayer that receives such a ruling); and

. court decisions.

No ruling has been or will be requested from the IRS regarding any matter affecting the combining partnerships, our partnership or their partners. Accordingly, the opinions and statements made in this discussion

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may not be sustained by a court if contested by the IRS. Furthermore, there is a risk that future legislation, Treasury regulations, administrative interpretations or court decisions will significantly change the current law or adversely affect existing interpretations of the federal income tax laws. Any change could apply retroactively to transactions preceding the date of the change.

For the reasons described below, counsel is not rendering an opinion with respect to the following specific United States federal income tax issues:

. the treatment of assignees of common units who fail to execute and deliver transfer applications (see "Consequences of Ownership of Our Common Units After the Combination--Classification of Unitholders and Assignees for Federal Income Tax Purposes");

. the validity of our partnership's monthly convention for allocating taxable income and loss between transferors and transferees of our common units (see "Consequences of Ownership of Our Common Units After the Combination--Tax Allocations by Us to Unitholders--Allocations between Transferors and Transferees");

. the validity of our partnership's method for allocating depletion deductions with respect to contributed mineral properties (see "Consequences of Ownership of Our Common Units After the Combination--Tax Allocations by Us to Unitholders--Tax Allocations with Respect to Book-Tax Difference on Contributed Properties");

. the availability and extent of percentage depletion deductions to the holders of our common units (see "Consequences of Ownership of Our Common Units After the Combination--Partnership Income, Gains/Losses and Depletion");

. the validity of our partnership's depletion, depreciation and amortization deductions relating to adjustments under Section 743(b) of the Internal Revenue Code (see "Consequences of Ownership of Our Common Units After the Combination--Section 754 Election");

. the treatment of a unitholder of our partnership whose common units are loaned to a short seller to cover a short sale of those common units (see "Consequences of Ownership of Our Common Units After the Combination--Treatment of Short Sales"); and

. the validity of our partnership's adoption of a convention that will enable you to track basis of your individual common units or unit groups (see "Consequences of Ownership of Our Common Units After the Combination--Disposition of Our Common Units").

The discussion is not intended to be, and should not be construed by the partners of the combining partnerships, and our partnership as, tax advice. Therefore, each partner is urged to consult with its tax advisor to determine the United States federal, state, local and foreign tax consequences of the transactions and the ownership of our common units, including the particular facts and circumstances that may be unique to the partner.

Consequences of Pre-Combination Transactions

Consequences of Creation of Dorchester Hugoton ORRIs by Dorchester Hugoton

Prior to the combination, Dorchester Hugoton will convey its working interest in its mineral properties to Dorchester Minerals Operating LP and retain an overriding royalty interest in the properties, referred to as the Dorchester Hugoton ORRIs. This transfer should be treated, for federal income tax purposes, as a lease of the working interest from Dorchester Hugoton to Dorchester Minerals Operating LP and should not cause the Dorchester Hugoton partners to recognize taxable gain or loss at the time of the transfer. There is no assurance that the IRS will not challenge this position. Such a challenge, if successful, could cause the Dorchester Hugoton partners to recognize more taxable income or a taxable loss as a result of the combination.

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Consequences to Dorchester Hugoton Partners of Pre-Combination Stock Sale by Dorchester Hugoton

Prior to the combination, Dorchester Hugoton intends to sell 128,000 shares of Exxon Mobil stock with an average cost basis of $19.67 per share. As a result, Dorchester Hugoton will recognize long term capital gain in an amount equal to the difference between the amount realized on the sale and Dorchester Hugoton's adjusted tax basis in the stock. This gain will be allocated among Dorchester Hugoton's partners and be included in their gross income as long term capital gain for federal income tax purposes. Some unitholders received adjustments in their share of the basis of the Exxon Mobil stock under Section 743 of the Internal Revenue Code. As a result of those adjustments, those partners will be allocated more or less gain than other partners holding the same number of Dorchester Hugoton units, or may be allocated a loss, from the sale of the Exxon Mobil stock. Dorchester Hugoton will report information relating to the amount of gain or loss allocated to each partner to assist them in preparing their individual income tax returns.

Consequences to Partners and Republic ORRI Owners of Pre-Combination Reorganization of Republic

Prior to the combination, Republic will reorganize as a limited partnership. Simultaneously, the Republic ORRIs owners will contribute the Republic ORRIs to Republic in exchange for limited partnership interests in the reorganized Republic. None of Republic, the existing partners of Republic, or the Republic ORRI owners will recognize any gain or loss for federal income tax purposes as a result of either the reorganization or the exchange.

Each Republic ORRI owner who receives a limited partner interest in the reorganized Republic will have an initial tax basis in its limited partner interest equal to the adjusted tax basis in the Republic ORRIs exchanged by the limited partner. In addition, each limited partner will have a holding period in its limited partnership interest in the reorganized Republic equal to the holding period in the Republic ORRIs exchanged by the limited partner. The tax basis and the holding period of the partnership interest of each existing Republic partner will remain unchanged as a result of the reorganization.

Locke Liddell & Sapp LLP is not rendering an opinion with respect to the tax consequences to Republic, the existing partners of Republic, or the Republic ORRI owners as a result of the reorganization of Republic.

Consequences to Partners of Republic and Spinnaker of Pre-Combination Distributions of Cash by Republic and Spinnaker

Prior to the combination, Republic and Spinnaker each will distribute cash to its partners in proportion to their partnership interests. No partner of Republic or Spinnaker will recognize any gain or loss for federal income tax purposes as a result of these distributions except to the extent that the amount of cash received by the partner exceeds the partner's adjusted tax basis in its partnership interest at the time of the distribution. Cash distributions that exceed a partner's basis will be treated as long term capital gain, taxed at a maximum 20% federal tax rate if the partner is an individual, to any partner who held its partnership interest for more than one year. Otherwise, any gain will be taxed at rates applicable to ordinary income. As a result of the distribution, each partner's adjusted tax basis in its partnership interest in Republic or Spinnaker, as applicable, will be reduced (but not below zero) by the amount of cash received.

Consequences of the Combination

In General

Pursuant to the combination, Republic and Spinnaker will each merge with and into our partnership, with our partnership surviving. As a result of these mergers, the limited partner interests held by the limited partners of Republic and the non-dissenting limited partners of Spinnaker will be converted into our common units and the general partner interests held by the general partners of Republic and Spinnaker will be converted into general partner interests in our partnership. For federal income tax purposes, Republic and Spinnaker each will

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be considered to terminate as a result of the mergers, and the following steps will be deemed to occur: (i) Republic and Spinnaker each will be deemed to have transferred all of its assets and liabilities to us in exchange for common units and general partner interests in our partnership; and (ii) immediately thereafter, Republic and Spinnaker each will be deemed to have distributed these common units and general partner interests to the non-dissenting limited partners and general partners of Republic and Spinnaker in liquidation of Republic and Spinnaker.

Also pursuant to the combination, and simultaneously with the mergers described above, Dorchester Hugoton will contribute to us the Dorchester Hugoton ORRIs and other assets not conveyed to Dorchester Minerals Operating LP or distributed to the partners of Dorchester Hugoton in exchange for our common units and the assumption by us of the balance of Dorchester Hugoton's obligations and liabilities. Following this contribution and assumption, after making any necessary payments to its creditors, Dorchester Hugoton will distribute its remaining cash and our common units to its non-dissenting depositary receipt holders and general partners in liquidation of Dorchester Hugoton. The liquidation of Dorchester Hugoton will not be taxable to its non-dissenting partners except to the extent that any cash distributed to a partner in the liquidation exceeds the partner's tax basis in his partnership interest. Cash distributions in excess of a partner's basis will be treated as long term capital gain, taxed at a maximum 20% federal tax rate, if the partner is an individual who held his units for more than one year. Otherwise the gain will be taxed at rates applicable to ordinary income.

The tax consequences of the combination to the dissenting partners of Spinnaker and Dorchester Hugoton are discussed separately below. See "Consequences of the Combination--Consequences to Dissenting Partners" below.

Nonrecognition of Gain or Loss by the Combining Partnerships and their Non-Dissenting Partners

None of the combining partnerships or our partnership will recognize any material amount of gain or loss for federal income tax purposes as a result of the combination. Likewise, no non-dissenting partner of the combining partnerships will recognize any gain or loss for federal income tax purposes as a result of the combination except to the extent that any such partner receives distributions of cash in excess of his adjusted tax basis in his interest in a combining partnership as described above. Even though a partner of a combining partnership may not recognize taxable gain at the time of the combination, the occurrence of subsequent events could cause the partner to recognize all or part of the gain that was deferred in the combination. See "Consequences of the Combination--Effects of Post-Combination Transactions on Consequences to Non-Dissenting Partners" below.

Tax Basis and Holding Period of Our Partnership in Our Assets and of Non-Dissenting Partners in Our Common Units

We will have an initial tax basis in the assets we receive in the combination equal to the adjusted tax basis of those assets immediately prior to the combination. Each partner will have an initial tax basis in our common units equal to the adjusted tax basis of the partner in its partnership interest in the applicable combining partnership immediately prior to the combination, adjusted as follows:

. the tax basis of each partner will be increased by the increase, if any, in its share of partnership liabilities as a result of the combination; and

. the tax basis of each partner will be decreased both by the decrease, if any, in its share of partnership liabilities as a result of the combination and by the amount of any cash distributed to the partner in the combination.

Our initial holding period in the assets we receive in the combination will include the holding periods of the applicable combining partnership, with respect to those assets at the time of the combination. The initial holding

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period of each partner in our common units will include the holding period of the partner in its partnership interest in the applicable combining partnership.

Limitations with Respect to Suspended Passive Activity Losses

In general, individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities only to the extent of any income from passive activities. The passive activity loss limitations apply to losses allocated to limited partners of a partnership and are applied separately with respect to each publicly traded partnership. Because Dorchester Hugoton is a publicly traded partnership engaged in a trade or business, the passive activity loss limitation rules apply to some of the partners of Dorchester Hugoton. Consequently, any passive losses relating to a partnership interest held by a Dorchester Hugoton partner are only available to offset passive income of Dorchester Hugoton allocated to the partner and will not be available to offset income from other activities or investments (whether passive or active).

Passive losses relating to an interest in a publicly traded partnership that are not deductible may be deducted in full when the taxpayer disposes of all of its interest in the partnership in a fully taxable transaction with an unrelated party. A partner may also deduct otherwise suspended passive losses to the extent the partner receives a distribution of money in excess of its adjusted tax basis in its partnership interest. The exchange of Dorchester Hugoton depositary receipts for our common units will not constitute a taxable disposition.

We do not anticipate that we will generate any passive activity income. Instead, we anticipate that our income will consist primarily of royalty income, which does not constitute passive activity income and may not be used to offset passive activity losses. Therefore, except to the extent a Dorchester Hugoton partner receives cash in excess of the adjusted tax basis in its partnership interest upon the liquidation of Dorchester Hugoton, any suspended passive activity losses that the partner has at the time of the combination will continue to be suspended until the partner disposes of our common units in a fully taxable transaction with an unrelated third party.

It is uncertain whether the recognition by one of our partners who was a partner of Dorchester Hugoton of any Built-in Gain inherent in assets contributed to us by Dorchester Hugoton will constitute gain from a passive activity against which the partner's suspended passive activity losses may be applied. See "Consequences of Ownership of Our Common Units After the Combination--Tax Allocations by Us to Unitholders--Tax Allocations with Respect to Book-Tax Difference on Contributed Properties" below.

Effect of Closing Tax Years for the Combining Partnerships

The termination of Republic and Spinnaker for federal income tax purposes will result in a closing of each of Republic's and Spinnaker's taxable year as of the date of the combination. The dissolution and liquidation of Dorchester Hugoton also will result in a closing of Dorchester Hugoton's taxable year at the time of its liquidation. As a result, if a partner has a taxable year that ends after the date of the combination or liquidation, as applicable, but before December 31, 2002, that partner will be required to include in the same taxable year its allocable share of income, gain, loss, deduction, credits and other items of the applicable combining partnership, from both the taxable year ending December 31, 2001 and the short taxable year ending at the time of the combination (in the case of Republic and Spinnaker) or the liquidation of Dorchester Hugoton, as applicable.

Effects of Post-Combination Transactions on Consequences to Non-Dissenting Partners

Even if the partners of the combining partnerships are not required to recognize taxable gain at the time of the combination, a subsequent sale of assets could cause a former partner of a combining partnership that continues as a unitholder of our partnership to recognize part or all of such gain. If, following the combination, we sell an asset that, prior to the combination, was held by a combining partnership, the former partners of the partnership which originally contributed the property to us will be allocated, for federal income tax purposes, the

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portion of the gain from the sale that is attributable to any remaining unrealized gain that existed when the asset was contributed to us. Those former partners that are specially allocated gain under these rules would report the additional gain on their own federal income tax returns, but would not be entitled to any special distributions from us in connection with a sale by us of any assets of the former partnership. Thus, the former partners may not receive cash distributions from us sufficient to pay their additional taxes if we sell properties that we acquired pursuant to the combination. For a discussion of the impact to our unitholders of unrealized gain in the absence of a sale, see "Consequences of Ownership of Our Common Units After the Combination--Tax Allocations by Us to Unitholders--Tax Allocations with Respect to Book-Tax Difference on Contributed Properties."

As a general rule, our general partner is not required to take into account the tax consequences to, or obtain the consent of, our unitholders in deciding whether to cause us to undertake specific transactions that could have adverse tax consequences to our unitholders. Our general partner has not made any commitment to the combining partnerships or any of the partners of the combining partnerships not to undertake transactions that will cause the former partners of the combining partnerships to recognize all or part of the taxable gain that was deferred through the combination.

Consequences to Dissenting Partners

A Spinnaker or Dorchester Hugoton partner who exercises its dissenters' rights with respect to the combination will not receive any of our common units, but instead will receive a certain amount of cash in exchange for its partnership interest in Spinnaker or Dorchester Hugoton, as applicable. The partner will recognize taxable gain to the extent that the amount of cash received exceeds the adjusted tax basis in its partnership interest in Spinnaker or Dorchester Hugoton, as applicable, and the partner will recognize taxable loss to the extent that the adjusted tax basis in its partnership interests in Spinnaker or Dorchester Hugoton exceeds the amount of cash received. This gain or loss generally will be capital gain or loss. Any capital gain will be taxed at a maximum federal rate of 20% if the partner is an individual and has held the partnership interest for more than one year. However, to the extent of the dissenting partner's percentage share of Dorchester Hugoton's unrealized receivables and substantially appreciated inventory items (which include depreciation, depletion and intangible drilling cost recapture), the dissenting partner will have ordinary income. Ordinary income attributable to unrealized receivables and substantially appreciated inventory items may exceed the net taxable gain realized by the dissenting partner upon the exchange of its interest and may be recognized even if there is a net taxable loss realized on the exchange of its interests. Thus, a dissenting partner may recognize both ordinary income and a capital loss upon a disposition of its interest. Net capital loss may offset no more than $3,000 of ordinary income in the case of individuals and may only be used to offset capital gain in the case of corporations.

Consequences of Ownership of Our Common Units After the Combination

Classification of Our Partnership as a Partnership for Federal Income Tax Purposes

The Treasury regulations provide that a domestic business entity not otherwise classified as a corporation with at least two members will be classified as a partnership for federal income tax purposes, unless it elects to be classified as an association taxable as a corporation. We have not made, and will not make, an election to be classified as an association. Therefore, subject to the discussion below with respect to publicly traded partnerships, we will be treated as a partnership for federal income tax purposes and will not be a taxable entity subject to federal income tax. Instead, each of our unitholders will be required to take into account its allocable share of our items of income, gain, loss, deduction and credit in computing its federal income tax liability, even if no cash distributions are made. Distributions by us to a unitholder generally will not be taxable unless the amount of cash distributed is in excess of the unitholder's adjusted tax basis in its common units.

However, Section 7704 of the Internal Revenue Code provides that a publicly traded partnership will be taxed as a corporation, unless a certain percentage of its income consists of qualifying income. A partnership constitutes a publicly traded partnership if the interests in the partnership are traded on an established securities market. Because our common units will be traded on the Nasdaq National Market System, we will be a publicly traded partnership for federal income tax purposes.

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A publicly traded partnership will not be taxed as a corporation if 90% or more of the partnership's gross income for every taxable year consists of qualifying income. Qualifying income includes income and gains from the exploration, development, mining or production, processing, refining, transportation or marketing of any mineral or natural resource. Gains from the sale of an asset used in the production of this type of income also will be qualifying income. The combining partnerships anticipate that at least 90% of our income will constitute income from its various interests in oil and natural gas properties, including royalties and net profits interests. Based upon and subject to this estimate, the factual representations made by the combining partnerships and a review of the applicable legal authorities, counsel is of the opinion that more than 90% of our gross income will constitute qualifying income.

No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status for federal income tax purposes. Instead, the combining partnerships will rely on the opinion of counsel that, based upon the Internal Revenue Code, applicable regulations, published revenue rulings and court decisions and the representations described below, we will be classified as a partnership and will not be taxed as a corporation for federal income tax purposes. In rendering its opinion, counsel is relying on the following factual representations made by us:

. we will not elect to be treated as an association taxable as a corporation; and

. for each taxable year, more than 90% of our gross income will constitute income that counsel has opined or will opine is qualifying income within the meaning of Section 7704(d) of the Internal Revenue Code.

If we fail to meet the qualifying income exception, other than a failure which is determined by the IRS to be inadvertent and which is cured within a reasonable time after discovery, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the qualifying income exception, in return for stock in that corporation, and then distributed that stock to our unitholders and the general partner in liquidation of their common units and partnership interests in our partnership. This contribution and liquidation should be tax-free to our unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we were taxable as a corporation in any taxable year, either as a result of a failure to meet the qualifying income requirement or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder's tax basis in our common units, or taxable capital gain, after the unitholder's tax basis in our common units is reduced to zero. Accordingly, taxation of our partnership as a corporation would result in a material reduction in a unitholder's cash flow and after-tax return and thus would likely result in a substantial reduction of the value of our common units.

The discussion below is based on the conclusion that we will be classified as a partnership for federal income tax purposes and will not be taxed as a corporation under Section 7704 of the Internal Revenue Code.

Classification of Unitholders and Assignees for Federal Income Tax Purposes

Our unitholders generally will be treated as partners of our partnership for federal income tax purposes, including those unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units.

A purchaser or other transferee of common units who does not advise us of its ownership of common units directly or through its broker may not receive some federal income tax information or reports furnished to record

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unitholders unless the common units are held in a nominee or street name account with a qualified securities broker. As there is no direct authority addressing ownership by these persons, counsel's opinion does not extend to these persons.

A beneficial owner of common units whose common units have been transferred to a short seller to complete a short sale would appear to lose its status as a partner with respect to those common units for federal income tax purposes. See "--Consequences of Ownership of Our Common Units After the Combination--Treatment of Short Sales."

Income, gain, deduction or losses would not be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore be fully taxable as ordinary income. Each prospective unitholder of our partnership should consult its tax advisor with respect to its status as a partner in our partnership for federal income tax purposes.

Tax Allocations by Us to Unitholders

In General

Each unitholder of our partnership will be required to report on its income tax return its allocable share of our income, gains, losses, deductions and credits. Each unitholder of our partnership will be required to include these items on its federal income tax return even if the unitholder has not received any cash distributions from us. For each taxable year, we will be required to furnish each unitholder of our partnership with a Schedule K-1 tax statement that sets forth the unitholder's share of any of our income, gains, losses, deductions and credits. Our partnership itself will not be required to pay any federal income tax.

Allocations of Income, Gain, Loss and Deductions.

Our Partnership Agreement will generally provide that our net income and net losses will be allocated to the unitholders and our general partner in accordance with their percentage interests.

Under Section 704(b) of the Internal Revenue Code, our allocation of any item of income, gain, loss or deduction to a unitholder will be given effect for federal income tax purposes so long as it has substantial economic effect, or is otherwise in accordance with the unitholder's interest in our partnership. If an allocation of an item does not satisfy this standard, it will be reallocated among the unitholders and our general partner on the basis of their respective interests in our partnership, taking into account all facts and circumstances. Except as provided below in "--Allocations between Transferors and Transferees" and "--Tax Allocations with Respect to Book-Tax Difference on Contributed Properties," counsel is of the opinion that the allocations under our Partnership Agreement will be given effect for federal income tax purposes in determining a unitholder's allocable share of an item of income, gain, loss or deduction.

Allocations between Transferors and Transferees

In general, each of our items of income, gain, loss and deduction will, for federal income tax purposes, be determined on at least a quarterly basis and, if quarterly, one third of each quarterly amount will be allocated to those unitholders who hold common units on the last business day of each month in that quarter. However, the items for the period beginning on the date the combination is consummated, referred to as the closing date, and ending on the last day of the calendar quarter in which the closing date occurs will be apportioned equally to each month ending in that quarter after the closing date and allocated to the unitholders on the last business day of each such month; and provided, that gain or loss on a sale or other disposition of any of our assets or any other extraordinary item of income or loss realized and recognized other than in the ordinary course of business, as determined by our general partner in its sole discretion, will be allocated to our unitholders and general partner on the last business day of the month in which the gain or loss is recognized for federal income tax purposes. As

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a result, a unitholder who acquires its common units in the open market may be allocated our items of income, gain, loss and deduction realized by us prior to the date of acquisition. However, in certain circumstances we may make these allocations in connection with extraordinary or nonrecurring events on a more frequent basis.

Due to the absence of specific authority on the utilization of the above method by a publicly traded limited partnership such as our partnership, counsel is unable to opine on the validity of this method of allocating our income, gain, loss and deduction between the transferors and the transferees of our common units. If this method is determined to be an unreasonable method of allocation, our income, gain, loss and deduction would be reallocated among the unitholders and our general partner. Our general partner is authorized to revise the method of allocation between transferors and transferees, as well as among unitholders whose common units otherwise vary during a taxable period, to conform to a method permitted or required by the Internal Revenue Code and applicable regulations or rulings.

A unitholder who transfers or acquires common units should consult with its tax advisor with respect to the proper reporting of its allocable share of our items of income, gain, loss and deduction during the month in which the common units are acquired or transferred.

Tax Allocations with Respect to Book-Tax Difference on Contributed Properties

Pursuant to Section 704(c) of the Internal Revenue Code, income, gain, loss and deduction attributable to appreciated or depreciated property that is contributed to a partnership in exchange for a partnership interest in the partnership must be allocated so that the contributing partner is charged with, or benefits from, respectively, the unrealized gain or unrealized loss associated with the property at the time of its contribution to the partnership. The amount of unrealized gain or unrealized loss is generally equal to the difference between the property's fair market value and its adjusted tax basis at the time of the initial contribution and is referred to as Built-in Gain and Built-in Loss, respectively. If property with Built-in Gain or Built-in Loss is sold by the partnership, then the gain or loss recognized by the partnership is required to be allocated to the contributing partner in an amount that takes into account the Built-in Gain or Built-in Loss.

The Treasury regulations require a partnership to make allocations under
Section 704(c) of the Internal Revenue Code using any reasonable method consistent with the provisions of Section 704(c) of the Internal Revenue Code and describe three different methods for taking any Built-in Gain or Built-in Loss into account that are presumed to be reasonable for purposes of Section 704(c) of the Internal Revenue Code. The Treasury regulations also provide that other methods may be reasonable in appropriate circumstances.

Under Section 613A(c)(7)(D) of the Internal Revenue Code tax depletion on oil and natural gas property held by a partnership is computed separately by each partner outside the partnership based on the partner's share of the partnership's adjusted basis in the depletable properties. Gain or loss on the disposition of a depletable property is computed separately by each partner outside of the partnership based on its share of the partnership's amount realized and adjusted tax basis in the property. Our Partnership Agreement provides that the adjusted tax basis of the oil and natural gas properties contributed to us will be allocated to the partners of the contributing partnerships for the purposes of separately determining depletion deductions, and any gain or loss recognized by us on the disposition of contributed property will be allocated to the partners of the contributing partnerships in proportion to their percentage interests in the combining partnerships to the extent of the Built-in Gain or Built-in Loss. This method of allocating Built-in Gain and Built-in Loss is not one of the three methods set forth in the Treasury regulations. However, the combining partnerships believe that the above method should be respected as reasonable and consistent with the underlying purposes of Section 704(c) of the Internal Revenue Code.

When the IRS issued the final Treasury regulations under Section 704(c) of the Internal Revenue Code, it acknowledged that the method to be used by us was used in the oil and natural gas industry and may be reasonable in appropriate situations. However, the IRS did not include this method as a specific reasonable method in the final Treasury regulations because the method was not a generally applicable method. Despite not including it as a

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specific reasonable method in the final Treasury regulations, the IRS has issued private letter rulings acknowledging that this method is reasonable under the facts of those rulings. A private letter ruling may not be relied on by any taxpayer other than the taxpayer to whom the ruling was issued. Accordingly, counsel is unable to opine on the validity of this method of allocating Built-in Gain and Built-in Loss. However, private letter rulings are indicative of the position of the IRS on the issues addressed in the rulings. Despite these prior rulings, there is no assurance that the IRS will not change its position and challenge the method to be used by us. Such a challenge, if successful, could cause one or more unitholders to recognize more taxable income or less taxable loss on an ongoing basis in respect of their common units. Each prospective unitholder is encouraged to consult with its tax advisor with respect to the proper reporting of its allocable share of Built-in Gain and Built-in Loss.

Partnership Income, Gains/Losses and Depletion

Income received by us from our oil and natural gas royalties and net profits interests will be taxable to our unitholders as ordinary income subject to depletion. Gains and losses from sales of our royalty interests and net profits interests held for more than one year, except to the extent of ordinary income recapture discussed below, will be long term capital gains and losses.

Unitholders will be entitled to deductions for the greater of either cost depletion or (if otherwise allowable) percentage depletion with respect to the oil and natural gas interests owned by us. Although the Internal Revenue Code requires each unitholder to compute its own depletion allowance and maintain records of its share of the adjusted tax basis of the underlying mineral property for depletion and other purposes, we intend to furnish each of its unitholders with information relating to this computation for federal income tax purposes.

Percentage depletion is generally available with respect to unitholders who qualify under the independent producer exemption contained in Section 613A(c) of the Internal Revenue Code. For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, natural gas, or derivative products or the operation of a major refinery. Percentage depletion is calculated as an amount generally equal to 15% (and in the case of marginal production potentially a higher percentage) of the unitholder's gross income from the depletable property for the taxable year. The percentage depletion deduction in respect of any property is limited to 100% of the taxable income of the unitholder from the property for each taxable year, computed without the depletion allowance. A unitholder that qualifies as an independent producer may deduct percentage depletion only to the extent the unitholder's daily production of domestic crude oil, or the natural gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between crude oil and natural gas production, with 6,000 cubic feet of domestic natural gas production regarded as equivalent to one barrel of crude oil. The 1,000 barrel limitation must be allocated among the independent producer and controlled or related persons and family members in proportion to the respective production by such persons during the period in question.

In addition to the foregoing limitation, the percentage depletion deduction otherwise available is limited to 65% of the unitholders' total taxable income from all sources for the year, computed without the depletion allowance, net operating loss carrybacks or capital loss carrybacks. Any percentage depletion deduction disallowed because of the 65% limitation may be deducted in the following taxable year if the percentage depletion deduction for such year plus the deduction carryover does not exceed 65% of the taxpayer's total taxable income for that year. The carryover period resulting from the 65% net income limitation is indefinite.

Some partners of Dorchester Hugoton do not qualify for percentage depletion on properties owned by Dorchester Hugoton at the time those partners acquired their units because, at that time, the Internal Revenue Code included a provision prohibiting percentage depletion on properties transferred (directly or indirectly) between taxpayers. That Code provision has been repealed but the partners affected by it remain unable to use percentage depletion. After the combination, these partners will remain unable to use percentage depletion on their share of income from the properties formerly owned by Dorchester Hugoton. However, they will be permitted to take percentage depletion, if otherwise allowable, on all other properties owned by us.

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The combination also will have the effect of reducing percentage depletion available with respect to the properties contributed to us by Dorchester Hugoton. The transfer of the working interest by Dorchester Hugoton to Dorchester Minerals Operating LP, with the reserved Dorchester Hugoton ORRIs, will have the effect of reducing the amount of gross income reported by us with respect to the properties contributed to us by Dorchester Hugoton, even though the net income will be substantially the same as if the working interest had been transferred to us. Since percentage depletion is calculated as a percentage of gross income, the reduction of our gross income from these properties will have the effect of reducing the percentage depletion deductions available to our unitholders. Whether this will decrease overall depletion for any unitholder cannot be predicted since depletion will depend in part on the costs of operation and on the individual unitholder's cost depletion deductions. As a result of these and other factors relating to the combination, the amount of depletion deductions of a partner of a combining partnership following the combination will not be the same, and may be less than, the amount of depletion deductions of the partner prior to the combination.

Unitholders that do not qualify under the independent producer exemption are generally restricted to deductions based on cost depletion. Cost depletion is calculated by (i) dividing the unitholder's share of the adjusted tax basis in the underlying mineral property by the number of mineral units (barrels of oil and thousand cubic feet, or Mcf, of gas) remaining as of the beginning of the taxable year and (ii) multiplying the result in (i) by the number of mineral units sold within the taxable year. The total amount of deductions based on cost depletion cannot exceed the unitholder's share of the total adjusted tax basis in the property.

All or a portion of any gain recognized by a unitholder as a result of either the disposition by us of some or all of our oil and natural gas interests or the disposition by the unitholder of some or all of its common units may be taxed as ordinary income to the extent of recapture of depletion deductions, except for percentage depletion deductions in excess of the basis of the property. The amount of the recapture is generally limited to the amount of gain recognized on the disposition.

The foregoing discussion of depletion deductions does not purport to be a complete analysis of the complex legislation and Treasury regulations relating to the availability and calculation of depletion deductions by the unitholders. Further, because depletion is required to be computed separately by each unitholder and not by our partnership, no assurance can be given, and counsel is unable to express any opinion, as to the availability or extent of percentage depletion deductions to the unitholders. Each prospective unitholder should consult its tax advisor to determine whether percentage depletion would be available to it.

Limitations on Deductions

Tax Basis and At-Risk Limitations

The deduction by a unitholder of any losses relating to the unitholder's common units will be limited to the tax basis in its common units. See "--Consequences of the Combination--Our Partnership's Tax Basis and Holding Period of Our Assets and of Non-Dissenting Partners in Our Common Units." In the case of an individual unitholder or a corporate unitholder of which more than 50% of the value of its stock is owned directly or indirectly by five or fewer individuals or some tax-exempt organizations, the deduction of losses will be limited to the amount for which the unitholder is considered to be "at risk" with respect to our activities, if that amount is less than the unitholder's tax basis in its common units. A unitholder must recapture losses deducted in previous years to the extent that distributions cause its at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable to the extent that the unitholder's tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a common unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any suspended losses in excess of that gain are no longer utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of its common units, excluding any portion of that tax basis attributable to its share of our liabilities, reduced by any amount of money the unitholder

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borrows to acquire or hold its common units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder, or can look only to the common units for repayment. A unitholder's at risk amount will increase or decrease as the tax basis of the unitholder's common units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in the unitholder's share of our liabilities.

Limitations with Respect to Passive Activities

In general, individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities only to the extent of the taxpayer's income from passive activities. We do not anticipate that any material amount of the activities we conduct will constitute passive activities since our assets will primarily generate portfolio income such as royalty income (which is not income from a passive activity). Thus, the passive activity loss limitations will not apply to our unitholders with respect to any material amount of our losses that may be allocated to them. These limitations will continue to apply to any suspended passive activity losses of our partners arising during their ownership of partnership interests in the combining partnerships. See "Consequences of the Combination--Limitations with Respect to Suspended Passive Activity Losses."

Limitations on Interest Deductions

The deductibility of a non-corporate taxpayer's investment interest expense is generally limited to the amount of that taxpayer's net investment income. Investment interest expense includes:

. interest on indebtedness properly allocable to property held for investment;

. interest properly allocable to portfolio income; and

. interest properly allocable to the purchase or carrying of an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder's investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry the unitholder's common units.

Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. Therefore, a unitholder's share of our portfolio income will be treated as investment income.

Distributions by Us to Unitholders

Distributions of money by us to a unitholder generally will not result in taxable income or gain to the unitholder unless, and only to the extent that, the distribution exceeds the unitholder's adjusted tax basis in its common units immediately before the distribution. Any such gain generally will be capital gain, except that a portion of such gain will be separately computed and taxed as ordinary income to the extent the distribution is in exchange for all or a part of the unitholder's common units and is attributable to the unitholder's allocable share of unrealized receivables or inventory items owned by us. Unrealized receivables include the unitholder's share of potential recapture items, including depreciation and depletion deductions. Ordinary income attributable to unrealized receivables and inventory items may exceed the net taxable gain realized.

Any reduction in a unitholder's share of our nonrecourse liabilities, including upon a non-pro rata issuance of additional common units by us without a corresponding increase in our nonrecourse liabilities, will constitute a deemed distribution of money by us to the unitholder. We are not expected to incur significant nonrecourse liabilities. Therefore, it is not anticipated that any unitholder will be deemed to receive a cash distribution from a reduction in a unitholder's share of nonrecourse liabilities that would result in the recognition of a material amount of taxable gain.

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Ratio of Taxable Income to Distributions

The ratio of the amount of taxable income that will be allocated to each unitholder to the amount of cash that will be distributed to the unitholder is uncertain. The amount of taxable income realized by each unitholder will be dependent upon a number of factors including: (a) the amount of taxable income recognized by us; (b) the amount of any gain recognized by us that is attributable to specific asset sales that may be wholly or partially attributable to Built-in Gain and the resulting allocation of such gain to the former partners of the applicable combining partnerships, depending on the asset being sold (see "Consequences of Ownership of Our Common Units After the Combination--Tax Allocations by Us to Unitholders--Tax Allocations with Respect to Book-Tax Difference on Contributed Properties"); and (c) the amount of basis adjustment pursuant to Section 754 of the Internal Revenue Code available to the unitholder based on the purchase price for any common units and the amount by which such price exceeded the unitholder's proportionate share of inside tax basis of our assets attributable to the common units when the common units were purchased (see "Consequences of Ownership of Our Common Units After the Combination--Section 754 Election").

Tax Basis in Our Assets

The tax basis of our mineral interests will be used for purposes of computing gain or loss on the disposition of these interests. The federal income tax burden associated with the difference between the fair market value of property contributed to us and the tax basis established for that property will be borne by the contributing partners of the applicable combining partnership to the extent of any Built-in Gains. See "Consequences of Ownership of Our Common Units After the Combination--Tax Allocations by Us to Unitholders--Tax Allocations with Respect to Book-Tax Difference on Contributed Properties."

Tax Basis in Our Common Units

Generally, each partner will have an initial tax basis in our common units equal to its adjusted tax basis in the partnership interest in the applicable combining partnership immediately prior to the combination decreased by the amount of cash received or deemed to be received by the partner in the combination. See "Consequences of the Combination--In General."

After the combination, a unitholder's adjusted tax basis in its common units generally will be increased by (a) the unitholder's allocable share of our taxable and tax exempt income, (b) any contributions by the unitholder to our capital, and (c) any increases in the unitholder's allocable share of our liabilities. Generally, a unitholder's adjusted tax basis in its common units will be decreased (but not below zero) by (1) the unitholder's allocable share of our losses and nondeductible expenditures which are not chargeable to capital, (2) the amount of any cash and the amount of the basis of any property distributed to the unitholder by us, (3) any decreases in the unitholder's allocable share of our liabilities, and (4) the amount of any depletion deductions taken by the unitholder with respect to its common units to the extent the deductions do not exceed the unitholder's proportionate share of the adjusted tax basis of the underlying producing property.

Disposition of Our Common Units

A unitholder will recognize gain or loss on a sale of its common units in an amount equal to the difference between the amount realized and the unitholder's adjusted tax basis in the common units sold. A unitholder's amount realized will be measured by the sum of any cash and the fair market value of any other property received plus the unitholder's share of our nonrecourse liabilities, if any.

Except as noted below, gain or loss recognized by a unitholder, other than a dealer in common units, on the sale or exchange of common units held by the unitholder generally will be capital gain or loss. However, this gain or loss will be taxed as ordinary income or loss to the extent attributable to the unitholder's allocable share of unrealized receivables or inventory items owned by us. Unrealized receivables include the unitholder's share of potential recapture items, including depletion deductions to the extent such deductions previously reduced a

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unitholder's basis in its common units. Ordinary income attributable to unrealized receivables and inventory items may exceed the net taxable gain realized upon the sale of the common units and may be recognized even if there is a net taxable loss realized on the sale of the common units. Thus, a unitholder may recognize both ordinary income and a capital loss upon a disposition of its common units. Net capital loss may offset no more than $3,000 of ordinary income in the case of individuals and may only be used to offset capital gain in the case of corporations.

A unitholder who acquires its common units in separate transactions must maintain a single adjusted tax basis for federal income tax purposes with respect to those common units. According to an IRS ruling, upon a sale or other disposition of less than all of those common units, a portion of the combined tax basis must be allocated to the common units sold using an "equitable apportionment" method. Although the ruling is unclear as to how the holding period of these interests is determined once they are combined, recently finalized regulations allow a selling unitholder who can identify an ascertainable holding period with respect to the common units transferred to elect to use the actual holding period of the common units transferred provided that the unitholder consistently uses that method for all subsequent common unit transactions. Thus, according to the ruling, a unitholder will be unable to select high or low tax basis common units to sell as would be the case with corporate stock, but, under the recently finalized regulations, can designate specific common units for purposes of determining the holding period of the common units to be sold. Notwithstanding the position of the IRS ruling, we intend to adopt a convention that will enable unitholders to track basis of individual common units or unit groups and use the basis so determined in calculating unitholders' basis adjustments under Section 743 of the Internal Revenue Code and gain or loss on the sale of common units. Currently available tax accounting software will not permit us to follow exactly the requirements of the IRS ruling. Although our general partner believes that our method is reasonable, no assurance can be given that the IRS will not challenge our method. In light of the conflicting IRS ruling, counsel is unable to opine that our method is permissible.

A unitholder considering the purchase of additional common units or a sale of common units purchased in separate transactions should consult its tax advisor as to the possible consequences of this ruling and application of the new regulations.

For individuals, trusts and estates, net capital gain from the sale of an asset held one year or less is subject to tax at the applicable rate for ordinary income. For these taxpayers, the maximum federal rate of tax on the net capital gain from a sale or exchange of an asset held for more than one year generally is 20%.

Provisions of the Internal Revenue Code may cause a unitholder to be treated as having sold appreciated common units at their fair market value resulting in the recognition of taxable gain if the taxpayer or related persons enter(s) into:

. a short sale;

. an offsetting notional principal contract; or

. a futures or forward contract with respect to the common units or substantially identical property.

Moreover, if a unitholder has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the common units, the unitholder will be treated as having sold that position if the taxpayer or a related person then acquires the common units or substantially identical property. Further, the Secretary of Treasury is authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position. See "Consequences of Ownership of Our Common Units After the Combination--Treatment of Short Sales" below.

Treatment of Short Sales

A unitholder whose common units are loaned to a short seller to cover a short sale of common units may be considered as having disposed of ownership of those common units for federal income tax purposes. If so, the

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unitholder would no longer be a partner for tax purposes with respect to those common units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:

. any of our income, gain, loss or deduction with respect to those common units would not be reportable by the lending unitholder;

. any cash distributions received by the lending unitholder for those common units would be fully taxable and would appear to be treated as ordinary income.

Counsel is not rendering an opinion regarding the treatment of a unitholder whose common units are loaned to a short seller. Therefore, unitholders desiring to assure their status as partners for federal income tax purposes and avoid the risk of gain recognition should modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units. See "Consequences of Ownership of Our Common Units After the Combination--Disposition of Our Common Units."

Constructive Termination

We will be considered to terminate for tax purposes if there is a sale or exchange of 50% or more of the total interests in its capital and profits within a 12-month period. A termination of our partnership will result in the closing of its taxable year for all unitholders. As a result, if a unitholder has a different taxable year than us, the unitholder may be required to include in the same taxable year its allocable share of our income, gain, loss, deduction, credits and other items from both the taxable year ending prior to the year of the termination of our partnership and the short taxable year ending at the time of the termination. In addition, we would be required to make new tax elections after a termination, including a new election under
Section 754 of the Internal Revenue Code. A termination also could result in penalties if we were unable to determine that the termination occurred.

Section 754 Election

We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit us to make an adjustment, referred to as the Section 743(b) adjustment, to a unitholder's tax basis in our assets, referred to as inside basis, to reflect the unitholder's purchase price in its common units. This election does not apply to a person who purchases common units directly from us or with respect to those common units issued to partners of the combining partnerships as a part of the combination. It will apply to any purchaser of common units after the combination. The Section 743(b) adjustment belongs solely to the purchaser and not to the other unitholders. For purposes of this discussion, a unitholder's inside basis of our assets will be considered to have two components:

. the unitholder's share of our tax basis in our assets; and

. the unitholder's Section 743(b) adjustment to that tax basis.

Our general partner intends to utilize a method of calculating inside basis, including the unitholders' Section 743(b) adjustments, which will result in an aggregate basis for depletion purposes that reflects the purchase price of common units as paid by the unitholders. Although the method our general partner intends to use is not specifically authorized under the applicable Treasury regulations, we believe that it is a reasonable method of determining each unitholder's share of net income or loss (including depletion and gain or loss from the sale of property). Because there is no clear authority on this issue, counsel is unable to opine as to this method. If the IRS successfully contends that such method may not be used, our general partner may use any other reasonable depletion conventions to preserve the uniformity of the intrinsic tax characteristics of any common units that would not have a material adverse effect on the unitholders or record holders of any class or classes of units.

A Section 754 election is advantageous if the transferee's tax basis in its common units is higher than the common units' share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a

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result of the election, the transferee would have a higher tax basis in its share of our assets for purposes of calculating, among other items, its depletion deductions and its share of any gain or loss on a sale of our assets. Conversely, a Section 754 election is disadvantageous if the transferee's tax basis in its common units is lower than those common units' share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the common units may be affected either favorably or adversely by the Section 754 election.

The calculations involved in the Section 754 election are complex and we will make them on the basis of assumptions as to the fair market value of our assets and other matters. The allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment. We cannot assure our unitholders that the determinations made by us will not be successfully challenged by the IRS or that the deductions resulting from these determinations may not be reduced or disallowed altogether. Should the IRS require a different basis adjustment, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of common units may be allocated more income that it would have been allocated had the election not been revoked.

Alternative Minimum Tax on Items of Tax Preference

The Internal Revenue Code contains alternative minimum tax rules that are applicable to corporate and noncorporate taxpayers. We will not be subject to the alternative minimum tax, but our unitholders are required to take into account on their own tax returns their respective shares of our tax preference items and adjustments in order to compute their alternative minimum taxable income.

The minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Although it is not expected that we will generate significant tax preference items or adjustments, since the impact of the alternative minimum tax depends on each unitholder's particular situation, each prospective unitholder should consult with its tax advisor as to the impact of an investment in common units on its alternative minimum tax liability.

Considerations for Tax-Exempt Limited Partners

Unitholders that are tax-exempt entities, including charitable corporations, pension, profit-sharing or stock bonus plans, Keogh plans, individual retirement accounts and certain other employee benefit plans are subject to federal income tax on unrelated business taxable income, referred to as UBTI. Generally, UBTI can arise from a trade or business unrelated to the exempt purposes of the tax-exempt entity that is regularly carried on by either the tax-exempt entity or a partnership in which it is a partner. However, UBTI does not apply to interest income, royalties (including overriding royalties) or net profits interests, whether the royalties or net profits are measured by production or by gross or taxable income from the property. Pursuant to the provisions of our Partnership Agreement, our general partner shall use all reasonable efforts to prevent us from realizing income that would constitute UBTI. However, there is no assurance that we will not incur UBTI.

Administrative Matters

Accounting Method and Taxable Year

We will use the year ending December 31 as our taxable year and we will adopt the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income its share of our income, gain, loss and deduction for our taxable year ending within or with the unitholder's taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of its common units following the close of our taxable year but before the close of the unitholder's taxable year

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must include the unitholder's allocable share of our income, gain, loss and deduction for one year ended on the pervious December 31, as well as for the portion of our current tax year ending on the date of the disposition, in income for its taxable year, with the result that the unitholder could be required to include in income for its taxable year its share of more than one year of our income, gain, loss and deduction. See "Consequences of Ownership of Our Common Units After the Combination--Tax Allocations by Us to Unitholders--Allocations between Transferors and Transferees." Because of differences between generally accepted accounting principles, which apply to the financial statements that will be issued by Dorchester Minerals, and the tax accounting method described above, net income of Dorchester Minerals as reported on its financial statements will likely differ from the taxable income for the same period.

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1 tax statement, which describes each unitholder's share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will generally not be reviewed by counsel, we will use various accounting and reporting conventions, some of which have been mentioned earlier, to determine the unitholder's share of income, gain, loss and deduction. We cannot assure unitholders that any of those conventions will yield a result that conforms to all of the technical requirements of the Internal Revenue Code, regulations or administrative interpretations of the IRS. Neither we nor our counsel can assure prospective unitholders that the IRS will not successfully contend in court that those accounting and reporting conventions are impermissible. Any challenge by the IRS could negatively affect the value of the common units. In addition, the cost of any contest will be borne directly or indirectly by the unitholders.

The IRS may audit our federal income tax information returns. The Internal Revenue Code contains partnership audit procedures governing the manner in which the IRS audit adjustments for partnership items are resolved. Adjustments resulting from any audit of this kind may require each unitholder to adjust a prior year's tax liability, and possibly may result in an audit of that unitholder's own return. Any audit of a unitholder's return could result in adjustments not related to our returns as well as those related to our returns. It is our understanding that the IRS has begun "matching" a partner's partnership information as reported on that partner's individual income tax return against the electronic Schedule K-1 tax information that we are required to provide to the IRS. Thus, if the IRS continues this practice and you do not report tax information on your tax returns in a manner that is consistent with your Schedule K-1 tax statement, the IRS matching program may trigger an inquiry or possibly an audit of your individual tax return.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code provides for one partner to be designated as the "Tax Matters Partner" for these purposes. Our Partnership Agreement appoints our general partner as our Tax Matters Partner.

The Tax Matters Partner will make some elections on our behalf and on behalf of the unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against the unitholders for items in our returns. The Tax Matters Partner will make a reasonable effort to keep each unitholder informed of administrative and judicial tax proceedings with respect to our items in accordance with applicable Treasury regulations. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in our partnership to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

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Accuracy-related Penalties

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

A substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

. for which there is, or was, "substantial authority"; or

. as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

Based upon representations of our general partner that a significant purpose for our partnership is not the avoidance of federal income tax, the more stringent rules that apply to tax shelters should not apply to us. If any item of income, gain, loss or deduction included in the distributive shares of the unitholders might result in that kind of an understatement of income for which no "substantial authority" exists, we must disclose the pertinent facts on its return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns to avoid liability for this penalty. A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 200% or more of the amount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 400% or more than the correct valuation, the penalty imposed increases to 40%.

Nominee Reporting

Persons who hold our common units as a nominee for another person are required to furnish to us:

. the name, address and taxpayer identification number of the beneficial owner and the nominee;

. whether the beneficial owner is a person that is not a United States person, a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing, or a tax-exempt entity;

. the amount and description of common units held, acquired or transferred for the beneficial owner; and

. specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on common units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the common units with the information furnished to us.

Registration as a Tax Shelter

The Internal Revenue Code requires that tax shelters be registered with the Secretary of the Treasury. The temporary Treasury regulations interpreting the tax shelter registration provisions of the Internal Revenue Code are extremely broad. It is arguable that we will be exempt from the registration requirement by qualifying as a

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projected income investment. An investment in our common units is not expected to reduce the cumulative federal income tax liability of any unitholder with respect to any year for the first five years ending after the date on which such common units first become available. However, we will register as a tax shelter with the Secretary of Treasury in the absence of assurance that we will not be subject to tax shelter registration and in light of substantial penalties which might be imposed if registration is required and not undertaken.

ISSUANCE OF THIS REGISTRATION NUMBER DOES NOT INDICATE THAT INVESTMENT IN US

OR THE CLAIMED TAX BENEFITS HAVE BEEN REVIEWED, EXAMINED OR APPROVED BY THE IRS.

We will supply our tax shelter registration number to you when one has been assigned to us. A unitholder who sells or otherwise transfers a common unit in a later transaction must furnish the registration number to the transferee. The penalty for failure of the transferor of a common unit to furnish the registration number to the transferee is $100 for each failure. The unitholders must disclose our tax shelter registration number on Form 8271 to be attached to the tax return on which any deduction, loss or other benefit we generate is claimed or on which any of our income is included. A unitholder who fails to disclose the tax shelter registration number on his return, without reasonable cause for that failure, will be subject to a $250 penalty for each failure. Any penalties discussed are not deductible for federal income tax purposes.

Entity-Level Collections

Our general partner is authorized to take any action that it determines in its discretion to be necessary or appropriate to cause us to comply with any withholding requirements established under the Internal Revenue Code or any other federal, state or local law. To the extent that we are required or elect to withhold and pay over to any taxing authority any amount resulting from the allocation or distribution of income to any unitholder, the amount withheld may, at the discretion of our general partner, be treated by us as a distribution of cash in the amount of the withholding from the unitholder.

State and Local Taxes

In addition to the federal income tax aspects described above, a unitholder should consider the potential state and local tax consequences of owning our common units. Tax returns may be required and tax liability may be imposed both in the state or local jurisdictions where a unitholder resides and in each state or local jurisdiction in which we have assets or otherwise do business. Thus, persons holding our common units either directly or through one or more partnerships or limited liability companies may be subject to state and local taxation in a number of jurisdictions in which we directly or indirectly hold oil and gas properties and would be required to file periodic tax returns in those jurisdictions. We also may be required to withhold state income tax from distributions otherwise payable to our unitholders. For example, withholding will be required with respect to properties located in Louisiana. We anticipate providing our unitholders with summary federal information, broken down by state which may be used by them in preparing their state and local returns. To the extent that a unitholder pays income tax with respect to our income to a state where it is not resident or to the extent that we are required to pay state income tax on behalf of such unitholder, the unitholder may be entitled to a deduction or credit against income tax that it otherwise would owe to its state of residence with respect to the same income.

No ruling or opinion has been requested from any state or local taxing authority with respect to the combination or any of the other transactions discussed in this document. Each prospective unitholder should consult with its tax advisor regarding the state and local income tax implications of owning our common units.

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Notification Requirements

A person who purchases common units from a unitholder is required to notify us in writing of that purchase within 30 days after the purchase. We are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Additionally, a transferor and a transferee of common units will be required to furnish statements to the IRS, filed with their income tax returns for the taxable year in which the sale or exchange occurred, that describe the amount of the consideration received for the common unit that is allocated to our goodwill or going concern value, if any. Failure to satisfy these reporting obligations may lead to the imposition of substantial penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker.

Backup Withholding

The Internal Revenue Code requires backup withholding at a rate of thirty percent (30%) with respect to all reportable payments. A reportable payment includes not only reportable interest or dividend payments but also other payments including some royalty payments. Accordingly, subject to the limitations discussed below, a unitholder may be subject to backup withholding with respect to all or a portion of its distributions from us.

Backup withholding is required with respect to any reportable payment if the payee fails to furnish its taxpayer identification number, referred to as TIN, to the payor in the required manner or to establish an exemption from the requirement or if the Secretary of the Treasury notifies the payor that the TIN furnished by the payee is incorrect. Accordingly, a unitholder may avoid backup withholding by furnishing its correct TIN to us. Any unitholder who does not provide its TIN to us should consult its tax advisor concerning the applicability of the backup withholding provisions to its distributions from us.

BUSINESS OF DORCHESTER MINERALS AFTER COMPLETION OF THE COMBINATION

General

We were formed as a Delaware limited partnership in December, 2001 in connection with the proposed combination. Our business plan is to own and hold the Operating ORRIs and the properties acquired from Republic and Spinnaker, which consist of producing and non-producing mineral, royalty, overriding royalty and leasehold interests and which we refer to as the royalty properties. We will distribute on a quarterly basis all cash that we receive from the ownership of those interests 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. One of our objectives will be 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. No specific assets have been identified for sale, financing, refinancing or purchase following the consummation of the combination.

We intend to grow by encouraging the exploration and development of the royalty properties and 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:

. in exchange for our limited partner interests, including common units, not exceeding 20% of the common units outstanding after issuance; or

. in exchange for cash, if the aggregate cost of any acquisitions made for cash during the twelve month period ending on the first to occur of the execution of a definitive agreement for the acquisition or its consummation is no more than ten percent (10%) of our aggregate cash distributions for the four most recent fiscal quarters.

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Properties

Operating ORRIs

A principal asset of our partnership are 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 the minor working interest properties to be conveyed by Republic and Spinnaker to Dorchester Minerals Operating LP promptly after the combination. We believe that the exclusion of excluded information will represent a less than 1% change in each item of information set forth below.

Acreage

The following table sets forth as of January 1, 2002 the pro forma combined developed and undeveloped acreage subject to the Operating ORRIs giving effect to the combination and assuming the consummation of the combination as of such date. Acreage in which an interest is limited to royalty, overriding royalty or the similar interests is excluded. Undeveloped acreage underlies the Oklahoma developed acreage.

           Developed    Undeveloped
         ------------- -------------
Location Gross   Net   Gross   Net
-------- ------ ------ ------ ------
Oklahoma 79,861 74,031 47,360 46,960
Kansas..  7,035  7,035     --     --
         ------ ------ ------ ------
Total... 86,896 81,066 47,360 46,960
         ====== ====== ====== ======

Costs Incurred and Drilling Results

The following table sets forth the pro forma information regarding 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.

                  Years Ended December 31,
                  ------------------------
                    2001      2000   1999
                   ------    ----   ----
                       (in thousands)
Acquisition costs $5,297*    $ 23   $ 16
Development costs    240      301    332
                   ------     ----   ----
Total............ $5,537     $324   $348
                   ======     ====   ====


/* Includes $5,270,000 paid for an Oklahoma production payment. See "Information Concerning Dorchester Hugoton--Management's Discussion and Analysis of Financial Condition and Results of Operation." /

Productive Well Summary

The following table sets forth as of January 1, 2002 the pro forma combined number of producing wells on the properties subject to the Operating ORRIs giving effect to the combination and assuming the consummation of the combination as of such date.

         Productive Wells
         ----------------
Location Gross      Net
-------- -----     -----
Oklahoma  127     115.2
Kansas..   20      20.0
          ---      -----
Total...  147     135.2
          ===      =====

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Royalty Properties

Another principal asset of our partnership will be the royalty properties, which will be directly owned by our partnership.

Acreage

The following table sets forth as of January 1, 2002 a pro forma 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 development status of the acres in each category giving effect to the combination and assuming the consummation of the combination as of such date.

                                 Mineral
                            -----------------         Overriding
                            Leased  Unleased  Royalty  Royalty   Leasehold   Total
                            ------- --------- ------- ---------- --------- ---------
Number of States...........      18        25      17       18         8          27
Number of Counties/Parishes     207       424     192      131        35         564
Gross...................... 603,410 1,554,444 574,415  196,131    35,678   2,958,366
Net (where applicable).....  69,218   276,795     N/A      N/A       N/A     346,013

Our net interest in production from royalty, overriding royalty and leasehold interests is based on burdens or reservations which vary from property to property. Consequently, net acreage ownership in these categories is not determinable.

The following table sets forth as of January 1, 2001 the pro forma 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 and assuming the consummation of the combination as of such date.

   State     Gross   Net      State       Gross     Net
----------- ------- ------ ------------ --------- -------
Alabama.... 106,074  7,517 Missouri....       344      43
Arkansas...  45,548 15,453 Montana.....   285,232  62,850
California.     924    162 Nebraska....     3,360     256
Colorado...  22,880  1,423 New Mexico..    31,548   2,202
Florida....  88,832 24,249 New York....    23,077  18,440
Georgia....   3,676  1,024 North Dakota   296,348  37,694
Illinois...   4,480    761 Oklahoma....   211,370  15,166
Indiana....     302    113 Pennsylvania    10,016   4,841
Kansas.....   9,073  1,334 South Dakota    14,007   1,266
Kentucky...   1,995    552 Texas....... 1,515,519 135,627
Louisiana.. 112,093  2,353 Utah........     5,937     200
Michigan...  54,367  2,623 Wyoming.....    28,888   1,256
Mississippi  80,070  8,607

Activity Summary

As a royalty owner, our access to information concerning activity and operations on our 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 our properties at any point in time is not determinable. The primary manner by which we will become aware of activity on our properties is the receipt of division orders or other correspondence from operators or purchasers.

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The following table sets forth a pro forma summary of leases consummated and new wells added during 1997 through 2001 giving effect to the combination and assuming the consummation of the combination on December 31 of each year.

                            2001       2000        1999        1998       1997
                          --------  ----------  ----------  ----------  --------
Consummated Leases
   Number................       17          47          26          41        58
   Number of States......        5           6           6           8         8
   Number of Counties....       14          25          21          32        30
   Average Royalty.......     23.7%       24.8%       24.9%       24.8%     24.8%
   Average Bonus, $/acre. $    272  $      150  $      192  $      162  $    164
   Total Lease Bonus..... $173,217  $  436,627  $  744,938  $1,313,355  $601,325
Other Land Revenue....... $330,714  $2,260,342  $  558,981  $  828,890  $ 72,539
                          --------  ----------  ----------  ----------  --------
Total Land Revenue....... $503,931  $2,696,969  $1,303,919  $2,142,245  $673,864
                          ========  ==========  ==========  ==========  ========
New Wells Added
   Number................      212         124         150         179       117
   Number of States......       11           8           8          10         9
   Number of Counties....       64          49          50          57        51

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, 2001 for the Operating ORRIs and the royalty properties giving effect to the combination and assuming the consummation of the combination as of such date.

                                             Operating ORRIs Royalty Properties   Total
                                             --------------- ------------------ ----------
Proved developed reserves
   Natural gas (Mcf)........................    46,838,709       30,876,400     77,715,109
   Oil (Bbls)...............................            --        4,158,270      4,158,270
Proved reserves
   Natural gas (Mcf)........................    46,838,709       34,691,700     81,530,409
   Oil (Bbls)...............................            --        4,374,768      4,374,768
Future net revenues ($, in thousands).......   $  63,948.1        149,986.7      213,934.8
SEC PV-10 present value(1) ($, in thousands)   $  43,371.2         76,917.5      120,288.7


(1) We do not reflect a federal income tax provision since our partners will include the income of our partnership in their respective federal income tax returns.

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Capitalization

The following table sets forth as of January 1, 2002 the pro forma capitalization of our partnership giving effect to the combination and assuming the consummation of the combination as of such date and no eligible limited partners elect to exercise dissenters' rights.

                                               January 1, 2002
                                           ------------------------
                                           Combined(1) Pro forma(2)
                                           ----------- ------------
                                              (amounts in 000's)
Partners' capital
   General partners.......................   $ 3,152     $  3,152
   Limited partners.......................    80,325      120,854
   Accumulated other comprehensive income.     2,513           --
                                             -------     --------
                                             $85,990     $124,006
                                             =======     ========


(1) Amounts represent the aggregate capital of the combining partnership before giving effect to the combination transaction.
(2) Amounts represent the aggregate capital of the combining partnerships, adjusted to give effect a revaluation of assets using purchase accounting of $153,358 less a write-down of $94,514 to the estimated amount of discounted future net cash flows from the oil and gas properties. See Pro Forma Financial Information beginning on page P-1.

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. 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 in "--General."

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 which would represent over 20 percent of the outstanding limited partnership interests immediately after giving effect to such issuance 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:

. requiring permits for the drilling of wells;

. maintaining bonding requirements in order to drill or operate wells;

. regulating the location of wells;

. the method of drilling and casing wells;

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

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. the plugging and abandonment of wells;

. numerous federal and state safety requirements;

. environmental requirements;

. property taxes and severance taxes; and

. specific state and federal income tax provisions.

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 the 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.

Competition

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

Operating Hazards and Uninsured Risks

Our operations will 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, whose operations may be materially curtailed, delayed or canceled as a result of numerous factors, including:

. the presence of unanticipated pressure or irregularities in formations;

. accidents;

. title problems;

. weather conditions;

. compliance with governmental requirements; and

. shortages or delays in the delivery of equipment.

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:

. capacity and availability of oil and natural gas systems and pipelines;

. effect of federal and state production and transportation regulations;

. changes in supply and demand for oil and natural gas; and

. creditworthiness of the purchasers of oil and natural gas.

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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 will maintain insurance against some, but not all, of the risks that our business exposes us to. While we believe that we will be 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.

Legal Proceedings

We expect to be involved from time to time in various legal and administrative proceedings and threatened legal and administrative proceedings incidental to the ordinary course of our business. As a result of the combination, we will assume any liabilities relating to the legal proceedings involving Dorchester Hugoton and Republic, including those described in "Information Concerning Dorchester Hugoton--Legal Proceedings" and "Information Concerning Republic--Legal Proceedings." Other than those legal proceedings, neither we nor any of the combining partnerships is now involved in any litigation, individually or in the aggregate, which could have a material adverse effect on our business, financial condition, results of operations, or cash flows after giving effect to the combination as if the combination has occurred.

Facilities

On a pro forma combined basis, Dorchester Minerals Operating LP will lease 13,420 square feet in Dallas and Garland, Texas for our partnership offices.

Employees

As of January 1, 2002, on a pro forma combined basis Dorchester Minerals Operating LP will have 16 full and part-time permanent employees in our Dallas and Garland, Texas offices and nine employees in field locations, including Amarillo, Texas. None of these employees is represented by a union and we believe that we will maintain good relations with our employees.

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 our 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.

We have prepared the following unaudited table, which demonstrates the effect that changes in the prices for oil and natural gas could have on cash distributions. The following table reflects hypothetical cash distributions per unit for a calendar year based on certain production volume and operating cost assumptions and a range of oil and natural gas prices. See "Information Concerning Dorchester Hugoton," "Information Concerning Republic"

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and "Information Concerning Spinnaker" for a description of actual average sales prices for each combining partnership.

The table is not a projection or forecast of the actual or estimated results from an investment in our common units. The purpose of the table is to illustrate the sensitivity of cash distributions to changes in the prices of oil and natural gas assuming hypothetical amounts of production and expenses. There is no assurance that the assumptions described below will actually occur or that the prices of oil or natural gas will not change by amounts different from those in the table. Other factors can and will impact the amount of our cash distributions.

Due to fluctuating production volumes, product prices and operating expenses, the amount of quarterly cash distributions from us is expected to vary during the year. Quarter-to-quarter distributions will also vary based on the timing of development expenditures by the operators of our properties and the net profits, if any, generated by such development projects.

Price Sensitivity of Hypothetical Total Cash Distributions Per Common Unit
--------------------------------------------------------------------------
Net Wellhead
  Oil Price                             Net Wellhead Gas Price
   per Bbl                                      per Mcf
   ----                  -----------------------------------------------------
                            $2.00            $2.50        $3.00       $3.50
                         -----            -----        -----       -----
   $15.00............... 0.72             0.90         1.08        1.26
    20.00............... 0.78             0.96         1.14        1.32
    25.00............... 0.84             1.02         1.20        1.38
    30.00............... 0.89             1.08         1.26        1.44

Significant Assumptions Used to Prepare the Sensitivity of Hypothetical Total Cash Distributions

Timing of Actual Distributions. Our net income for financial statement purposes will be presented on an accrual basis in accordance with generally accepted accounting principles. Distributions, however, will be calculated on the basis of actual cash receipts and disbursements by us during the relevant reporting period. As a result, the proceeds of production will not actually enter into the calculation determining the amount, if any, of our cash distributions for a quarter until a point in time after the production giving rise to those proceeds.

Production Estimates. Oil and natural gas production volumes are assumed to be equal to actual net amounts for 2001 as set forth below:

                   Net Oil (Bbls) Net Gas (MMcf)
                   -------------- --------------
Dorchester Hugoton          0       6,115,000
Republic..........    277,653       2,717,207
Spinnaker.........     88,514       2,247,204

Net gas production volumes include an equivalent volume attributable to natural gas liquids and other plant products.

Differing levels of production volumes and production costs will result in cash distributions different than those set forth in this sensitivity table.

Other Income. This sensitivity table assumes no lease bonus, delay rental or other revenue is received by our partnership.

Expenses. Lease operating expenses, excluding capital expenditures, attributable to the properties underlying the Operating ORRIs are assumed to be $3,620,918, which is based on 2001 actual expenses. Severance taxes are included at 2001 percentages of gross revenues. Other operating expenses attributable to our

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properties are assumed to be $101,000. Direct expenses and administrative expenses are primarily based on actual expenses. Direct expenses are assumed to be $700,000 and administrative expenses are assumed to be $1,000,000 in accordance with our Partnership Agreement.

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 to foreign currency related market risk.

INFORMATION CONCERNING DORCHESTER HUGOTON

General

Dorchester Hugoton is a publicly traded limited partnership that owns, produces, gathers and sells natural gas almost exclusively from wells in the Hugoton gas field in western Oklahoma and Kansas. Sales are currently made primarily to two customers under short-term contracts that provide for prices based on the field market price.

Dorchester Hugoton was formed on June 16, 1982 as a Texas limited partnership pursuant to a Certificate and Agreement of Limited Partnership. Depositary receipts for units of limited partnership interest were originally distributed on August 20, 1982 to holders of common stock of Dorchester Gas Corporation in the form of a taxable property dividend.

Dorchester Hugoton's principal operating assets consist of working interests and support facilities for properties that produce natural gas from the Hugoton field. Most of Dorchester Hugoton's current working interest wells were drilled and have been producing since prior to 1954. Dorchester Hugoton has operated most of its properties since July 1, 1984.

Dorchester Hugoton is limited as to the activities it may engage in by its partnership agreement and has not engaged in any recent material acquisition of additional properties or any exploration and development activities except on a very limited basis as described below.

Properties and Operations

Oklahoma

Dorchester Hugoton's Oklahoma working interests encompass 127 natural gas wells (115.2 net wells) in the Guymon-Hugoton field. Dorchester Hugoton operates and owns interests in 117 wells in Oklahoma. Of these wells, Dorchester Hugoton has a 100% working interest in 109 wells, working interests ranging from 50% to 88% in five wells and liquefiable hydrocarbons interests only in the remaining three wells. Dorchester Hugoton also has working interests ranging from 25% to 50% per well in a 10 well group operated by an unaffiliated third party. Dorchester Hugoton also has minor royalty interests in various producing natural gas wells.

Of Dorchester Hugoton's 127 gas wells, 124 deliver natural gas through a 132-mile Dorchester Hugoton owned and operated gas pipeline gathering system to its Oklahoma gas compressor station before delivery to a gas transmission pipeline owned by others. Numerous other transmission pipelines are also nearby. Dorchester Hugoton has owned and operated the 5,400 horsepower gas compression and dehydration facility in Oklahoma since 1994. The purpose of such compressors is to increase the pressure of the gas from low levels (approximately 10 psig) to higher levels needed to enter the transmission pipelines (approximately 800 psig). The dehydration facility removes water vapor to meet transmission pipeline quality standards. Major maintenance was performed in 1998 and again in 2001. Electronic measurement equipment was installed on the Oklahoma gas

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gathering pipelines during 1996. Fuel consumption of natural gas at the compression and dehydration facilities is estimated to be approximately 4.6% of the compressor's inlet gas volume. Dorchester Hugoton has a continuing program of testing and reinstallation of anodes (corrosion protection devices) on the Oklahoma gas pipeline gathering system.

Wells in the Guymon-Hugoton field are drilled into a 150 feet thick geological formation commonly called the Chase Group. An average Dorchester Hugoton well will encounter the top of the Chase Group approximately 2,700 feet below the surface. This formation typically consists of non-productive shale rock layers that separate the productive zones commonly called Herington, Krider, Winfield and the deeper Fort Riley, which is sometimes referred to as Towanda. At the time of drilling Dorchester Hugoton's wells (primarily during the late 1940's), the Fort Riley zone was considered to contain salt water rather than natural gas and was not penetrated. Based on current information, the Fort Riley zone for the most part appears to be full of water.

Dorchester Hugoton believes that it is possible that some of Dorchester Hugoton's acreage contains gas productive Fort Riley zones without excessive water saturation. Dorchester Hugoton's existing wells, whose production holds the acreage leases regardless of depth, are mechanically not capable of being deepened. Consequently, to explore in the Fort Riley zone requires drilling a well and isolating the zone for testing. Considering the numerous unknown factors such as possible salt water and possible previous lateral gas migration in the Fort Riley, Dorchester Hugoton continues to follow a cautious approach in further drilling to this zone.

Thus far Dorchester Hugoton has drilled and completed three wells to test the Fort Riley zone. Each of the three wells replaced an existing gas well that was plugged and abandoned as required by Oklahoma regulations. The first of the three wells initially appeared to be favorable in both the Fort Riley zones and Winfield/Krider zones; however, subsequent testing indicated gas leaked upward through the shale rock layer separating the zones, causing Fort Riley evaluations to be inconclusive. The first of the three wells recently produced 377 Mcf per day at 41 psig, which is an improvement over the plugged well's previous 105 Mcf per day at 24 psig. The second of the three Fort Riley test wells was not as successful, producing 78 Mcf per day while pumping 30 bbls of water per day. The second well replaced a Winfield/Krider well that produced 175 Mcf per day with no water. In December 1998, the second Fort Riley well was plugged and recompleted in the Winfield/Krider zone, and in September 2001, produced 142 Mcf per day at 17 psig. During October 2001, Dorchester Hugoton reopened the previously plugged Fort Riley zone in the second well. At present, this second well is producing 202 Mcf per day at 16 psig and 38 bbls of water per day from the commingled Winfield/Krider/Fort Riley zones. The third Fort Riley test recently produced 46 Mcf per day at 15 psig while pumping 3.6 bbls of water per day. The third Fort Riley test replaced a Winfield/Krider well that produced 85 Mcf per day at 20 psig.

Dorchester Hugoton's ownership also includes the Council Grove formation, which is unrelated to the Chase Group and underlies most of its Oklahoma acreage. Dorchester Hugoton has not drilled any wells in the Council Grove formation, but it is monitoring the activity of others on nearby acreage in the formation. At present, other parties have drilled 15 wells on nearby acreage. Two of the 15 wells were recompleted in the Guymon Hugoton field and improved production over the original Guymon Hugoton wells that were plugged and abandoned per state regulations. It is not known if such monitoring will result in any plans by Dorchester Hugoton to attempt a Council Grove well; previous preliminary reviews yielded unfavorable forecasts. Recent results by others in the 13 remaining wells have varied from 3 to 354 Mcf per day. Production volumes in subsequent months have varied with most wells showing decreases. Current total production from the three Council Grove wells owned by others but located on Dorchester Hugoton's acreage is approximately 6, 8 and 20 Mcf per day. Dorchester Hugoton has a minor overriding royalty interest in the three wells.

The routine workover of wells in Oklahoma includes fracture treating, or the creation of cracks in the formation to assist gas flow toward the well bore from the producing zones. Currently, Dorchester Hugoton has fracture treated 37 wells in Oklahoma which includes 13 wells during 2000 and seven wells during 2001. Of the 20 wells, 16 increased in gas production volume and 20 increased in gas pressure. The combination of an

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increase in pressure and volume resulted in an overall increase of 48% in gas reserves for the 37 wells. The results of fracture treating can vary widely from well to well and may not be successful. Dorchester Hugoton anticipates continuing additional fracture treating in Oklahoma.

Kansas

Dorchester Hugoton currently operates and owns 100% of the working interest in 20 natural gas wells producing from the Kansas Hugoton field which consists of the Chase Group similar to Oklahoma. Dorchester Hugoton does not own the Council Grove formation underlying its acreage in Kansas. The natural gas from these operated wells is currently delivered through a 26 mile gas gathering pipeline and compression and dehydration facility owned by Dorchester Hugoton and is then sold into a pipeline owned by others at an average of field market prices. Dorchester Hugoton's gas gathering pipelines also include seven rental gas compressor units in the Kansas Hugoton field which are scattered over a 10 mile area. Electronic measurement equipment was installed on the Kansas gathering system during 2000. Fuel consumption of natural gas at the Kansas compression and dehydration facilities including field rental compression is estimated to be approximately 9.6%. Dorchester Hugoton also has minor overriding royalty interests in various producing natural gas wells in Kansas.

Dorchester Hugoton's operations in Kansas have been generally limited to routine maintenance of wells and support facilities. Fracture treatment attempts during the 1990's in Kansas have not been successful, and no additional attempts are presently contemplated.

Acreage

The following table sets forth the developed and undeveloped acreage as of December 31, 2001 owned by Dorchester Hugoton. Acreage in which an interest is limited to royalty, overriding royalty and other similar interests is excluded. Council Grove acreage underlies the Oklahoma developed acreage.

                         Undeveloped
           Developed   (Council Grove)
         ------------- ---------------
Location Gross   Net    Gross    Net
-------- ------ ------ ------  ------
Oklahoma 79,861 74,031 47,360  46,960
Kansas..  7,035  7,035     --      --
         ------ ------ ------  ------
Total... 86,896 81,066 47,360  46,960
         ====== ====== ======  ======

Costs Incurred and Drilling Results

The following table sets forth information regarding the costs incurred by Dorchester Hugoton in acquisition and development activities during the periods indicated in connection with its properties.

                  Years Ended December 31,
                  ------------------------
                    2001      2000   1999
                   ------    ----   ----
                       (in thousands)
Acquisition costs $5,297*    $ 23   $ 16
Development costs    240      301    332
                   ------     ----   ----
Total............ $5,537     $324   $348
                   ======     ====   ====


/* Includes $5,270,000 paid for an Oklahoma production payment. See "Information Concerning Dorchester Hugoton--Management's Discussion and Analysis of Financial Condition and Results of Operation." /

Dorchester Hugoton has not acquired or drilled or participated in the drilling of wells during the three years ended December 31, 2001 as a working interest owner. During December 1999 Dorchester Hugoton acquired a

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1.6% royalty interest in one well operated by Dorchester Hugoton and in one non-Hugoton well operated by others. During December 2000, Dorchester Hugoton acquired a 4.5% royalty interest in another Oklahoma well operated by Dorchester Hugoton. During 2001, Dorchester Hugoton acquired royalty interests ranging from .02% to 1.2% in eight Oklahoma wells operated by Dorchester Hugoton.

Productive Well Summary

The following table sets forth the ownership of Dorchester Hugoton in productive wells at December 31, 2001.

         Productive Wells
         ----------------
Location Gross      Net
-------- -----     -----
Oklahoma  127     115.2
Kansas..   20      20.0
          ---      -----
Total...  147     135.2
          ===      =====

Natural Gas Reserves

Proved natural gas reserves are estimated quantities which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Dorchester Hugoton retained Calhoun, Blair & Associates, Inc., an independent petroleum engineering consulting firm, to provide annual estimates as of December 31 of each year of Dorchester Hugoton's future net recoverable natural gas reserves. Dorchester Hugoton has no known reserves of crude oil. There have been no events that have occurred since December 31, 2001 that would have a material effect on the estimated proved developed natural gas reserves.

The following table summarizes the estimates of Dorchester Hugoton's historical net proved developed producing natural gas reserves as of December 31, 2001, 2000 and 1999, and the future net cash flow present values discounted at 10% per year attributable to these reserves at such dates prepared by Dorchester Hugoton's independent petroleum consultants, Calhoun, Blair & Associates, Inc.

                                                   Natural Gas (MMCF)
                                                -----------------------
                                                 2001    2000     1999
                                                ------  -------  ------
Estimated quantity, beginning of year.......... 54,127   58,209  64,147
Revisions in previous estimates................    743    3,012   1,478
Production..................................... (6,568)  (7,094) (7,416)
Estimated quantity, end of year................ 48,302   54,127  58,209
                                                ------  -------  ------
SEC PV-10 present value ($, in thousands)(1)(2) 44,726  140,003  44,382
                                                ======  =======  ======


(1) Dorchester Hugoton does not reflect a federal income tax provision since its partners include the income of their partnership in their respective federal income tax returns.
(2) The SEC PV-10 present value of future net cash flow is based on year-end natural gas sales prices. Because December 31, 2000 prices were significantly higher than other year-end prices, 2000 results appear higher.

Other Properties

Dorchester Hugoton leases its principal offices in Garland, Texas under a lease expiring in 2007. Dorchester Hugoton also owns a field office in Hooker, Oklahoma and leases part of an office in Amarillo, Texas under a month-to-month lease. Dorchester Hugoton owns 160 surface acres in Oklahoma and 160 surface acres in Kansas on which it maintains compressor stations and dehydration facilities.

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Dorchester Hugoton owns a fleet of 11 vehicles which are used in its operations.

Dorchester Hugoton also owns 128,000 shares of common stock of Exxon Mobil Corporation.

Selected Financial and Operating Data

The following table sets forth a summary of selected financial and operating data for Dorchester Hugoton for the periods indicated. It should be read in conjunction with the financial statements and related notes included elsewhere in this document. All of the information presented has been derived from the audited financial statements of Dorchester Hugoton.

                                                           Years ended December 31,
                                          ----------------------------------------------------------
                                             2001        2000        1999        1998        1997
                                            -------     -------     -------     -------    -------
                                          (in thousands, except per unit and as otherwise indicated)
Total operating revenues................. $26,779     $25,182     $15,302     $15,366     $19,159
Net earnings............................. $18,351     $17,962     $ 9,046     $ 9,010     $12,665
Net earnings per unit.................... $  1.69     $  1.66     $  0.83     $  0.83     $  1.17
Cash distributions....................... $13,349     $ 9,768     $ 7,814     $ 7,814     $ 7,814
Net cash provided by operating activities $21,029     $18,526     $11,045     $10,501     $15,482
Total assets at book value............... $41,454     $38,709     $28,165     $26,444     $25,215
Cash/cash equivalents.................... $18,439     $15,767     $ 7,017     $ 4,167     $ 3,344
Increase in cash/cash equivalents........ $ 2,672     $ 8,750     $ 2,850     $   823     $ 3,229
Long-term debt, including current portion $    --     $   100     $   100     $   100     $   122
Total liabilities........................ $ 4,118     $ 5,779     $ 3,827     $ 3,803     $ 4,374
Partners' equity......................... $37,336     $32,930     $24,338     $22,641     $20,841

Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion is intended to assist in understanding Dorchester Hugoton's financial position and results of operations for the three years ended December 31, 2001. 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.

Overview

Dorchester Hugoton's business operations consist of producing, gathering and selling natural gas from the long-established Hugoton gas field in Oklahoma and Kansas. Dorchester Hugoton distributes a large proportion of its net cash flow each year. It has not engaged in exploration activities and has not engaged in development activities except to a very limited extent with respect to replacement or improvement of its existing wells. Its cash flow from operations has historically been sufficient to fund its cash and capital expenditure requirements, and, while it maintains a revolving credit arrangement with a bank, borrowings since January 1, 1998 have been minimal.

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Dorchester Hugoton's year to year changes in net earnings and cash flows from operating activities are 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) and weighted average sales prices were:

                                       Years ended December 31,
                                       ------------------------
                                         2001    2000    1999
                                        ------  ------  ------
Sales Volumes (MMcf):
   Oklahoma...........................  5,141    5,576   5,580
   Kansas.............................    974    1,082   1,320
                                        ------  ------  ------
   Total..............................  6,115    6,658   6,900
                                        ======  ======  ======
Weighted Average Sales Prices ($/Mcf):
   Oklahoma........................... $ 4.42   $ 3.95  $ 2.28
   Kansas............................. $ 4.55   $ 3.99  $ 2.36
Overall Weighted Average Sales Price.. $ 4.44   $ 3.96  $ 2.30

It is expected that net operating revenues for 2002 and future years will be benefited by Dorchester Hugoton's acquisition in 2001 of a production payment, which had reduced its 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 periods ending March 1, 1999, 2000, and 2001, the production payment to others has been approximately $646,000, $730,000, and $1,701,000, respectively. See "Information Concerning Dorchester Hugoton--Management's Discussion and Analyzing Financial Condition and Results of Operations--Liquidity and Capital Resources" below.

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

As shown in the table above, Oklahoma 2001 gas sales volumes were 7.8% 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.

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 percentage decline from 2000 was smaller compared to prior years' declines, which was approximately 20%. The use of field compression, which increased volume initially, helped lessen the decline on an annual basis. Existing Kansas compressors were adequate to create a vacuum at the well, although no significant increase in current gas production has occurred.

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, 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.

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 announced agreement to combine with Republic and Spinnaker.

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

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Year Ended December 31, 2000 Compared with the Year Ended December 31, 1999

As shown in the table above, Oklahoma 2000 gas sales volumes were essentially unchanged from 1999 which was largely due to volume increases resulting from fracture treating offsetting natural declines.

Kansas 2000 sales volumes were 18% lower than 1999 which was a result of declining volumes and pressures typical of other producers in that area.

2000 weighted average natural gas prices were significantly higher than 1999 because of significantly higher marketplace prices, particularly in the last half of 2000.

Excluding cost items directly influenced by the market price of natural gas, such as production taxes, overall costs increased less than 2% of net earnings from 1999 to 2000. Noteworthy changes include an increase of $150,000 in tax and regulatory costs resulting from Y2K changes in Schedule K-1 preparation and electronic filing, and decreased "other income" primarily as a result of approximately $340,000 in costs associated with the proposed combination with Republic and Spinnaker.

Net earnings increased substantially from 1999 to 2000 primarily as a result of significant increases in natural gas market prices.

Liquidity and Capital Resources

On July 19, 1994, Dorchester Hugoton entered into a $15,000,000 unsecured revolving credit facility with Bank One, Texas, NA, which will expire July 31, 2002. The current borrowing base is $6,000,000, which will be re-evaluated by the bank at least annually. If, on any evaluation date, the aggregate amount of outstanding loans and letters of credit exceed the current borrowing base, Dorchester Hugoton is required to repay the excess. This credit facility includes both cash advances and any letters of credit that Dorchester Hugoton may need, with interest being charged at the bank's base rate, which was 4.75% on December 31, 2001. All amounts borrowed under this facility become due and payable on July 31, 2002. As of December 31, 2001, no letters of credit were issued under the credit facility and the amount borrowed was $100,000. Dorchester Hugoton is required to maintain certain minimum defined financial ratios with respect to its current ratio and the ratio of net cash flow to debt service. In addition, Dorchester Hugoton's capital must be maintained above specified amounts. Dorchester Hugoton's general partners have guaranteed this note. Since July 1994 the maximum amount borrowed under this credit facility has been $5,800,000. During 1999, 2000 and 2001 the amount borrowed under this credit facility was $100,000 (the minimum borrowing necessary to maintain the credit facility). Dorchester Hugoton does not believe that changes in interest rates will have a material adverse effect on its financial condition or operating results. Pursuant to the Combination Agreement, prior to closing Dorchester Hugoton will repay its borrowings.

Cash flows from operating activities remain sufficient to meet Dorchester Hugoton's anticipated costs and expenses and debt service requirements. Dorchester Hugoton has no current outstanding material commitments for capital expenditures. Year end cash and cash equivalents totaled $7,017,000 for 1999, $15,767,000 for 2000 and $18,439,000 for 2001.

Dorchester Hugoton does not currently anticipate drilling additional wells as a working interest owner in the Fort Riley zone, the Council Grove formation or elsewhere, but successful activities by others in these formations could prompt a reevaluation by Dorchester Hugoton. Any such drilling is estimated to require $250,000 to $300,000 per well. Dorchester Hugoton anticipates continuing additional fracture treating but is unable to predict the cost until additional engineering studies are done.

Dorchester Hugoton 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 Hugoton does not

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anticipate significant replacement of these items at this time. However, Dorchester Hugoton believes rental field compression units installed at various locations on its Oklahoma gas gathering pipelines may become necessary in 2003 because of lower pressures. The cost of such additional compression could require from $400,000 to $600,000 in capital and require $350,000 to $400,000 per year additional operating costs (primarily compressor rental). While it is believed that the benefits of such compression will more than exceed cost and recover capital, neither the timing of such a project nor the increased gas production are currently predictable.

In 1998, Oklahoma 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 has been installed that affects Dorchester Hugoton's wells during 2001 by operators on adjoining acreage resulting from the relaxed production rules. Such installations by others could require expenditures by Dorchester Hugoton to stay competitive with adjoining operators.

Since its first annual payment in 1997, each May Dorchester Hugoton has paid an Oklahoma production payment (calculated through the prior February) that is based upon the difference between market gas prices compared to a table of rising prices and based upon a table of declining volumes. In May 2001 Dorchester Hugoton paid approximately $1,701,000 in production payments for the year ended February 28, 2001. In August 2001, Dorchester Hugoton paid $5,270,000 to acquire, effective March 1, 2001, the Oklahoma production payment and will not be required to make such production payments to others in the future.

Critical Accounting Policies

Dorchester Hugoton 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.

Dorchester Hugoton's discounted present value of its 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. Dorchester Hugoton's 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 writedown. In addition to the impact on calculation of the ceiling test, estimates of proved reserves are also a major component of the calculation of depletion.

While the quantities of proved reserves require substantial judgment, the associated prices of natural gas reserves that are included in the discounted present value of the 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 Dorchester Hugoton's or the industry's forecast of future prices.

Changes in and Disagreements with Accountants

Dorchester Hugoton has not, during its two most recent fiscal years, experienced any changes in accountants or disagreements with Grant Thornton LLP, the independent accountants engaged as the principal accountants to audit Dorchester Hugoton's financial statements.

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Regulation

The transportation of natural gas after sale by Dorchester Hugoton is subject to regulation by federal authorities, specifically by the FERC. Various state agencies and authorities regulate the production of natural gas. Dorchester Hugoton's operations are also affected by various statutory controls or obligations and, in varying degrees, by political developments and federal and state laws and regulations. Natural gas production is affected by changing federal and state tax and other laws which are specifically applicable to the oil and natural gas industry, by constantly changing federal and state administrative regulations as well as possible interruption or termination by government authorities due to ecological and other considerations. Allowable gas production rates have been, and are, to varying degrees, subject to conservation and environmental laws and regulations.

Both Kansas and Oklahoma regulate the amount of natural gas that can be produced by assigning to each well or proration unit a monthly allowable rate of production. Kansas and Oklahoma also specifically regulate the drilling of new or replacement oil and natural gas wells, the spacing of wells, the prevention of waste of natural gas resources, environmental protection and various other matters.

During 1986, the Kansas Corporation Commission issued an order authorizing infill drilling on 320 acre spacing. Previously, each gas well required 640 acres. Dorchester Hugoton drilled and completed on its operated properties eight producing wells through 1990 and one each in 1995, 1996 and 1997. One infill well was plugged in 1992 and another in 1993 for economic reasons.

At present, the Oklahoma Guymon-Hugoton field is restricted by state conservation regulations to a maximum of one well for each 640 acres, subject to minor variances. Including Dorchester Hugoton's 127 wells, there are about 1,350 currently producing gas wells in the Guymon-Hugoton field owned by both independent producers and major oil and natural gas companies. Previously, a few producers and numerous other interested parties in the area were actively seeking either regulatory or legislative changes to enable "increased density drilling" similar to Kansas infill drilling on 320 acre spacing. At present, several producers in the field have actively opposed such infill drilling. The difference in beliefs appears to rest in whether such infill drilling results in increased reserves. In 1989 the Oklahoma Corporation Commission concluded hearings on infill drilling and determined the present density of one well per 640 acres was adequate to drain the 640 acres. Numerous studies of the Kansas infill drilling results concluded that infill drilling developed no new reserves. This conclusion is consistent with Dorchester Hugoton's experience in Kansas.

A change in the Guymon-Hugoton field rules allowing infill drilling could result in a large number of wells being drilled that are not needed to produce the same gas that is being produced by the existing wells. Dorchester Hugoton believes it is not usually economically justifiable to drill a second well on 640 acres in Oklahoma just to produce the same gas as the original well, only faster. The outcome and cost of infill drilling is unpredictable. In late February 1997, Oklahoma did not pass legislation that would have allowed "infill drilling." Similar proposed legislation may arise in the future. On June 21, 1999 Oklahoma enacted legislation that clarifies who must receive notices of any application for Guymon-Hugoton infill drilling. Currently no such applications have been filed and such filings are expected to be controversial and require lengthy regulatory proceedings.

On February 4, 1998 the Oklahoma Corporation Commission adopted rules that essentially removed production volume limits from nearly all wells in the Guymon-Hugoton field effective July 1, 1998 and specifically provided that the rule changes have no bearing on the question of infill drilling which must be decided separately. Thus far only one company on adjoining acreage has installed gas compression to try to benefit from Oklahoma's removal of production limits. Dorchester Hugoton elected to install similar rental compression to stay competitive. Since 2000, seven of Dorchester Hugoton's wells have been assisted by such field compressors compared to five during 1999. The increase in production has more than offset costs of compression. Further activities by others resulting from the field rule changes and related costs or benefits to Dorchester Hugoton are unpredictable.

During 2000, Kansas adopted new regulatory rules, agreed upon by most producers, to enable the use of field compressors to operate Hugoton field wells at a vacuum and provide that no well will be restricted to less

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than 100 Mcf per day. Possible effects of state allowed production in excess of 100 Mcf per day are not predictable. Dorchester Hugoton has received approval to operate all its wells at a vacuum.

The FERC allows regulated transmission pipelines to transfer or sell portions of their system classified or reclassified by the FERC as gas gathering pipelines to non-regulated entities or affiliates. Most of Dorchester Hugoton's Oklahoma gas was not affected by any such sale or transfer, and the effect on Dorchester Hugoton in Kansas has been minimal since only one of the two transmission pipelines to which Dorchester Hugoton delivered gas became a non-regulated gathering pipeline in 1996. Since then, Dorchester Hugoton's gas from the 20 Kansas wells has been delivered directly to a transmission pipeline or sold to Duke Energy Field Services, Inc., at the outlet of Dorchester Hugoton's compression and dehydration facility. Both Kansas and Oklahoma have adopted state regulation of gas gathering pipeline systems available for hire, which excludes Dorchester Hugoton's facilities. Additionally, current court decisions in both Kansas and Oklahoma sharply restrict the practice of requiring royalty owners to bear their share of gas gathering and compression costs. Dorchester Hugoton has never charged royalty owners for such costs.

Customers and Pricing

The pricing of all Dorchester Hugoton's gas sales, both in Kansas and Oklahoma, is primarily determined by supply and demand in the marketplace. This price can fluctuate considerably. During 2001 the highest monthly average price was $10.02/MMBTU in January and the lowest monthly average was $1.85/MMBTU in October. Dorchester Hugoton anticipates continued fluctuations in marketplace pricing.

Effective May 1, 2002, all of Dorchester Hugoton's Kansas gas was committed for sale to Anadarko Energy Services Company for a period of one year and year to year thereafter. Anadarko pays Dorchester Hugoton based on an average of the market price in the field. Pursuant to notice given November 1, 2001, the previous gas sales agreement with Duke Energy Field Services, Inc. expired May 1, 2002. Dorchester Hugoton believes the impact of the change in gas purchasers will be immaterial to its income and cash flow.

Effective July 1, 2000, most of Dorchester Hugoton's Oklahoma gas was committed for sale to Williams Energy Marketing and Trading Company for a one-year period at a premium over the market price index. Since July 1, 2001, such sales have been on a month-to-month basis at varying market price indexes. During 1996, Dorchester Hugoton's Oklahoma gas began a five-year commitment to Williams Field Services Company for delivery to the ultimate purchaser or purchasers through a processing facility, which also removes the contaminant nitrogen. During 2001, the commitment was extended another five years. Effective February 28, 2002 Williams Field Services Company sold the processing facility to Duke Energy Field Services, L.P., which has shifted the processing to its facility near Liberal, Kansas. Minimal impact is expected. The quantity sold to Williams Energy Marketing is determined by nominations at the processing facility outlet. Imbalances with actual deliveries to Duke Energy Field Services, L.P., formerly Williams Field Services Company are corrected in each subsequent month. At December 31, 2001, the imbalance was approximately 3,000 MMBTU owed Dorchester Hugoton compared to 7,000 MMBTU owed Dorchester Hugoton at December 31, 2000.

On May 1, 2000 Dorchester Hugoton extended year to year a previously four-year gas sales agreement with WFS Gas Resources Company (part of Williams Companies, Inc.) providing for gathering, compression, and sale of gas at market prices. This agreement covers only three wells in which Dorchester Hugoton has minimal interest that are not connected to Dorchester Hugoton's Oklahoma gas gathering pipeline and compression facilities. This sales agreement replaced the previously regulated gathering and compression services provided by Williams Natural Gas Company.

Dorchester Hugoton believes that the loss of any single customer would not have a material adverse effect on the results of its operations because the transmission and other pipelines connected to Dorchester Hugoton's facilities are required by the FERC or state regulations to provide continued equal access for shipment of natural gas. Additionally, there are numerous gas purchasers available on each pipeline.

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Competition

The energy industry in which Dorchester Hugoton competes is subject to intense competition among a large number of companies, both larger and smaller than Dorchester Hugoton, many of which have financial and other resources greater than Dorchester Hugoton.

Environmental Laws and Regulations

The costs associated with Dorchester Hugoton's compliance with environmental laws and regulations have not had, and are not anticipated to have, a material effect on its capital expenditures, earnings or competitive position. Dorchester Hugoton's gas production contains minimal contaminants other than nitrogen, which is inert and non-toxic. Dorchester Hugoton's quarterly air emission tests at its Oklahoma compression facility continue to comply with the Oklahoma Department of Environmental Quality's air quality regulations. The Kansas Department of Health and Environment has issued Dorchester Hugoton an air emissions operating permit for its Kansas compression facility. At present, no permits are necessary for the seven rental field compressors installed in Kansas during 1997 or the two rental field compressors installed in Oklahoma during 1999.

Tax Returns

Dorchester Hugoton's expenditures for regulatory reporting, primarily consisting of Schedule K-1 tax statement preparation and federal electronic filing fees were approximately $170,000 in 1999 and $320,000 in 2000 and 2001, as reflected in general and administrative costs. Dorchester Hugoton recently secured a two-year agreement for Schedule K-1 tax statement preparation and electronic filing for its 4,000 to 5,000 depositary receipt holders at a level slightly higher than 2001. This agreement will not apply to us in the event Dorchester Hugoton combines with Republic and Spinnaker pursuant to the Combination Agreement.

Legal Proceedings

Through 1998 Dorchester Hugoton recorded $450,000 (which included related interest) towards a request from Panhandle Eastern Pipe Line Company, referred to as PEPL, for refund of Kansas tax reimbursements received by Dorchester Hugoton during the years 1983 to 1987. These charges resulted from a ruling by the United States Court of Appeals for the District of Columbia, which overruled a previous order by the FERC. During March 1998, $151,757 was paid to PEPL and an additional $366,633 was placed into an escrow account. During March 1999, $2,840 was released from escrow to PEPL. During June 2001, Dorchester Hugoton, along with numerous other natural gas producers, agreed with PEPL to settle all issues. The FERC approved the settlement during October 2001. Dorchester Hugoton adjusted its accrued liability from approximately $419,000 to approximately $320,000 during the third quarter of 2001. Pursuant to the settlement, during October 2001, Dorchester Hugoton returned all funds collected from royalty owners, which were approximately $35,000, who had paid their refund obligation to Dorchester Hugoton. Also, in connection with the Settlement, on November 20, 2001 Dorchester Hugoton paid from the escrow account approximately $285,000 to PEPL and approximately $135,000 to itself, subsequently closing the escrow account.

In January 2002, 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. RRNGR consists primarily of Texas County, Oklahoma residents who use natural gas at their own risk free of cost from gas wells in residences located on leases. 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 1930's to the 1950's. 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. Dorchester Hugoton believes plaintiffs' claims are completely without merit as to Dorchester Hugoton and has filed an answer,

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including a motion for summary judgment against plaintiff. Further, based upon past measurements of such gas usage and current natural gas prices, Dorchester Hugoton believes the damages sought by plaintiffs to be minimal.

Security Ownership

Depositary Receipts

Immediately subsequent to its formation, all of Dorchester Hugoton's units of limited partnership interest were deposited with an authorized depositary, to be held in accordance with a depositary agreement. Effective September 8, 1998, the depositary became BankBoston, N.A., which is now EquiServe Trust Company, N.A., P.O. Box 43010, Providence, RI, 02940-3010. The depositary maintains an account with respect to the units deposited for which it has issued depositary receipts. Holders of depositary receipts, also referred to as unitholders, may transfer, combine or subdivide them at any office of the depositary designated for such purpose. Unitholders may also surrender them to the depositary and, upon submission of such documents as Dorchester Hugoton's general partners may require, reclaim deposited units. However, the units will not be readily transferable and any redeposit of units against newly issued depositary receipts will require 60 days' advance written notice and is subject to certain other conditions.

The units and the depositary receipts are fully paid and non-assessable. Each record holder of a depositary receipt evidencing the ownership of one or more units will, for purposes of the Texas Revised Limited Partnership Act, be an assignee with respect to the interests in Dorchester Hugoton represented by such units. Each such assignee may become a substituted limited partner upon
(i) the execution and delivery of a request and agreement to become a substituted limited partner, which includes a power of attorney to the general partners, (ii) the approval of the general partners to such admission as a substituted limited partner, and (iii) the filing of an amended Certificate of Limited Partnership evidencing the admission of such person as a substituted limited partner. If such action is not taken, unitholders will remain assignees of the interests of Dorchester Hugoton represented by the units. Under certain circumstances, a unitholder may not become a substituted limited partner if such holder is not an eligible citizen.

Hugoton Nominee, Inc., a Texas nominee corporation referred to as Nominee, was formed in August 1982 on behalf of Dorchester Hugoton and has agreed to act as limited partner of record for those unitholders of record who do not become substituted limited partners. Dorchester Hugoton is required to reimburse Nominee for all expenses incurred in its capacity and shall indemnify Nominee against certain liabilities. Nominee may at any time resign or be removed by Dorchester Hugoton and a successor appointed.

The agreement with the current depositary, Equiserve Trust Company, N.A. became effective September 1, 2001 and will continue for three years and year to year thereafter. The agreement is fully assignable.

Cash Distributions

Each unitholder (whether an assignee or limited partner) as of the last day of each month is allocated a pro rata share of Dorchester Hugoton's profits and losses for the month then ended, regardless of whether such holder receives any cash distributions from Dorchester Hugoton. Each unitholder of record (whether an assignee or limited partner) as of the applicable record date is entitled to receive an allocable share of any cash distributions made by Dorchester Hugoton. The timing and amount of such distributions is determined by the general partners. In addition, Dorchester Hugoton's credit agreement with Bank One, Texas, NA requires that Dorchester Hugoton's capital remain above certain specified amounts.

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Market Prices of Dorchester Hugoton Depositary Receipts

The depositary receipts have been traded on the Nasdaq Stock Market under the symbol "DHULZ" since August 26, 1982. The quoted market prices and reported trading volumes for 2001, 2000 and 1999 were as follows:

                     2001                       2000                     1999
           ------------------------- -------------------------- ----------------------
            Low     High    Volume     Low     High    Volume     Low    High  Volume
           ------ -------- --------- ------- -------- --------- ------- ------ -------
First Qtr. $12.25 $ 15.875 1,005,000 $ 8.875 $10.0625   687,000 $ 9.375 $10.50 867,000
Second Qtr  11.25  14.5555 1,183,000  9.9375   14.125 1,055,000    9.00  11.50 388,000
Third Qtr.  12.50    14.80   610,000  13.375   15.625   966,000  10.125  13.25 481,000
Fourth Qtr  10.23  14.8571   409,000   13.00    16.25 1,251,000    9.00  13.25 476,000

As of January 1, 2002, there were approximately 4,900 Unitholders.

Principal Holders

The following table sets forth certain information regarding the beneficial ownership of units by the general partners of Dorchester Hugoton, their officers, and Dorchester Hugoton's officer effective as of January 1, 2002 and other persons, excluding depositaries, of record on January 1, 2002 who held 5% or more of the units.

                                                                          Number of Units
                                                                         Beneficially Owned Percent of Class(1)(3)
                                                                         ------------------ ----------------------
P.A. Peak, Inc., general partner........................................            --                 --
Preston A. Peak, President of P.A. Peak, Inc............................     1,577,412(2)           14.68%
James E. Raley, Inc., general partner...................................            --                 --
James E. Raley, President of James E. Raley, Inc........................        14,706              00.14%
All general partners and their executive officers as a Group (4 persons)     1,592,118              14.82%


(1) Based on 10,744,380 units.
(2) Includes 1,576,412 units owned by various entities for the benefit of Mr. Peak and his family, and 1,000 units owned by Hugoton Nominee, Inc., of which he is the President and sole director.
(3) The units owned by the Advisory Committee members and the non-general partner officer of Dorchester Hugoton are less than 1% of the total units outstanding at January 1, 2002.

Other Information

Dorchester Hugoton, Ltd. has its principal place of business at 1919 S. Shiloh Road, Suite 600-LB 48, Garland, Texas 75042, telephone (972) 864-8610. Dorchester Hugoton employed 14 full time permanent employees (not including its general partners) as of January 1, 2002.

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INFORMATION CONCERNING REPUBLIC

General

Republic was formed in 1993 as a Texas general partnership to acquire oil and natural gas properties from multiple sellers. Prior to the combination, Republic will reorganize and be converted into a Texas limited partnership. See "The Combination--Preparatory Steps--Reorganization of Republic" beginning at page 56 for a more complete discussion of the Republic reorganization. Except where otherwise indicated, the following discussion of Republic assumes that the Republic reorganization has not occurred. SAM Partners, Ltd. and Vaughn Petroleum, Ltd. are the general partners of Republic and own equal 50% partnership interests. SAM Partners, Ltd. manages and administers Republic's properties and business.

Republic's properties consist primarily of producing and non-producing mineral, royalty, overriding royalty and leasehold interests located in 392 counties and parishes in 23 states. See "--Description of the Republic Properties" below for a more detailed discussion of the Republic properties. Republic funded the acquisitions of its properties with the proceeds of the sale of overriding royalty interests which burden all of Republic's properties, referred to as the Republic ORRIs, in varying undivided portions to five institutional investors and one limited partnership, referred to as the Republic ORRI owners. The Republic ORRIs, a real property interest, are commonly referred to in the oil and natural gas industry as a net profits interest. Republic's primary business is the management and administration of its properties. Republic has not acquired any properties since its formation in 1993.

The terms of the transaction resulting in the sale of the Republic ORRIs are summarized below:

. The Republic ORRI owners paid 95.9% of Republic's actual cost to acquire the properties.

. The Republic ORRI owners are entitled to 95.9% of net proceeds (as defined below) attributable to the properties until Payout No. 1 (as described below) is achieved, 86.31% thereafter until Payout No. 2 (as described below) is achieved and 77.679% thereafter for the life of the properties.

. Net proceeds equal cash receipts, less cash disbursements attributable to Republic's properties. Net proceeds are adjusted for an overhead reimbursement amount equal to 4% of cash flow. Actual general and administrative costs are not included in the determination of net proceeds.

. Payout No. 1 occurs when the Republic ORRI owners have recovered 100% of their initial investment from Republic ORRIs payments; Payout No. 2 occurs when the Republic ORRI owners have received a 14% internal rate of return on their initial investment.

. Payout No. 1 was achieved in August 2000.

Republic receives payment for oil and natural gas production revenue, lease bonus and all other sources of income and pays all expenses, including severance, property and ad valorem taxes. Republic determines the payment under the Republic ORRIs and pays that amount to the Republic ORRI owners monthly. Distributions to the general partners reflect actual cash receipts less actual cash disbursements, including the payments to the Republic ORRI owners and actual general and administrative expenses. The general partners bear their respective share of actual general and administrative expenses to the extent these expenses exceed the overhead reimbursement.

There is no established public trading market for Republic's partnership interests. As a result of the Republic reorganization, two general partners and a total of 11 limited partners will hold Republic's partnership interests. The general partners are not aware of any purchases or sales of partnership interests or the Republic ORRIs since formation, except for isolated transactions not involving brokers or other market participants. Three of the five Republic ORRI owners that are institutional investors have conveyed all or a portion of their Republic ORRIs to successor entities in corporate transactions. The result is that seven institutional investors, referred to as the Unaffiliated ORRI Owners, and one limited partnership, referred to as the Affiliated Partnership, now own the

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Republic ORRIs. In accordance with generally accepted accounting principles, financial statements are presented separately for Republic and the Affiliated Partnership, and for the Unaffiliated ORRI Owners.

All capital raised by Republic has been invested as planned. As a result of these investments, Republic has achieved its investment objective of purchasing and owning oil and natural gas properties.

Description of the Republic Properties

Republic owns producing and nonproducing mineral, royalty, overriding royalty and leasehold interests. See "Glossary of Certain Oil and Natural Gas Terms" for descriptions of these terms.

Acquisition History

Republic acquired all of its interests from SASI Minerals Company, referred to as SASI, Vaughn Petroleum, Inc., referred to as VPI, and Vaughn Petroleum 1989 Joint Venture, referred to as Vaughn JV, in one transaction in September 1993. We refer to the interests acquired from SASI as the SASI properties, while the interests acquired from VPI are referred to as the VPI properties and the interests acquired from Vaughn JV are referred to as the Vaughn JV properties.

The SASI properties consisted of substantially all, but not all, of SASI's producing and nonproducing mineral, royalty, overriding royalty, leasehold and surface fee interests located in 352 counties and parishes in 22 states. SASI acquired these interests in 15 transactions from 1987 through 1992 from multiple sellers and include properties formerly owned by Newmont Oil Company, Felmont Oil Corporation, Case Pomeroy Oil Corporation, Essex Royalty Corporation, Montoya Oil Corporation, Alder Oil Company, Mayfair Minerals and others. SASI acquired these properties and others pursuant to a Management and Consulting Agreement among SASI and Smith Allen Oil & Gas, Inc. pursuant to which Messrs. McManemin and Allen, as officers and directors of Smith Allen Oil & Gas, were individually responsible for their acquisition and subsequent administration. The SASI properties represented approximately 93% of Republic's oil and natural gas reserves upon its formation.

The VPI properties consisted of VPI's producing and nonproducing mineral, royalty, overriding royalty and leasehold interests located in 125 counties and parishes in 16 states. VPI acquired these properties in multiple transactions from 1930 through 1992 from multiple sellers. The VPI properties represented approximately 7% of Republic's oil and natural gas reserves upon its formation. The Vaughn JV properties consisted of leasehold interests in five exploratory drilling prospects located in the Smackover Trend of East Texas. Five wells were drilled on these properties; as of December 31, 2001 none of these wells were producing and all of the leases acquired from Vaughn JV have expired.

Acreage Summary

The following table sets forth a summary of Republic's gross and net (where applicable) acres of mineral, royalty, overriding royalty and/or leasehold interests, and a compilation of the number of counties and parishes and states and development status of the acres in each category as of January 1, 2002.

                                Mineral
                            ----------------         Overriding
                            Leased  Unleased Royalty  Royalty   Leasehold   Total
                            ------- -------- ------- ---------- --------- ---------
Number of States...........      17      23       14       11         6          23
Number of Counties/Parishes     165     300      130       51        31         392
Gross...................... 464,926 984,954  373,465   95,552    29,698   1,948,594
Net (where applicable).....  55,761 167,175      N/A      N/A       N/A     222,956

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Our net interest in production from royalty, overriding royalty and leasehold interests is based on burdens or reservations which vary from property to property. Consequently, net acreage ownership in these categories is not determinable.

Properties located in Texas represent 83% of Republic's total production revenues received during 2001, while properties located in Louisiana represented 7.5% and properties located in New Mexico represented 3%.

Republic owns 2,499 acres of surface fee interest located in Wood County, Texas commonly referred to as the SASI Ranch. Republic leases these lands for cattle grazing and owns approximately a 1/3 undivided mineral interest in these lands. Republic also owns small amounts of surface acreage in numerous states which are individually insignificant and not material in the aggregate.

The following table sets forth a summary of Republic's 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 as of January 1, 2002.

   State    Gross   Net      State       Gross     Net
----------- ------ ------ ------------ --------- -------
Alabama.... 73,675  4,220 Montana.....    16,506   2,388
Arkansas... 24,090  5,599 Nebraska....     1,120     239
Colorado...  9,231  1,015 New Mexico..    27,552   2,074
Florida.... 88,832 24,249 New York....     3,755   1,653
Georgia....  3,676  1,024 North Dakota   246,710  36,098
Illinois...  3,908    724 Oklahoma....    20,919   2,213
Indiana....    303    113 Pennsylvania     7,973   2,879
Kansas.....  5,114    924 South Dakota    12,257   1,222
Kentucky...  1,995    553 Texas....... 1,219,748 124,070
Louisiana.. 72,456  2,113 Utah........     1,280      40
Michigan... 55,367  2,623 Wyoming.....    11,814     821
Mississippi 41,317  6,105

Activity Summary

As a royalty owner Republic's access to information concerning activity and operations on its properties is significantly limited. Most of Republic's producing properties are subject to leases and other contracts pursuant to which it is not entitled to well information. Most leases consummated by Republic since its formation in 1993 provide for access to technical data and other information. Republic 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 Republic's properties at any point in time is not determinable. The primary manner by which Republic becomes aware of activity on its properties is the receipt of division orders or other correspondence from operators or purchasers.

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The following table sets forth a summary of leases consummated and new wells added by Republic during 1997 through 2001.

                                         Years Ended December 31,
                          ------------------------------------------------------
                            2001       2000        1999        1998       1997
                          --------  ----------  ----------  ----------  --------
Consummated Leases
   Number................       10          19          22          26        42
   Number of States......        3           6           5           5         7
   Number of Counties....        7          16          18          23        22
   Average Royalty.......     26.3%       24.3%       25.1%       24.8%     24.7%
   Average Bonus, $/acre. $    427  $      178  $      201  $      162  $    194
   Total Lease Bonus..... $140,171  $  275,327  $  742,678  $1,201,474  $583,965
Other Land Revenue....... $316,427  $2,212,988  $  468,237  $  407,710  $ 50,058
                          --------  ----------  ----------  ----------  --------
Total Land Revenue....... $456,598  $2,488,315  $1,211,915  $1,609,184  $634,023
                          ========  ==========  ==========  ==========  ========
New Wells Added
   Number................       77          80          79          87        57
   Number of States......        9           7           7           9         6
   Number of Counties....       39          32          34          33        30

Oil and Natural Gas Reserves

Huddleston & Co., Inc. has estimated Republic's proved reserves and SEC PV-10 present value attributable thereto as of December 31, 2001 and at year-end annually since 1993.

Huddleston has segregated Republic's properties into three Property Groups. The properties included in these Groups include only those properties evaluated by Huddleston and represent (to the best of Republic's knowledge) all of Republic's producing properties as of December 31, 2001, based on information available to Republic. Set forth below is a description of the properties in each Group.

The Group I properties are located in 20 counties in west Texas, New Mexico and Colorado and may be characterized as long lived oil and natural gas fields operated by major oil companies and large independents. Approximately 80% of Group I's total proved oil reserves and 18% of Group I's total proved natural gas reserves are attributable to Republic's interest in the Means, Robertson, Seminole and Wasson fields in Andrews, Gaines and Yoakum counties of west Texas, each of which fields were discovered in the 1930s. These fields are located in the Permian Basin and generally produce oil and associated gas from depths ranging from 4,500 to 7,500 feet. Enhanced recovery operations are underway in each property.

The Group II properties are located in six counties and parishes along the Gulf Coast of south Texas and south Louisiana and may be characterized as long lived natural gas and condensate fields operated by major oil companies and large independents. Approximately 92% of Group II's total proved oil reserves and 99% of Group II's total proved natural gas reserves are attributable to Republic's interest in the Bob West, Jeffress, McAllen Ranch and Port Hudson fields. These fields generally produce natural gas and condensate from depths ranging from 8,000 to 17,000 feet.

The Group III properties consist of the balance of Republic's producing properties and are located in 206 counties and parishes in 15 states. The Group III properties produce hydrocarbons from a variety of depths and types of reservoirs. Due to the limited nature of information available to Republic as a royalty owner, and the varying methodologies by which data concerning oil and natural gas operations is reported to the agencies having jurisdiction in the various states, the number of producing oil and natural gas wells included in Group III is not determinable. During 2001, Republic received payment from 454 purchasers for its share of production from 5,273 properties included in Group
III. Although Group III represents the largest property group, any specific

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property included in Group III may be characterized as individually insignificant in the context of Republic's total proved reserves.

The following table sets forth a summary of certain financial and reserve information for each Property Group for the period December 31, 1999 through December 31, 2001, and includes amounts attributable to the Republic ORRIs.

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                                                                                              Years Ended December 31,
                                       ----------------------------------------------------------------------------------------
                                                   Group I                          Group II                         Group III
                                       -------------------------------- -------------------------------- ----------------------
                                          2001       2000       1999       2001       2000       1999       2001       2000
                                       ---------- ---------- ---------- ---------- ---------- ---------- ---------- -----------
Proved Developed
   Net Oil (Bbls).....................  1,954,689  1,984,370  1,973,620    102,802    129,923    212,674  1,169,587   1,198,290
   Net Gas (Mcf)......................  4,873,500  4,450,200  3,984,100  3,760,000  4,460,100  6,623,700  9,945,700   8,636,200
Total Proved
   Net Oil (Bbls).....................  1,954,689  1,984,370  1,973,620    103,340    130,475    236,333  1,343,059   1,376,187
   Net Gas (Mcf)......................  4,873,500  4,450,200  3,984,100  3,926,000  4,632,200  8,681,300 11,354,800   9,883,500
Annual Production
   Net Oil (Bbls).....................    106,267    108,950    115,044     28,872     35,425     29,362    147,514     149,750
   Net Gas (Mcf)......................    340,694    375,740    324,884  1,139,503  2,192,767    931,184  1,237,010   1,172,949
Average Prices
   Oil ($/Bbl)........................     $26.31     $22.21     $15.83     $24.63     $27.72     $16.73     $24.79      $27.34
   Gas ($/Mcf)........................     $ 4.32     $ 3.23     $ 2.05     $ 4.67     $ 3.79     $ 2.43     $ 4.35      $ 3.18
Total Proved Future Net Revenue ($)(1)
   Undiscounted....................... 42,279,575 84,243,341 50,672,021 10,700,503 44,760,654 23,064,211 48,308,598 118,418,185
   SEC PV-10 present value (2)........ 17,053,996 34,815,799 20,161,643  6,850,744 29,413,496 15,050,342 26,185,887  64,831,827

                                           Total - All Property Groups
                                       -----------------------------------
                                          1999       2001        2000        1999
                                       ---------- ----------- ----------- -----------
Proved Developed
   Net Oil (Bbls).....................  1,373,700   3,227,078   3,312,583   3,559,994
   Net Gas (Mcf)......................  9,199,700  18,579,200  17,546,500  19,807,500
Total Proved
   Net Oil (Bbls).....................  1,577,635   3,401,088   3,491,032   3,787,588
   Net Gas (Mcf)...................... 10,492,500  20,154,300  18,965,900  23,157,900
Annual Production
   Net Oil (Bbls).....................    162,349     277,653     294,125     306,755
   Net Gas (Mcf)......................  1,140,420   2,717,207   3,741,456   2,396,488
Average Prices
   Oil ($/Bbl)........................     $15.52      $25.36      $25.49      $15.76
   Gas ($/Mcf)........................     $ 2.02      $ 4.49      $ 3.55      $ 2.19
Total Proved Future Net Revenue ($)(1)
   Undiscounted....................... 54,524,973 101,288,676 247,422,180 128,261,205
   SEC PV-10 present value (2)........ 29,772,220  50,090,627 129,061,122 64,984,2059


(1) Amounts shown in this table with respect to total proved future net revenue are based on year-end oil and natural gas prices and not on average prices for the entire year.
(2) Republic does not reflect a federal income tax provisions since its partners include the income of their partnership in their respective federal income tax returns.

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Contribution and Distribution Information

The following table sets forth information concerning capital contributions by and distributions to Republic's partnership interests and the Republic ORRIs. The capital contributions attributable to the Republic ORRIs reflect the actual cash consideration received by Republic upon the conveyance of the Republic ORRIs to the Republic ORRI owners. The capital contributions attributable to the general partners reflect the fair value of the properties contributed to Republic by its general partners, which amount was deemed to be $6,061,000 on the date of the contribution in accordance with generally accepted accounting principles.

                                              Cumulative Cash
                         Total Initial     Distributions through
                      Capital Contribution December 31, 2001(1)
                      -------------------- ---------------------
General Partners.....     $ 6,061,000           $ 8,822,572
Republic ORRIs Owners     $61,288,810           $82,255,803
                          -----------           -----------
   Totals............     $67,349,810           $91,078,375
                          ===========           ===========


(1) Because of depletion (which is usually higher in the early years of production), a portion of every distribution of revenues from properties represents a return of a limited partner's original investment. Until a limited partner receives cash distributions equal to his original investment, 100% of such distributions may be deemed to be a return of capital.

Selected Historical Combined Financial and Operating Information

The following table presents a summary of selected unaudited combined financial information and operating data for Republic for the periods indicated, and assumes that the Republic reorganization has occurred. The combined financial information reflects the combined operating results and financial condition of Republic and the Republic ORRIs. Intercompany amounts have been eliminated. It should be read in conjunction with the Republic and Republic ORRI audited financial statements and related notes included in this document.

                                                     Years ended December 31,
                                             ----------------------------------------
                                              2001    2000    1999    1998     1997
                                             ------- ------- ------- -------  -------
                                                          (in thousands)
Total operating revenues.................... $18,256 $25,134 $12,632 $ 8,962  $11,738
Net earnings................................ $11,905 $18,268 $ 7,175 $ 3,659  $ 5,915
Cash distributions (1)...................... $18,588 $20,398 $ 8,828 $ 8,653  $ 9,869
Net cash provided by operating activities... $17,261 $21,228 $ 9,524 $ 8,058  $11,061
Total assets at book value.................. $35,071 $41,525 $43,636 $45,441  $50,247
Cash/cash equivalents....................... $   578 $ 1,906 $ 1,076 $   381  $   887
Increase (decrease) in cash/cash equivalents $ 1,328 $   829 $   695 $  (505) $    24
Total liabilities........................... $   272 $    43 $    24 $   176  $    79
Partners' equity............................ $34,798 $41,482 $43,612 $45,265  $50,168


(1) Because of depletion (which is usually higher in the early years of production), a portion of every distribution of revenues from properties represents a return of a limited partner's original investment. Until a limited partner receives cash distributions equal to his original investment, 100% of such distributions may be deemed to be a return of capital.

Management's Discussion and Analysis of Combined Financial Condition and Results of Operations

The following discussion is intended to assist the reader in understanding Republic's combined financial position and results of operations for the three years ended December 31, 2001. This discussion assumes that the Republic Reorganization has occurred. See "The Combination--Preparatory Steps--Reorganization of Republic" beginning on page for a discussion of the Republic reorganization. You should also refer to Republic's financial statements and the notes the financial statements included elsewhere in this document in conjunction with this discussion.

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Overview

Republic's business activities consist of the ownership and administration of producing and nonproducing mineral, royalty, overriding royalty and leasehold interests located in 392 counties and parishes in 23 states. Republic owns and produces oil and natural gas reserves almost exclusively in the capacity of a royalty owner. As a royalty owner, Republic's involvement in the operation of producing properties in which it owns an interest is extremely limited and as such, Republic is a passive participant in these activities. In the instances in which Republic owns the executive rights in nonproducing properties, it is generally able to negotiate certain terms and conditions governing the conduct of its lessees when leasing its interest to third parties who may develop such properties. However, in the event production is established on those properties, Republic's involvement in the operation of such properties is similarly limited and as such Republic becomes a passive participant in such operations. Republic does not engage in oil and gas exploration, development and producing activities as an operator or working interest owner, and except in limited instances, does not bear any cost associated with activity on properties in which it owns an interest. Republic distributes substantially all of its cash flow each year.

Republic's year-to-year changes in net income and net cash flow from operations are principally determined by changes in oil and natural gas sales volumes and oil and natural gas prices. As a royalty owner, Republic essentially has no control over the volumes of oil and natural gas produced and sold from properties in which it owns an interest. Republic's net share of oil and natural gas sales volumes and the corresponding weighted average sales prices were:

                       Years ended December 31
                       -----------------------
                        2001    2000    1999
                       ------- ------- -------
Sales Volumes
   Oil (Bbls)......... 277,653 294,125 306,755
   Gas (MMcf)......... 2,717.2 3,741.5 2,396.5
Weighted Average Price
   Oil ($/Bbl)........   25.36   25.49   15.76
   Gas ($Mcf).........    4.49    3.55    2.19

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

As shown in the table above oil and natural gas sales volumes during 2001 were 5.6% and 27.4% lower, respectively, than during 2000. The decrease in oil sales volume was primarily due to natural reservoir declines. The decrease in natural gas sales volume was primarily due to production declines in the Jeffress Field area of Hidalgo County, Texas and to natural reservoir declines. The significant production decline in the Jeffress Field is attributable to reduced drilling activity and to the high rate of decline customarily observed from wells drilled in the area. Most production in the Jeffress Field area is derived from abnormally pressured Vicksburg sandstone reservoirs that require massive hydraulic fracture stimulation. Production from these reservoirs generally exhibits a hyberbolic decline curve, with significant decline rates in the first years of production, gradually leveling off to lesser rates of declines after two or three years of production. The production and pressure declines exhibited by wells in which Republic owns interests in the Jeffress field are typical of other producers in the field.

Weighted average oil sales prices were essentially unchanged from 2000 to 2001 due to average marketplace prices and the effects of fixed price oil sales contracts attributable to production from several properties in which Republic owns an interest, the terms of which include portions of both years. Weighted average natural gas sales prices were 26.5% higher in 2001 than 2000 due to higher marketplace prices and higher production volumes from the Jeffress Field area during the first half of 2001. Weighted average prices reflect the quotient of gross production revenue divided by net sales volumes, each attributable to a specific product during the year.

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Lease bonus and delay rental income was 53% lower in 2001 than 2000 due to reduced leasing activity and receipt of fewer payments of delay rentals. Other income was 84.7% lower in 2001 than 2000 due to extraordinary amounts received during 2000 attributable to litigation settlement proceeds and reduced interest earned on accumulated balances.

Oil and gas production taxes were 18.4% higher in 2001 than in 2000 due to the expiration of certain state severance tax moratoriums and higher property taxes attributable to higher rendered values.

General and administrative expenses were 17.4% higher during 2001 than 2000 due primarily to increased rent and to salaries and benefits of employees of the general partners and their affiliates, which costs are reimbursed in accordance with Republic's partnership agreement.

Depletion expense was 28.0% lower in 2001 than 2000 due to lower production volumes and reduced depletable cost bases in Republic's properties.

Operating costs were 115.7% higher in 2001 than 2000 due to (a) increased legal expenses associated with the prosecution of the Garza litigation, (b) increased legal expenses associated with the defense of the Salinas litigation, and (c) increased legal and professional expenses attributable to the proposed combination with Dorchester Hugoton and Spinnaker. See "--Legal Proceedings" in this section for a discussion of the Garza and Salinas litigation.

As a result, although total expenses during 2001 were 8.9% lower than 2000, net income during 2001 was 34.8% lower than 2000, due primarily to lower oil and natural as production volumes and lower income from other sources.

Year Ended December 31, 2000 Compared to the Year Ended December 31, 1999

As shown in the table above oil and natural gas sales volumes during 2000 were 4.1% lower and 56.1% higher, respectively, than during 1999. The decrease in oil sales volume was primarily due to natural reservoir declines. The increase in natural gas sales volume was primarily due to production from new wells drilled in 1999 and 2000 in the Jeffress Field area of Hidalgo County, Texas and the Bob West Field area of Starr County, Texas. The drilling activity in Jeffress Field commenced soon after the settlement of litigation between Republic and the operator and other lessees of Republic's interests in that field.

Weighted average oil sales prices were 61.7% higher in 2000 than in 1999 due to average marketplace prices and the effects of fixed price oil sales contracts attributable to production from several properties in which Republic owns an interest, the terms of which includes portions of both years. Weighted average natural gas sales prices were 62.1% higher in 2000 than 1999 due to higher marketplace prices. Weighted average prices reflect the quotient of gross production revenue divided by net sales volumes, each attributable to a specific product during the year.

Lease bonus and delay rental income was 56.9% lower in 2000 than 1999 due to reduced leasing activity and receipt of fewer payments of delay rentals. Other income was 634.9% higher in 2000 than 1999 due to extraordinary amounts received during 2000 attributable to litigation settlement proceeds.

Oil and gas production taxes were 3.7% higher in 2000 than in 1999.

General and administrative expenses were 8.4% higher during 2000 than 1999 due primarily to increased rent and to salaries and benefits of employees of the general partners and their affiliates, which costs are reimbursed in accordance with Republic's partnership agreement.

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Depletion expense was 31.5% higher in 2000 than in 1999 due to higher production volumes.

Operating costs were 91.9% higher in 2000 than 1999 due to increased legal expenses associated with the prosecution of the Garza litigation and increased legal expenses associated with the defense of the Salinas litigation. See "--Legal Proceedings" in this section for a discussion of the Garza and Salinas litigation.

As a result, although total expenses during 2000 were 29.8% higher than 1999, net income during 2000 was 154.6% higher than 1999, due primarily to higher oil and natural gas prices and higher natural gas production volumes.

Liquidity and Capital Resources

Republic's only cash requirements are the distributions pursuant to the Republic ORRIs and the payment of (a) oil and gas production and property taxes not otherwise deducted from gross production revenues, (b) operating expenses associated with the minor working interest properties not otherwise deducted from gross production revenues and (c) general and administrative expenses incurred in its behalf and properly allocated in accordance with its partnership agreement. These cash requirements are funded with oil and natural gas production revenues, lease bonus and delay rental income and nonrecurring income generated from other sources. Since the amounts distributable pursuant to the Republic ORRIs are, by definition, determined after the payment of all expenses actually paid by the partnership, these payments do not represent obligations for which sufficient liquidity is at all times available. As a result, the only cash requirements that may create liquidity concerns for Republic are the payments of taxes and expenses as detailed above. These expenses ranged between 11.5% and 18.9% of total revenues during 1999, 2000 and 2001. Since most of these expenses are dependent upon oil and natural gas prices and sales volumes, sufficient funds are anticipated to be available at all times for payment thereof.

Republic is not liable for the payment of any exploration, development or production costs, with certain limited exceptions, which are both individually and in the aggregate insignificant. Republic does not have any transactions, arrangements or other relationships that could materially affect the partnership's liquidity or the availability of capital resources. Republic had no obligations and commitments to make future contractual payments as of December 31, 2001, other than the December distribution payable to the Republic ORRI Owners in January 2002, as reflected in the financial statements. Republic has not guaranteed the debt of any other party, nor does it have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt.

Critical Accounting Policies

Republic uses the full cost method of accounting for its oil and gas properties. Under the full cost method of accounting, all costs of acquisition, exploration and development of oil and gas properties are capitalized in a "full cost pool" as such costs are incurred. Oil and 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 oil and 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.

Republic's discounted present value of its proved oil and 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 oil and natural gas reserves based on the same information. Republic's 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

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no assurance that more significant revisions will not be necessary in the future. Significant downward revisions could result in a full cost writedown. In addition to the impact on calculation of the ceiling test, estimates of proved reserves are also a major component of the calculation of depletion.

While the quantities of proved reserves require substantial judgment, the associated prices of oil and natural gas reserves that are included in the discounted present value of the 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. Oil and natural gas prices have historically been volatile and the prevailing prices at any given time may not reflect Republic's or the industry's forecast of future prices.

Since Republic generally has not acquired, explored for or developed oil and natural gas properties since its initial formation, capital expenditures and therefore additions to its full cost pool have been and are anticipated to be minimal.

Changes in and Disagreements with Accountants

Republic has not, during its two most recent fiscal years, experienced any changes in or disagreements with KPMG, LLP, the independent accountants engaged as the principal accountants to audit Republic's financial statements.

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

. requiring permits for the drilling of wells;

. maintaining bonding requirements in order to drill or operate wells;

. regulating the location of wells;

. the method of drilling and casing wells;

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

. the plugging and abandonment of wells;

. numerous federal and state safety requirements;

. environmental requirements;

. property taxes and severance taxes; and

. specific state and federal income tax provisions.

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 the oil and natural gas that the operators of Republic's properties can produce and limit the number of wells or the locations at which the operators can drill.

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The transportation of natural gas after sale by operators of the Republic properties is sometimes subject to regulation by federal authorities, specifically by FERC. The interstate transportation of natural gas is subject to federal governmental regulation, including regulation of tariffs and various other matters, by the FERC.

Competition

The energy industry in which Republic competes is subject to intense competition among a large number of companies, both larger and smaller than Republic, many of which have financial and other resources greater than Republic.

Environmental Laws and Regulations

Activities on Republic's properties are subject to existing federal, state and local laws (including case law), rules and regulations governing health, safety, environmental quality and pollution control. It is anticipated that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations regulating health, safety, the release of materials into the environment or otherwise relating to the protection of the environment have not had, and are not anticipated to have, a material adverse effect upon Republic or its limited partners. Republic cannot predict what effect additional regulations or legislation or their enforcement policies and claims for damages to property, employees, other persons or the environment from operations on Republic's properties could have on Republic or its limited partners. Even if Republic were not directly liable for costs and expenses related to these matters, increased costs of compliance could result in wells being plugged and abandoned earlier in their productive lives, with a resulting loss of reserves and revenue to Republic.

Legal Proceedings

Republic is currently involved in pending litigation in two separate matters arising out of the same or similar facts. Republic obtained a judgment in connection with its successful defense of litigation and is currently pursuing the recovery of legal fees in connection with that judgment in an adversary bankruptcy proceeding. The litigation in which Republic obtained its judgment, along with the related bankruptcy proceeding, are referred to as the Garza litigation. The original Garza litigation involves claims of trespass to try title and adverse possession to a portion of a 180 acre tract of land, among other things. Republic was awarded summary judgment awarding it record title to the minerals underlying the disputed tract of land which was upheld in a final, nonappealable judgment by the Texas Supreme Court. Subsequent to the Texas Supreme Court judgment, Republic received a judgment entitling it to attorneys' fees and expenses incurred in defense of this matter. One of the plaintiffs filed a suggestion of bankruptcy causing the legal fees claim to be removed to federal bankruptcy court. On March 29, 2002, Republic was awarded attorneys' fees and expenses in the bankruptcy proceeding and is currently pursuing collection. Republic's risk of loss in this matter is minimal.

Republic is a defendant in a proceeding which is currently pending in Texas state court in Hidalgo County, Texas, referred to as the Salinas litigation. The Salinas litigation involves claims of trespass to try title and adverse possession claim to a portion of a 180 acre tract of land, among other things, in which substantial mineral interests exist and with respect to which all royalties from the tract have been deposited into an escrow account pursuant to an agreement among the parties to the litigation. The chain of title being asserted by the plaintiffs in the Salinas litigation is essentially identical to the chain of title unsuccessfully asserted in the Garza litigation described above. Republic is asserting the identical chain of title that it asserted successfully in the Garza litigation. Therefore, Republic believes that the risk of loss in this matter is minimal. The Salinas litigation is currently set for trial in August 2002. Republic and its co-defendants have recently reached an agreement with the plaintiffs to settle this matter. Final disposition is expected to occur by June 30, 2002.

We will be indemnified from any loss in connection with the Garza or Salinas litigation and any recovery received by us from these matters relating to periods prior to the combination will be assigned by us to the APO Partnership as described in "The Combination--Preparatory Steps--Reorganization of Republic."

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Republic is, and expects 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 its business.

Security Ownership

The following table sets forth information regarding the record and beneficial ownership of Republic's partnership interests, represented as sharing percentages, as of January 1, 2002 as if the combination and the Republic reorganization had taken place on January 1, 2002, by each general partner, each of the executive officers and managers, as applicable, of the general partners, the general partners and all executive officers and managers, as applicable, of the general partners as a group, and all those known by Republic to be beneficial owners of more than five percent of Republic's partnership interests.

                                                                             Sharing
Beneficial Owner                                                            Percentage
----------------                                                            ----------
General Partners and Named Executive Officers/ Managers:
   SAM Partners, Ltd. (1) (10) (11)........................................    7.52%
   Vaughn Petroleum, Ltd. (2) (10) (11)....................................    7.52%
   Frederick M. Smith II (3) (11)..........................................    7.52%
   William Casey McManemin (4) (11)........................................    7.52%
   H.C. Allen, Jr. (5) (11)................................................    7.52%
   Benny D. Duncan (6) (11)................................................    7.52%
   Jack C. Vaughn, Jr. (7) (11)............................................    7.52%
   Robert C. Vaughn (8) (11)...............................................    7.52%
   David C. Vaughn (9) (11)................................................    7.52%

All executive officers/managers and general partners as a group (8 persons)   14.31%

Holders of 5% or More Not Named Above:
   Lucent Technologies Master Pension Trust (12) (13)......................   37.17%
   AT&T Long Term Investment Trust (12) (13)...............................   26.63%
   Delta Airlines Master Trust (12) (13)...................................   18.07%
   Boeing Master Plans Retirement Trust (12) (13)..........................   16.54%
   Bell Atlantic Master Trust (12) (13)....................................   16.54%
   Kodak Retirement Income Plan (12) (13)..................................   14.17%
   Eastman Retirement Assistance Plan (12) (13)............................    9.68%
   RRC APO, L.P. (13)......................................................    8.85%


(1) The business address of SAM Partners, Ltd. and each of its named officers is 3738 Oak Lawn Ave., Suite 300, Dallas, Texas 75219. Includes sharing percentages owned as both a general partner and as a limited partner. (2) The business address of Vaughn Petroleum, Ltd. and each of its named managers is 3738 Oak Lawn, Suite 101, Dallas, Texas 75219. Includes sharing percentages owned as both a general partner and as a limited partner.
(3) Mr. Smith disclaims the sharing percentage owned by SAM Partners, Ltd. In his capacity as President of SAM Partners Management, Inc., the general partner of SAM Partners, Ltd., Mr. Smith may be deemed to beneficially own this sharing percentage based on shared voting or dispositive power.
(4) Mr. Allen disclaims the sharing percentage owned by SAM Partners, Ltd. In his capacity as Vice President of SAM Partners Management, Inc., the general partner of SAM Partners, Ltd., Mr. Allen may be deemed to beneficially own this sharing percentage based on shared voting or dispositive power.
(5) Mr. McManemin disclaims the sharing percentage owned by SAM Partners, Ltd. In his capacity as Secretary of SAM Partners Management, Inc., the general partner of SAM Partners, Ltd., Mr. McManemin may be deemed to beneficially own this sharing percentage based on shared voting or dispositive power.

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(6) Mr. Duncan disclaims the sharing percentage owned by Vaughn Petroleum, Ltd. In his capacity as Manager of VPL (GP) LLC, the general partner of Vaughn Petroleum, Ltd., Mr. Duncan may be deemed to beneficially own this sharing percentage based on shared voting or dispositive power.
(7) Mr. Vaughn disclaims the sharing percentage owned by Vaughn Petroleum, Ltd. In his capacity as Manager of VPL (GP) LLC, the general partner of Vaughn Petroleum, Ltd., Mr. Vaughn may be deemed to beneficially own this sharing percentage based on shared voting or dispositive power.
(8) Mr. Vaughn disclaims the sharing percentage owned by Vaughn Petroleum, Ltd. In his capacity as Manager of VPL (GP) LLC, the general partner of Vaughn Petroleum, Ltd., Mr. Vaughn may be deemed to beneficially own this sharing percentage based on shared voting or dispositive power.
(9) Mr. Vaughn disclaims the sharing percentage owned by Vaughn Petroleum, Ltd. In his capacity as Manager of VPL (GP) LLC, the general partner of Vaughn Petroleum, Ltd., Mr. Vaughn may be deemed to beneficially own this sharing percentage based on shared voting or dispositive power.
(10) Includes sharing percentages indirectly owned through RRC NPI Holdings, LP.
(11) Does not include sharing percentages owned by RRC APO, L.P. which the named person does not beneficially own, but in which the named person may have a contingent economic interest.
(12) Includes sharing percentages indirectly owned through RRC APO, L.P. (13) The business address of each party is c/o Republic Royalty Company, 3738 Oak Lawn, Suite 300, Dallas, Texas 75219.

INFORMATION CONCERNING SPINNAKER

General

Spinnaker was formed in 1996 as a Texas general partnership. Smith Allen Oil & Gas, Inc. was the managing general partner of Spinnaker. Spinnaker was reorganized as a Texas limited partnership in August 1997 in connection with the acquisition of properties from SASI Minerals Company, referred to as SASI. Smith Allen Oil & Gas, Inc. is the sole general partner and a limited partner of Spinnaker. There is no established public trading market for Spinnaker's partnership interests. As of January 1, 2002, one general partner and a total of 14 limited partners hold Spinnaker's partnership interests. The general partner is not aware of any purchases or sales of general partner or limited partner interests since Spinnaker's formation, except for isolated transactions not involving brokers or other market participants.

Spinnaker was originally formed to purchase oil and natural gas properties from Triton Oil and Natural Gas Corp, referred to as Triton. Proceeds from a private offering were used to capitalize Spinnaker, fund the acquisition from Triton and for general partnership business purposes. The reorganization of Spinnaker in 1997 reflected the non-taxable contribution and exchange of oil and natural gas properties, which we call the contributed properties, to Spinnaker by SASI in exchange for limited partnership interests and Spinnaker's reorganization from a general partnership to a limited partnership. SASI acquired the contributed properties in multiple transactions between 1988 and 1997.

Spinnaker's properties consist primarily of producing and non-producing royalty and mineral interests located in 353 counties and parishes in 21 states. See "--Description of the Spinnaker Properties" below for a more detailed description of the Spinnaker properties.

All capital raised by Spinnaker has been invested as planned. As a result of these investments, Spinnaker has achieved its investment objectives of purchasing and owning oil and natural gas properties, including the contributed properties.

Each month Spinnaker distributes all of its cash funds that Smith Allen Oil & Gas, Inc., its general partner, determines are not needed for the payment of existing or foreseeable obligations and expenditures. Distributions are made to partners in accordance with the partners' respective sharing percentages. Smith Allen Oil & Gas, Inc. is reimbursed for its actual and allocable general and administrative expense attributable to Spinnaker's properties and business, subject to a limitation equal to 5% of Spinnaker's net cash flow from operations and excluding any salary for its executive officers and directors.

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Spinnaker's partnership agreement as currently in effect provides for the limited partners to receive sharing percentages equal to 94% of their respective capital contributions. The only capital contributed to Spinnaker is that which was contributed upon its formation. Prior to the consummation of the combination, Spinnaker's partnership agreement will be amended so Smith Allen Oil & Gas, Inc. will hold a 4% interest in Spinnaker and the limited partners of Spinnaker, including Smith Allen Oil & Gas, Inc., will hold interests aggregating a 96% interest in Spinnaker. See "The Combination--Preparatory Steps--Reorganization of Spinnaker" for a description of the Spinnaker reorganization.

Description of the Spinnaker Properties

Spinnaker owns producing and nonproducing mineral, royalty, overriding royalty and leasehold interests. See "Glossary of Certain Oil and Natural Gas Terms" for descriptions of these terms.

Acquisition History

Spinnaker acquired all of its interests from Triton in March 1996 and from SASI in two transactions in August 1997. The interests acquired from Triton are referred to as the Triton properties and the interests acquired from SASI are referred to as the contributed properties. See "--General" above for a discussion of the transactions pursuant to which Spinnaker acquired the Triton properties and the contributed properties.

The Triton properties consisted of all of Triton's producing and nonproducing mineral, royalty, overriding royalty, leasehold and surface interests located in 331 counties and parishes in 20 states. Triton acquired these interests in 14 transactions from 1968 through 1988 from multiple sellers and include properties formerly owned by Bradley Producing Company, Magna Oil, Century Production, WECO Development, Landa Oil, Harp Royalty Limited and others.

The contributed properties consisted of all of SASI's producing and nonproducing mineral, royalty, and overriding royalty interests located in 53 counties and parishes in seven states. SASI acquired these properties in multiple transactions from 1988 through 1997 from multiple sellers including Mayfair Minerals, Tecovas Partners, Crestone Energy and others.

Acreage Summary

The following table sets forth a summary of Spinnaker's gross and net (where applicable) acres of mineral, royalty, overriding royalty and/or leasehold interests, and a compilation of the number of counties and parishes and states and development status of the acres in each category as of January 1, 2002.

                                Mineral
                            ----------------         Overriding
                            Leased  Unleased Royalty  Royalty   Leasehold   Total
                            ------- -------- ------- ---------- --------- ---------
Number of States...........      14      15       12       12         4          20
Number of Counties/Parishes      96     213       98       91         7         353
Gross...................... 146,068 569,489  200,951  100,578     5,981   1,023,067
Net (where applicable).....  13,456 109,597      N/A      N/A       N/A     123,053

Our net interest in production from royalty, overriding royalty and leasehold interests is based on burdens or reservations which vary from property to property. Consequently, net acreage ownership in these categories is not determinable.

Properties located in Texas represented 49% of Spinnaker's total production revenue received during 2001, while properties located in Oklahoma represented 21% and properties located in Louisiana represented 20%.

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The following table sets forth a summary of Spinnaker's 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.

   State     Gross   Net      State      Gross   Net
----------- ------- ------ ------------ ------- ------
Alabama....  32,398  3,297 Nebraska....   2,240     18
Arkansas...  23,463  9,854 New Mexico..   3,996    128
California.     924    162 New York....  19,322 16,787
Colorado...  13,649    409 North Dakota  49,638  1,596
Illinois...     572     37 Oklahoma.... 190,972 12,953
Kansas.....   3,960    410 Pennsylvania   2,043  1,961
Louisiana..  39,638    240 South Dakota   2,151     44
Mississippi  39,865  2,502 Texas....... 307,436 11,557
Missouri...     344     43 Utah........   4,675    160
Montana.... 268,725 60,462 Wyoming.....  17,074    485

Activity Summary

As a royalty owner Spinnaker's access to information concerning activity and operations on its properties is significantly limited. Most of Spinnaker's producing properties are subject to leases and other contracts pursuant to which it is not entitled to well information. Most leases consummated by Spinnaker since its formation in 1993 provide for access to technical data and other information. Spinnaker 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 Spinnaker's properties at any point in time is not determinable. The primary manner by which Spinnaker becomes aware of activity on its 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 received by Spinnaker during 1997 through 2001.

                           2001      2000     1999      1998     1997
                          -------  --------  -------  --------  -------
Consummated Leases
   Number................       7        28        4        15       16
   Number of States......       3         3        4         5        5
   Number of Counties....       5        12        4        12       10
   Average Royalty.......    20.9%     25.4%    20.7%     24.8%    25.4%
   Average Bonus, $/acre. $   107  $    117  $    12  $    160  $    27
   Total Lease Bonus..... $33,046  $161,299  $ 2,260  $111,875  $17,356
Other Land Revenue....... $14,287  $ 47,355  $89,744  $421,180  $22,731
                          -------  --------  -------  --------  -------
Total Land Revenue....... $47,333  $208,654  $92,004  $533,055  $40,087
                          =======  ========  =======  ========  =======
New Wells Added
   Number................     135        44       71        92       60
   Number of States......       7         6        5         7        6
   Number of Counties....      29        19       23        29       23

Oil and Natural Gas Reserves

Huddleston & Co., Inc. has estimated Spinnaker's proved reserves and SEC PV-10 present value attributable thereto as of December 31, 2001 and at year-end annually since 1996.

Huddleston has segregated Spinnaker's properties into three Property Groups. The properties included in these Groups include only those properties evaluated by Huddleston and represent (to the best of Spinnaker's

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knowledge) all of Spinnaker's producing properties as of December 31, 2001, based on information available to Spinnaker. Set forth below is a description of the properties in each Group.

The Group I properties consist of four units located in the Wasson Field in Gaines and Yoakum Counties in west Texas and may be characterized as long lived oil and natural gas fields operated by major oil companies and large independents. The Wasson field is located in the Permian Basin and produces oil and associated gas from depths ranging from 4,500 to 7,500 feet. Enhanced recovery operations are underway in each of the four units included in Group I.

The Group II properties consist of various units, leases and wells located in the Bob West, Jeffress and Port Hudson fields. These fields are located in six counties and parishes in south Texas and south Louisiana and may be characterized as long lived gas and condensate fields operated by major oil companies and large independents. These fields generally produce natural gas and condensate from depths ranging from 8,000 to 17,000 feet.

The Group III properties consist of the balance of Spinnaker's producing properties and are located in 102 counties and parishes in 17 states. The Group III properties produce hydrocarbons from a variety of depths and types of reservoirs. Due to the limited nature of information available to Spinnaker as a royalty owner, and the varying methodologies by which data concerning oil and natural gas operations is reported to the agencies having jurisdiction in the various states, the number of producing oil and natural gas wells included in Group III is not determinable. During 2001, Spinnaker received payment from 359 purchasers for its share of production from 3,216 properties included in Group
III. Any specific property included in Group III may be characterized as individually insignificant in the context of Spinnaker's total proved reserves.

The following table sets forth a summary of certain financial and reserve information for each Property Group for the years ended December 31, 1999 through December 31, 2001.

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                                                                              Years Ended December 31,
                         -------------------------------------------------------------------------------------------------
                                     Group I                         Group II                        Group III
                         ------------------------------- -------------------------------- --------------------------------
                           2001       2000       1999       2001       2000       1999       2001       2000       1999
                         --------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
Proved Developed
   Net Oil (Bbls).......   494,694    515,667    514,945    197,184    222,169    346,930    239,314    228,041    253,091
   Net Gas (Mcf)........   566,000    648,500    836,500  5,825,600  5,309,300  5,779,900  5,905,600  6,711,200  7,411,700
Total Proved
   Net Oil (Bbls).......   494,694    515,667    514,945    198,687    224,075    351,168    280,299    262,468    286,820
   Net Gas (Mcf)........   566,000    648,500    836,500  7,092,300  6,710,300  7,589,900  6,879,100  7,641,600  8,318,700
Annual Production
   Net Oil (Bbls).......    26,144     24,303     24,815     27,763     39,789     52,261     34,607     32,340     37,876
   Net Gas (Mcf)........    21,713     16,402      3,993  1,174,381  1,527,812  1,905,405  1,051,110  1,053,617  1,093,119
Average Prices
   Oil ($/Bbl)..........    $26.38     $19.49     $15.75     $25.80     $27.61     $16.65     $20.67     $25.71     $15.24
   Gas ($/Mcf)..........    $ 4.32     $ 3.70     $ 2.53     $ 4.63     $ 3.65     $ 2.19     $ 4.24     $ 2.82     $ 2.03
Total Proved Future
  Net Revenue ($) (1)
   Undiscounted......... 9,317,382 17,491,875 12,418,426 19,864,743 67,139,459 23,447,266 19,515,944 72,467,263 22,655,934
   SEC PV-10
     present value (2).. 3,621,980  6,821,011  4,709,777 12,672,830 44,044,111 17,328,584 10,532,101 41,550,459 13,064,142

                            Total - All Property Groups
                         ---------------------------------
                            2001       2000        1999
                         ---------- ----------- ----------
Proved Developed
   Net Oil (Bbls).......    931,192     965,877  1,114,966
   Net Gas (Mcf)........ 12,297,200  12,669,000 14,028,100
Total Proved
   Net Oil (Bbls).......    973,680   1,002,210  1,152,933
   Net Gas (Mcf)........ 14,537,400  15,000,400 16,745,100
Annual Production
   Net Oil (Bbls).......     88,514      96,432    114,952
   Net Gas (Mcf)........  2,247,204   2,597,831  3,002,517
Average Prices
   Oil ($/Bbl)..........     $24.06      $25.71     $16.00
   Gas ($/Mcf)..........     $ 4.42      $ 3.26     $ 2.12
Total Proved Future
  Net Revenue ($) (1)
   Undiscounted......... 48,698,069 157,098,597 58,521,626
   SEC PV-10
     present value (2).. 26,826,911  92,415,581 35,102,503


(1) Amounts shown in this table with respect to total proved future net revenue are based on year-end oil and natural gas prices and not on average prices for the entire year.
(2) Spinnaker does not reflect a federal income tax provision since its partners include the income of their partnership in their respective federal income tax returns.

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Contribution and Distribution Information

The following table sets forth information concerning capital contributions by and distributions to Spinnaker's partners. For the purposes of this table, the interests of Spinnaker's partners upon its initial formation, referred to as the original Spinnaker partners, are presented separately from the interests attributable to the partnership interest issued in exchange for the contributed properties. The capital contributions and distributions attributable to the original Spinnaker partners reflect their initial contributions and cumulative distributions to date. The capital contributions and distributions set forth in the following table as being attributable to the partnership interests received upon contribution of the contributed properties reflect the fair value of those assets upon their contribution and distributions attributable to the partnership interest issued upon the contribution since the date of their contribution. The fair value of the contributed properties was deemed to be $8,892,500 on the date of the contribution. For financial statement purposes, the contributing partner's capital contribution to Spinnaker was recorded in an amount equal to the net book value ($4,653,217) of such partner's interest in the contributed properties on the date of the contribution, in accordance with generally accepted accounting principles.

                                                    Cumulative Cash
                               Total Initial     Distributions through
                            Capital Contribution December 31, 2001(1)
                            -------------------- ---------------------
General Partner............     $     2,403           $ 2,526,820
Original Spinnaker Partners     $23,576,000           $37,704,679
Contributed Properties.....     $ 8,892,500           $11,752,503
                                -----------           -----------
   Totals..................     $32,470,903           $51,984,002
                                ===========           ===========


(1) Because of depletion (which is usually higher in the early years of production), a portion of every distribution of revenues from properties represents a return of a limited partner's original investment. Until a limited partner receives cash distributions equal to his original investment, 100% of such distributions may be deemed to be a return of capital.

Selected Historical Financial and Operating Information

The following table presents a summary of selected financial information and operating data for Spinnaker for the periods indicated. It should be read in conjunction with Spinnaker's financial statements and related notes included in this document. The information shown for 2001, 2000 and 1999 is derived from the audited financial statements. The information shown for 1998 and 1997 is unaudited as presented.

                                                     Years ended December 31,
                                             -----------------------------------------
                                              2001     2000    1999    1998     1997
                                             -------  ------- ------- -------  -------
                                                          (in thousands)
Total operating revenues.................... $10,944  $12,212 $ 8,652 $10,051  $ 9,323
Net earnings................................ $ 8,062  $ 9,156 $ 5,365 $ 6,767  $ 5,122
Cash distributions (1)...................... $11,529  $ 9,977 $ 7,367 $10,016  $ 8,151
Net cash provided by operating activities... $10,851  $10,239 $ 7,575 $ 9,595  $ 8,164
Total assets at book value.................. $14,005  $17,425 $18,201 $20,239  $23,593
Cash/cash equivalents....................... $   371  $ 1,049 $   787 $   579  $ 1,000
Increase (decrease) in cash/cash equivalents $  (678) $   262 $   208 $  (421) $   268
Long-term debt, including current portion... $     0  $     0 $     0 $     0  $     0
Total liabilities........................... $   150  $   103 $    58 $    95  $   199
Partners' equity............................ $13,855  $17,322 $18,143 $20,145  $23,394


(1) Because of depletion (which is usually higher in the early years of production), a portion of every distribution of revenues from properties represents a return of a limited partner's original investment. Until a limited partner receives cash distributions equal to his original investment, 100% of such distributions may be deemed to be a return of capital.
(2) The increase in cash in 1997 is computed based upon the change in balances from October 1, 1996 to December 31, 1997. The actual cash balance on December 31, 1996 is currently unavailable.

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Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion is intended to assist the reader in understanding Spinnaker's financial position and results of operations for the three years ended December 31, 2001. You should refer to Spinnaker's financial statements and the notes the financial statements included elsewhere in this document in conjunction with this discussion.

Overview

Spinnaker's business activities consist of the ownership and administration of producing and nonproducing mineral, royalty, overriding royalty and leasehold interests located in 353 counties and parishes in 21 states. Spinnaker owns and produces oil and natural gas reserves almost exclusively in the capacity of a royalty owner. As a royalty owner, Spinnaker's involvement in the operation of producing properties in which it owns an interest is extremely limited and as such, Spinnaker is a passive participant in these activities. In the instances in which Spinnaker owns the executive rights in nonproducing properties, it is generally able to negotiate certain terms and conditions governing the conduct of its lessees when leasing its interest to third parties may develop such properties. However, in the event production is established on those properties, Spinnaker's involvement in the operation of such properties is similarly limited and as such Spinnaker becomes a passive participant in such operations. Spinnaker does not engage in oil and gas exploration, development and producing activities as an operator or working interest owner, and except in limited instances, does not bear any cost associated with activity on properties in which it owns an interest. Spinnaker distributes substantially all of its cash flow each year.

Spinnaker's year-to-year changes in net income, net cash flow from operations and distributions to partners are principally determined by changes in oil and natural gas sales volumes and oil and natural gas prices. As a royalty owner, Spinnaker essentially has no control over the volumes of oil and natural gas produced and sold from properties in which it owns an interest. Spinnaker's net share of oil and natural gas sales volumes and the corresponding weighted average sales prices were:

                          Years ended December 31
                       -----------------------------
                         2001      2000      1999
                       --------- --------- ---------
Sales Volumes
   Oil (Bbls).........    88,514    96,432   114,952
   Gas (MMcf)......... 2,247,204 2,597,831 3,002,517
Weighted Average Price
   Oil ($/Bbl)........     24.06     25.71     16.00
   Gas ($Mcf).........      4.42      3.26      2.12

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

As shown in the table above oil and natural gas sales volumes during 2001 were 8.2% and 13.5% lower, respectively, than during 2000. The decreases in oil and natural gas sales volumes were due to natural reservoir declines.

Weighted average oil sales prices during 2001 were 6.4% lower than 2000 due to average marketplace prices and the effects of a fixed price oil sales contract attributable to production from several properties in which Spinnaker owns an interest, the term of which includes portions of both years. Weighted average natural gas sales prices were 35.6% higher in 2001 than 2000 due to higher marketplace prices and higher production volumes from the Jeffress Field area during the first half of 2001. Weighted average prices reflect the quotient of gross production revenue divided by net sales volumes, each attributable to a specific product during the year.

Lease bonus and delay rental income was 79.5% lower in 2001 than 2000 due to reduced leasing activity and receipt of fewer payments of delay rentals. Other income was 53.0% lower in 2001 than 2000 due to

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extraordinary amounts received during 2000 attributable to litigation settlement proceeds and reduced interest earned on accumulated balances.

Oil and gas production taxes were 24.7% higher in 2001 than in 2000 due to the expiration of certain state severance tax moratoriums and higher property taxes attributable to higher rendered values.

Management expense was 14.6% higher during 2001 than 2000 due primarily to increased rent and to salaries and benefits of employees of the general partner and its affiliates. Management expense reflects general and administrative costs that are reimbursed to the general partner in accordance with Spinnaker's partnership agreement.

Depletion expense was lower 28.8% in 2001 than 2000 due to lower production volumes and reduced depletable cost bases in Spinnaker's properties.

Other operating costs were 204% higher in 2001 than 2000 due to increased legal and professional expenses attributable to the proposed combination with Dorchester Hugoton and Republic.

As a result, although total expenses during 2001 were 5.7% lower than 2000, net income during 2001 was 11.9% lower than 2000, due primarily to lower oil and natural as production volumes and lower income from other sources.

Year Ended December 31, 2000 Compared to the Year Ended December 31, 1999

As shown in the table above oil and natural gas sales volumes during 2000 were 16.1% lower and 13.5% lower, respectively, than during 1999. The decreases in oil and natural gas sales volumes were due to natural reservoir declines.

Weighted average oil sales prices were 60.7% higher in 2000 than in 1999 due to average marketplace prices and the effects of a fixed price oil sales contracts attributable to production from several properties in which Spinnaker owns an interest, the terms of which includes portions of both years. Weighted average natural gas sales prices were 53.8% higher in 2000 than 1999 due to higher marketplace prices. Weighted average prices reflect the quotient of gross production revenue divided by net sales volumes, each attributable to a specific product during the year.

Lease bonus and delay rental income was 820% higher in 2000 than 1999 due to increased leasing activity. Other income was 93% higher in 2000 than 1999 due to extraordinary amounts received during 2000 attributable to litigation settlement proceeds.

Oil and gas production taxes were 19.7% higher in 2000 than in 1999 due to higher oil and natural gas prices and corresponding production revenue.

Management expenses were 11.7% higher during 2000 than 1999 due primarily to increased rent and to salaries and benefits of employees of the general partner and its affiliates. Management expense reflects general and administrative costs that are reimbursed to the general partner in accordance with Spinnaker's partnership agreement.

Depletion expense was 14.8% lower in 2000 than in 1999 due to higher production volumes and reduced depletable cost bases in Spinnaker's properties.

Other operating costs were 14.4% lower in 2000 than 1999 due to decreased professional fees.

As a result, although total expenses during 2000 were only 7% lower than 1999, net income during 2000 was 70.7% higher than 1999, due to higher oil and natural gas prices, increased lease bonus income and income from other sources.

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Liquidity and Capital Resources

Spinnaker's only cash requirements are the limited partner distributions pursuant to its partnership agreement and the payment of (a) oil and gas production and property taxes not otherwise deducted from gross production revenues, (b) operating expenses associated with the minor working interest properties not otherwise deducted from gross production revenues and (c) general and administrative expenses incurred in its behalf and properly allocated in accordance with its partnership agreement. These cash requirements are funded with oil and natural gas production revenues, lease bonus and delay rental income and nonrecurring income generated from other sources. Since the limited partner distributions are, by definition, determined after the payment of all expenses actually paid by the partnership, these payments do not represent obligations for which sufficient liquidity is at all times available. As a result, the only cash requirements that may create liquidity concerns for Spinnaker are the payments of taxes and expenses as detailed above. These expenses ranged between 8.4% and 13.2% of total revenues during 1999, 2000 and 2001. Since most of these expenses are dependent upon oil and natural gas prices and sales volumes, sufficient funds are anticipated to be available at all times for payment thereof.

Spinnaker is not liable for the payment of any exploration, development or production costs, with certain limited exceptions, which are both individually and in the aggregate insignificant. Spinnaker does not have any transactions, arrangements or other relationships that could materially affect the partnership's liquidity or the availability of capital resources. Spinnaker had no obligations and commitments to make future contractual payments as of December 31, 2001, other than the December distribution payable to the Spinnaker partners in January 2002, as reflected in the financial statements. Spinnaker has not guaranteed the debt of any other party, nor does it have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt.

Critical Accounting Policies

Spinnaker uses the full cost method of accounting for its oil and gas properties. Under the full cost method of accounting, all costs of acquisition, exploration and development of oil and gas properties are capitalized in a "full cost pool" as such costs are incurred. Oil and 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 oil and 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.

Spinnaker's discounted present value of its proved oil and 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 oil and natural gas reserves based on the same information. Spinnaker's 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 writedown. In addition to the impact on calculation of the ceiling test, estimates of proved reserves are also a major component of the calculation of depletion.

While the quantities of proved reserves require substantial judgment, the associated prices of oil and natural gas reserves that are included in the discounted present value of the 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. Oil and natural gas prices have historically been volatile and the prevailing prices at any given time may not reflect Spinnaker's or the industry's forecast of future prices.

Since Spinnaker generally has not acquired, explored for or developed oil and natural gas properties since its initial formation, capital expenditures and therefore additions to its full cost pool have been and are anticipated to be minimal.

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Changes in and Disagreements with Accountants

Spinnaker has not, during its two most recent fiscal years, experienced any changes in or disagreements with KPMG, LLP, the independent accountants engaged as the principal accountants to audit Spinnaker's financial statements.

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

. requiring permits for the drilling of wells;

. maintaining bonding requirements in order to drill or operate wells;

. regulating the location of wells;

. the method of drilling and casing wells;

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

. the plugging and abandonment of wells;

. numerous federal and state safety requirements;

. environmental requirements;

. property taxes and severance taxes; and

. specific state and federal income tax provisions.

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 the oil and natural gas that the operators of Spinnaker's 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 the Spinnaker properties is sometimes subject to regulation by federal authorities, specifically 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.

Competition

The energy industry in which Spinnaker competes is subject to intense competition among a large number of companies, both larger and smaller than Spinnaker, many of which have financial and other resources greater than Spinnaker.

Environmental Laws and Regulations

Activities on Spinnaker's properties are subject to existing federal, state and local laws (including case law), rules and regulations governing health, safety, environmental quality and pollution control. It is anticipated that,

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absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations regulating health, safety, the release of materials into the environment or otherwise relating to the protection of the environment have not had, and are not anticipated to have, a material adverse effect upon Spinnaker or its limited partners. Spinnaker cannot predict what effect additional regulations or legislation or their enforcement policies and claims for damages to property, employees, other persons or the environment from operations on Spinnaker's properties could have on Spinnaker or its limited partners. Even if Spinnaker were not directly liable for costs and expenses related to these matters, increased costs of compliance could result in wells being plugged and abandoned earlier in their productive lives, with a resulting loss of reserves and revenue to Spinnaker. Spinnaker has received a written communication from the Environmental Protection Agency regarding alleged violations under the Clean Water Act based on Spinnaker's purported ownership of an operating interest in the property that is the subject of the communication. Spinnaker does not own an operating interest as purported by the EPA. Spinnaker has received no further communication from the EPA regarding this matter and does not believe that this matter will have a material adverse effect on its business, financial condition, results of operations or cash flows.

Security Ownership

The following table sets forth information regarding the record and beneficial ownership of Spinnaker's partnership interests, represented as sharing percentages, as of January 1, 2002 by the general partner, each of the executive officers of the general partner, the general partner and all executive officers of the general partner as a group, and all those known by Spinnaker to be beneficial owners of more than five percent of Spinnaker's partnership interests.

                                                                                 Sharing
Beneficial Owner                                                                Percentage
----------------                                                                ----------
General Partner and Named Executive Officers (1):
    Smith Allen Oil & Gas, Inc., General Partner...............................    4.96%
    Frederick M. Smith, II, President (2)......................................    4.96%
    William Casey McManemin, Vice President (3)................................   75.31%
    H.C. Allen, Jr., Secretary (4).............................................    5.09%

All executive officers and general partner (as a group) (4 persons) (8 persons)   75.44%

Holders of 5% of More Not Named Above:.........................................
    Red Wolf Partners
     c/o William Casey McManemin
     3738 Oak Lawn Ave., Suite 300
     Dallas, Texas 75219.......................................................   67.95%
    New Triton Royalty Ltd.
     1221 McKinney, Suite 3700
     Houston, Texas 77010......................................................   13.70%


(1) The business address of the general partner and each named executive officer is 3738 Oak Lawn Ave., Suite 300, Dallas, Texas 75219.
(2) Mr. Smith disclaims the sharing percentage owned by Smith Allen Oil & Gas, Inc. Mr. Smith in his capacity as President of Smith Allen Oil & Gas, Inc. may be deemed to beneficially own this sharing percentage based on shared voting or dispositive power.
(3) Includes 70.35% sharing percentage owned by various entities of which Mr. McManemin is an officer, manager or general partner, including Red Wolf Partners, or for the benefit of Mr. McManemin and his family, although Mr. McManemin does not have an economic interest in all of these units. Mr. McManemin disclaims the sharing percentage owned by Smith Allen Oil & Gas, Inc. Mr. McManemin in his capacity as Vice-President of Smith Allen Oil & Gas, Inc. may be deemed to beneficially own this sharing percentage based on shared voting or dispositive power.
(4) Mr. Allen disclaims the sharing percentage owned by Smith Allen Oil & Gas, Inc. Mr. Allen in his capacity as Secretary of Smith Allen Oil & Gas, Inc. may be deemed to beneficially own this sharing percentage based on shared voting or dispositive power.

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MANAGEMENT

For a diagram that shows the ownership relationships among us, our general partner, its owners and its subsidiaries, see "Summary--Structure and Management of Dorchester Minerals After the Combination."

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 will exercise the effective control of the management of our partnership.

Dorchester Minerals Management LP's sole business will be to act as our general partner, to own and to act as a partner of Dorchester Minerals Operating LP, and to own and to act as managing member of Dorchester Minerals Operating GP LLC.

Three members of the Board of Managers of Dorchester Minerals Management GP LLC will 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 will determine if the resolution of a conflict of interest is fair and reasonable to us. The members of our advisory committee will be the independent managers of Dorchester Minerals Management GP LLC as described below in " --Management of the General Partner." 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. In addition, the members of the advisory committee will 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.

See "The Combination--Ownership Structure of Dorchester Minerals" for a description of the general partner interest that Dorchester Minerals Management LP owns in us.

Absence of Management Fees; Reimbursement of General Partner

General

We will not compensate Dorchester Minerals Management LP for services provided as our general partner. However, we will reimburse it and Dorchester Minerals Operating LP on a monthly basis for all expenses incurred or payments made on our behalf, and all other necessary or appropriate expenses allocable to us. Such expenses will include both direct expenses and management expenses. Under our Partnership Agreement, direct expenses include:

. professional fees and expenses, such as audit, tax, legal engineering costs;

. regulatory fees and expenses;

. ad valorem taxes;

. severance taxes;

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. the fees and expenses of independent managers or directors of our general partner and its general partner; and

. premiums for officers' and managers' liability insurance.

Management expenses are expenses of the general partner and its affiliates incurred on our behalf and include:

. wages, salaries, incentive compensation and the cost of employee benefit plans passed or provided to employees and officers that are properly allocable to us, and

. all other necessary or appropriate expenses allocable to us,

but do not include items classified as direct expenses or production costs.

As a result of the combination, the working interests currently held by Dorchester Hugoton, as well as certain minor working interests currently held by Republic and Spinnaker will be owned by Dorchester Minerals Operating LP, and we will own the Operating ORRIs in those properties. Under the terms of the Operating ORRIs, the production costs associated with those properties will be deducted in determining the amount of the overriding royalties paid to us. See "The Combination--Preparatory Steps--Creation of Overriding Royalty Interests" for a detailed description of production costs that will be deducted in determining the amount of Operating ORRIs.

Limits upon Management Expenses

Our reimbursements to Dorchester Minerals Management LP, our general partner, of management expenses (excluding overhead expenses included in production costs that are deducted in determining overriding royalties) during any fiscal year will be limited to an amount not greater than five percent (5%) of the sum of our distributions to our partners for that fiscal year, adjusted for changes in cash reserves, plus expenses paid by us for that year for production costs which are capital in nature and charged against the Operating ORRIs, and increases in taxes and regulatory compliance costs.

To the extent that actual reimbursement for management expenses in any fiscal year is less than five percent (5%) of this sum, our reimbursement to Dorchester Minerals Management LP may exceed the five percent limitation by the amount of that difference at any time during the succeeding three fiscal years. If reimbursement to Dorchester Minerals Management LP was limited by the 5% limitation during the preceding three fiscal years, the amount by which the management expenses are less that the 5% limitation in the current year may be used to permit Dorchester Minerals Management LP to recoup the deficit from the preceding years.

Ownership Structure of the General Partner and its General Partner

SAM Partners, Ltd. and Vaughn Petroleum, Ltd. are currently the general partners of Republic. Smith Allen Oil & Gas, Inc. is currently the general partner of Spinnaker. P.A. Peak Holdings LP, will be the successor to P. A. Peak, Inc., and James E. Raley General Partnership will be the successor to James E. Raley, Inc. P. A. Peak, Inc. and James E. Raley, Inc. are currently the general partners of Dorchester Hugoton. These entities will own our general partner and its general partner.

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Dorchester Minerals Management LP

Dorchester Minerals Management GP LLC owns a 0.1% general partnership interest in Dorchester Minerals Management LP. The limited partners of Dorchester Minerals Management LP, who will also be the members of its general partner, Dorchester Minerals Management GP LLC, and their respective limited partnership interests are as follows:

                                   Capital  Profits
Name                               Interest Interest
----                               -------- --------
Vaughn Petroleum, Ltd.............  28.98%   20.48%
SAM Partners, Ltd.................  28.98%   20.48%
Smith Allen Oil & Gas, Inc........  28.26%   19.98%
P.A. Peak Holdings LP.............   6.89%   19.48%
James E. Raley General Partnership   6.89%   19.48%

Provisions are included in the partnership agreement of Dorchester Mineral Management LP so that upon its liquidation allocations will be made to cause the partners' capital accounts to equal their sharing percentages.

Dorchester Minerals Management GP LLC

The members of Dorchester Minerals Management GP LLC and their ownership interests are as follows:

                                   Ownership
Name                               Interest
----                               ---------
Vaughn Petroleum, Ltd.............   20.5%
SAM Partners, Ltd.................   20.5%
Smith Allen Oil & Gas, Inc........   20.0%
P.A. Peak Holdings LP.............   19.5%
James E. Raley General Partnership   19.5%

Management of the General Partner

General

The business and affairs of Dorchester Minerals Management LP are managed by its general partner, Dorchester Minerals Management GP LLC. Dorchester Minerals Management GP LLC is governed by a Board of Managers, which consists of:

. five managers appointed by its members, and

. three independent managers, or such greater number of independent managers as may be required by Nasdaq rules. Each independent manager must not be a security holder, officer, manager, director, or employee of Dorchester Minerals Management GP LLC, or a security holder, officer, manager, director or employee of any affiliate of Dorchester Minerals Management GP LLC. The independent managers, as a group, must also meet the requirements of the Nasdaq rules for members of an audit committee. Independent managers may be holders of our common units.

Each member of Dorchester Minerals Management GP LLC has the power to appoint one manager. The initial appointed managers will be:

. H.C. Allen, Jr., appointed by SAM Partners, Ltd.;

. William Casey McManemin, appointed by Smith Allen Oil & Gas, Inc.;

. Preston A. Peak, appointed by P.A. Peak Holdings LP;

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. James E. Raley, appointed by James E. Raley General Partnership; and

. Robert C. Vaughn, appointed by Vaughn Petroleum, Ltd.

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 as described below in " --Effects of Change in Control."

The Amended and Restated Limited Liability Company Agreement of Dorchester Minerals Management GP LLC authorizes the creation of the following committees:

. Advisory Committee. The members of the Advisory Committee will be designated by the Board of Managers by resolution adopted by a majority of the Board of Managers, which must include at least four appointed managers. All matters decided upon by the Advisory Committee require the approval of the majority of the committee's members. In addition to serving as the advisory committee for purposes of our Partnership Agreement as described above in "--The General Partner," the Advisory Committee has the following functions:

. to review transactions between Dorchester Minerals Management GP LLC and any of its members or affiliates; and

. to review any compensation or benefits paid by us, our general partner, Dorchester Minerals Management GP LLC, Dorchester Minerals Operating LP or Dorchester Minerals Operating GP LLC to any executive officers.

. Operating Committee. The Board of Managers will designate the scope of authority delegated to the Operating Committee by resolution adopted by a majority of the Board of Managers. The Board of Managers has not yet adopted a resolution delegating authority to the Operating Committee, but it is anticipated that the Operating Committee will oversee day-to-day operations of our business. The Operating Committee shall consist of the appointed managers. All matters decided upon by the Operating Committee require the approval of the majority of the committee's members.

. Other Committees. The Board of Managers, by resolution adopted by a majority of the Board of Managers, including at least four appointed managers, may designate other committees. Each committee will have the authority of the Board of Managers to the extent provided in the resolution creating that committee.

Independent Managers

The members of Dorchester Minerals Management GP LLC will appoint independent managers as follows:

. One independent manager appointed collectively by P.A. Peak Holdings LP and James E. Raley General Partnership;

. One independent manager appointed by Vaughn Petroleum, Ltd.; and

. One independent manager appointed collectively by SAM Partners, Ltd. and Smith Allen Oil & Gas, Inc.

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 appoint the independent manager whose death, resignation or removal has created the vacancy. Any independent manager may resign at

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any time by giving notice to Dorchester Minerals Management GP LLC. An independent manager may be removed only by the member or members who appointed that manager.

The initial independent managers of Dorchester Minerals Management GP LLC will be appointed following the consummation of the combination.

Information Regarding Executive Officers and Appointed 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. Each manager will begin serving in that capacity upon the consummation of the combination.

Name                    Age              Position
----                    ---              --------
William Casey McManemin 41  Chief Executive Officer and Manager
H.C. Allen, Jr......... 63  Chief Financial Officer and Manager
James E. Raley......... 62  Chief Operating Officer and Manager
Preston A. Peak........ 80  Manager
Robert C. Vaughn....... 46  Manager

William Casey McManemin currently serves as Vice-President of the general partner of SAM Partners, Ltd., a general partner of Republic, and of Smith Allen Oil & Gas, Inc., the general partner of Spinnaker. Mr. McManemin has served in those capacities since 1993 and 1996, respectively. He co-founded SASI Minerals Company, Republic Royalty Company, Spinnaker Royalty Company LP 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. currently serves as Secretary of the general partner of SAM Partners, Ltd., a general partner of Republic, and of Smith Allen Oil & Gas, Inc., the general partner of Spinnaker. Mr. Allen has served in those capacities since 1993 and 1996, respectively. He co-founded SASI Minerals Company, Republic Royalty Company, Spinnaker Royalty Company LP 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 is the sole shareholder of James E. Raley, Inc., which has served as a general partner of Dorchester Hugoton since 1990. 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.

Preston A. Peak, a co-founder of Dorchester Hugoton, Ltd., has served as a general partner since 1982. He holds a Bachelor of Science degree from the U.S. Naval Academy and a Master of Business Administration

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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 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 1900's and is the general Partner of Vaughn Petroleum, Ltd., a general partner of Republic Royalty Company and 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.

Effects of Change in Control

In the event that a member of Dorchester Minerals Management GP LLC experiences a change in control, that member's right to appoint an appointed manager will immediately expire unless the other members unanimously agree to a continuation of the appointment right. If the appointment right expires, that position on the Board of Managers will then be elected by the vote of a majority of the other members of Dorchester Minerals Management GP LLC.

A member that has experienced a change in control will also lose its right to appoint an independent manager unless the other members unanimously agree to a continuation of the appointment right. If the member who experiences a change in control shares its appointment right with another member, then if the appointment right is lost, that other member will have the sole right to appoint the independent manager. If each member who shares an appointment right, or if a member with the sole right to appoint an independent manager, lose their appointment rights, that independent manager will be elected by the vote of a majority of the other members. If any additional independent managers are required by Nasdaq rules, those independent managers will be appointed by a vote of the majority of the members. Any independent manager appointed by a vote of the members may be removed at any time with or without cause by the vote of two-thirds of the members.

The Operating Subsidiary

General

Our general partner owns, directly and indirectly through Dorchester Minerals Operating GP LLC, all of the partnership interests in Dorchester Minerals Operating LP, and indirectly controls its management through Dorchester Minerals Operating GP LLC. After the consummation of the combination, Dorchester Minerals Operating LP will hold the working interests and most of the other operational assets now owned by Dorchester Hugoton, the minor working interests owned by Republic and Spinnaker and most of the operational assets now owned by Smith Allen Oil & Gas, Inc., the general partner of Spinnaker. Dorchester Minerals Operating LP will also provide day-to-day operational support and services to us and to our general partner, such as accounting, land and tax services. Actual and reasonable costs incurred by Dorchester Minerals Operating LP in performing the services will be reimbursed by us.

Ownership and Management of Dorchester Minerals Operating LP

Dorchester Minerals Operating LP is a limited partnership whose general partner is Dorchester Minerals Operating GP LLC. Dorchester Minerals Management LP is the limited partner of Dorchester Minerals Operating LP, owning a 99.9% limited partnership interest. Dorchester Minerals Management LP is also the sole member of Dorchester Minerals Operating GP LLC.

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Dorchester Minerals Operating LP is managed by its general partner, Dorchester Minerals Operating GP LLC, which has the authority to designate one or more officers to perform day-to-day management functions. Dorchester Minerals Operating GP LLC is managed by its sole member, Dorchester Minerals Management LP, and by officers designated by Dorchester Minerals Management LP.

Officers of Dorchester Minerals Operating GP LLC

The following information sets forth, where applicable, the age, business experience during the past five years, position and office of each executive officer of Dorchester Minerals Operating GP LLC. Each executive officer began serving in that capacity on December 12, 2001 and will serve until his successor is appointed by Dorchester Minerals Management GP LLC or until his death, resignation or removal.

Name                           Position
----                           --------
William Casey McManemin Chief Executive Officer
James E. Raley......... Chief Operating Officer
H.C. Allen, Jr......... Chief Financial Officer
Kathleen A. Rawlings... Controller

The ages and biographies of Messrs. McManemin, Raley and Allen are set forth on page 143.

Kathleen A. Rawlings, 45, has been the Controller and Principal Accounting officer of Dorchester Hugoton, Ltd. since 1991, and has been employed by Dorchester Hugoton since 1984. Prior to 1984, Mrs. Rawlings was employed by Dorchester Refining Company, a subsidiary of Dorchester Gas Corporation. Mrs. Rawlings has a Bachelor of Science degree in Business Management from LeTourneau University.

Conflicts of Interest

For a description of the conflicts of interests which may exist following the combination and how those conflicts will be resolved, see "Conflicts of Interests and Fiduciary Duties" and "Business Opportunities Agreement" in this document.

Officers of Dorchester Minerals

Our partnership will also have persons designated as officers for convenience in executing agreements and making regulatory filings. However, as discussed above, effective management control of our partnership will be exercised by the Board of Managers of Dorchester Minerals Management GP LLC which is the general partner of our general partner. Our officers will be subject to appointment and removal by our general partner.

The following information sets forth the office of each of our executive officers. Each executive officer will begin serving in that capacity upon the consummation of the combination and will serve until his successor is appointed by our general partner or until his death, resignation, retirement, disqualification or removal.

Name                           Position
----                           --------
William Casey McManemin Chief Executive Officer
James E. Raley......... Chief Operating Officer
H.C. Allen, Jr......... Chief Financial Officer

The ages and biographies of Messrs. McManemin, Raley and Allen are set forth on page 143.

Executive Compensation

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 will be 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 will not be paid any compensation for their services as officers of our partnership. Our officers will, 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. The level of compensation for these services has not yet been determined and will be determined after the consummation of the combination by the Advisory Committee of Dorchester Minerals Management GP LLC. 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 anticipate implementing any option or other incentive compensation plans for the benefit of our employees and officers and those of our affiliates. We do intend to offer life, health, dental and other insurance plans and other benefits such as retirement, vacation and other off-time benefits comparable to those currently available to the employees of the combining partnerships.

Two employees of Dorchester Hugoton will be offered employment contracts by Dorchester Minerals Operating LP with terms of at least two years and at an annual salary equal to at least the annual salary paid to the employee by Dorchester Hugoton as of the date of the Combination Agreement.

CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

General

Conflicts of interest exist and may arise in the future as a result of the relationships between Dorchester Minerals Management LP, our general partner, and its affiliates, on the one hand, and our partnership and our limited partners, on the other hand. The officers and members of the general partner of our general partner, Dorchester Minerals Management GP LLC, have fiduciary duties to manage Dorchester Minerals Management GP LLC in a manner beneficial to its owners. At the same time, those officers and members have a duty to cause Dorchester Minerals Management GP LLC to manage Dorchester Minerals Management LP and our partnership in a manner beneficial to us and our limited partners.

Whenever any potential conflict of interest exists or arises between Dorchester Minerals Management LP or any of its affiliates and us or any of our partners, Dorchester Minerals Management LP will resolve that conflict. Our Partnership Agreement authorizes Dorchester Minerals Management LP to seek approval of a majority of the members of the Advisory Committee of Dorchester Minerals Management GP LLC as to a proposed resolution of the conflict, and, if the Advisory Committee approves it, it will conclusively be deemed to be fair and reasonable to us. Dorchester Minerals Management LP is not required to obtain Advisory Committee approval.

Alternatively, any resolution of a conflict of interest shall also be conclusively deemed fair and reasonable to us if such resolution is:

. on terms no less favorable to us than those generally being provided to or available from unrelated third parties, or

. fair to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us).

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Dorchester Minerals Management LP, or its general partner's Advisory Committee if its approval is sought, is authorized, in connection with its determination of what is fair and reasonable to us, and in connection with its resolution of any conflict of interest, to consider:

. the relative interests of any party to such conflict, agreement, transaction or situation and the benefits and burdens relating to such interest,

. any customary or accepted industry practices and any customary or historical dealings with a particular person,

. any applicable generally accepted accounting practices or principles, and

. such additional factors as Dorchester Minerals Management LP, or its general partner's Advisory Committee, determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances.

Whenever our Partnership Agreement requires that a particular transaction, arrangement or resolution of a conflict of interest be fair and reasonable, the fair and reasonable nature of that transaction, arrangement, or resolution shall be considered in the context of all similar or related transactions.

Conflicts of interest may arise in the situations described below, among others:

Our general partner's affiliates may compete with us.

Our general partner--Dorchester Minerals Management LP, its general partner--Dorchester Minerals Management LLC, and its subsidiaries--Dorchester Minerals Operating LP and Dorchester Minerals Operating GP LLC will not engage in the acquisition, management, operation or sale of oil and natural gas properties except:

. in connection with the management and operation of our business, and

. except for the ownership of working interests in properties in which we will hold the Operating ORRIs.

However, subject to the requirements of the Business Opportunities Agreement, our Partnership Agreement will permit:

. the general partner of our general partner--Dorchester Minerals Management GP LLC,

. persons who are our officers,

. persons who are officers, managers or partners of our general partner--Dorchester Minerals Management LP,

. persons who are officers of the subsidiaries of our general partner--Dorchester Minerals Operating LP and Dorchester Minerals Operating GP LLC, and

. affiliates of these persons,

to engage in the acquisition, management, operation and sale of oil and natural gas properties or other activities that may create a potential conflict of interest with us. Subject to compliance with the Business Opportunities Agreement, our Partnership Agreement provides that:

. these persons will have the right to engage in businesses and activities of every type including businesses and activities in competition with us,

. engaging in these businesses and activities will not constitute a breach of our Partnership Agreement or any express or implied duty of these persons to any partner or assignee,

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. engaging in such activities by these persons is approved by us and all our partners, and is not deemed to be a breach of fiduciary duty or other obligations by our general partner and these persons have no obligations to present business opportunities to us.

However, our executive officers--William Casey McManemin, James E. Raley and H.C. Allen, Jr.--are parties to the Business Opportunities Agreement and are required by it to present to us certain business opportunities that become available to them. It is anticipated that persons who will hold executive offices with us and with Dorchester Minerals Operating LP or Dorchester Minerals Operating GP LLC in the future will also be required to join in the Business Opportunities Agreement and be similarly bound by its terms. See "Business Opportunities Agreement" for a description of the terms of the Business Opportunities Agreement.

Individuals that control the general partners of the combining partnerships will effectively control the management of our partnership.

The general partners of Republic, Spinnaker and Dorchester Hugoton or their successors will own all of the equity ownership of Dorchester Minerals Management LP, the general partner of our partnership, and will as a result also indirectly own all of the equity ownership of Dorchester Minerals Operating LP. However, neither any single general partner of Republic, Spinnaker or Dorchester Hugoton, nor the general partners of any one of Republic, Spinnaker or Dorchester Hugoton, will hold a large enough interest to control Dorchester Minerals Management LP or Dorchester Minerals Management GP LLC without the support of other general partners.

Individuals that control the general partners of the combining partnerships will receive partnership distributions and other benefits associated with their interests in our general partner and its affiliates.

See " --Interests of Certain Persons" below for a detailed description of the distributions and other benefits that these individuals may receive.

We will reimburse the general partner and its affiliates for expenses.

We will reimburse Dorchester Minerals Management LP and its affiliates for expenses it incurs or pays on our behalf, or which are allocable to us, subject to limits in our Partnership Agreement. See "Management-- Limits on Management Expenses."

We do not have any employees (other than our officers) and rely solely on the officers and employees of our general partner and its affiliates.

Affiliates of Dorchester Minerals Management LP may conduct businesses and activities other than ours, in which we may not have an economic interest. As a result, there could be material competition for the time and effort of the officers who provide services to Dorchester Minerals Management LP.

Fiduciary Duties Owed to Our Unitholders

Our general partner is accountable to us and our unitholders as a fiduciary. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, restrict or expand the fiduciary duties owed by the general partner to limited partners and the partnership.

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Our Partnership Agreement contains various provisions restricting the fiduciary duties that might otherwise be owed by the general partner. The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:

State-law fiduciary
  duty Standards............  Fiduciary duties are generally considered to
                              include an obligation to act with due care and
                              loyalty. The duty of care, in the absence of a
                              provision in a partnership agreement providing
                              otherwise, would generally require a general
                              partner to act for the partnership in the same
                              manner as a prudent person would act on his own
                              behalf. The duty of loyalty, in the absence of a
                              provision in a partnership agreement providing
                              otherwise, would generally prohibit a general
                              partner of a Delaware limited partnership from
                              taking any action or engaging in any transaction
                              where a conflict of interest is present.

                              The Delaware Act generally provides that a
                              limited partner may institute legal action on
                              behalf of the partnership to recover damages from
                              a third party where a general partner has refused
                              to institute the action or where an effort to
                              cause a general partner to do so is not likely to
                              succeed. In addition, the statutory or case law
                              of some jurisdictions may permit a limited
                              partner to institute legal action on behalf of
                              himself and all other similarly situated limited
                              partners to recover damages from a general
                              partner for violations of its fiduciary duties to
                              the limited partners.

Partnership Agreement
  modified Standards........  Our Partnership Agreement contains provisions
                              that waive or consent to conduct by our general
                              partner and its affiliates that might otherwise
                              raise issues as to compliance with fiduciary
                              duties or applicable law. For example, our
                              Partnership Agreement permits our general partner
                              to make a number of decisions in its "sole
                              discretion." This entitles the general partner to
                              consider only the interests and factors that it
                              desires and it has no duty or obligation to give
                              any consideration to any interest of, or factors
                              affecting, us, our affiliates or any limited
                              partner. Other provisions of the Partnership
                              Agreement provide that the general partner's
                              actions must be made in its reasonable
                              discretion. These standards reduce the
                              obligations to which the general partner would
                              otherwise be held.

                              Our Partnership Agreement generally provides that
                              affiliated transactions and resolutions of
                              conflicts of interest not involving a required
                              vote of unitholders must be "fair and reasonable"
                              to us under the factors described above in "
                              --General." In determining whether a transaction
                              or resolution is "fair and reasonable" our
                              general partner may consider interests of all
                              parties involved, including its own. Unless our
                              general partner has acted in bad faith, the
                              action taken by our general partner shall not
                              constitute a breach of its fiduciary duty. These
                              standards reduce the obligations to which our
                              general partner would otherwise be held.

                              In addition to the other more specific provisions
                              limiting the obligations of our general partner,
                              our Partnership Agreement further

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                              provides that our general partner and its
                              officers and directors will not be liable for
                              monetary damages to us, the limited partners or
                              assignees for errors of judgment or for any acts
                              or omissions if the general partner and those
                              other persons acted in good faith.

In order to become one of our limited partners, a common unitholder is required to agree to be bound by the provisions in our Partnership Agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner or assignee to sign a partnership agreement does not render the Partnership Agreement unenforceable against that person.

We must indemnify our general partner and its officers, directors, employees, affiliates, partners, members, agents and trustees, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by the general partner or these other persons. We must provide this indemnification if our general partner or these persons acted in good faith and in a manner they reasonably believed to be in, or (in the case of a person other than the general partner) not opposed to, our best interests. We also must provide this indemnification for criminal proceedings if our general partner or these other persons had no reasonable cause to believe their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it met these requirements concerning good faith and our best interests. See "The Partnership Agreement--Indemnification."

Interest of Certain Persons in the Combination

The general partners of the combining partnerships will have continuing relationships with and engage in transactions with us on an ongoing basis following the closing of the combination. As a result of these relationships and transactions, the general partners of the combining partnerships may be considered to have a financial interest in the combination which may be different from the financial interests of their respective partnerships and the limited partners in our partnership following the combination.

In addition, the individuals who are the owners of the general partners of the combining partnerships or who are involved in their management will have ownership interests in, or hold management positions with, our partnership, Dorchester Minerals Management LP and Dorchester Minerals Operating LP. As a result, those individuals may be considered to have a financial interest in the combination and in our partnership on an ongoing basis which may be different from the interests of the limited partners of their respective partnerships and from the limited partners of our partnership.

These relationships are summarized below.

Ownership of and Positions with our Partnership and certain Affiliates. The general partners of the combining partnerships and certain individuals that serve as officers or managers of these general partners will own interests in and hold positions with us, Dorchester Minerals Management LP and its affiliates. See "Management" and "Security Ownership of Certain Beneficial Owners and Management."

Working Interests Held by Dorchester Minerals Operating LP and Calculation of Overriding Royalty Interest. The transfer to Dorchester Minerals Operating LP of working interests held by the combining partnerships will be made subject to the reservation of the Operating ORRIs, which will be held by us following the combination. The amount of the Operating ORRIs was established by the general partners of the combining partnerships so that the total of the 3.03% interest in the net operating revenues attributable to the working interests burdened by the Operating ORRIs, which will be owned by Dorchester Minerals Operating LP, and the general partner's 1% share of the Operating ORRIs held by us would equal a 4% economic interest owned by the general partner after the combination in the properties burdened by the Operating ORRIs. This 4% economic interest will be similar in amount to the economic interest held by Dorchester Minerals Management LP in the properties formerly held by Republic and Spinnaker, and is generally the same as the compensation historically

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paid to Dorchester Hugoton's general partners. A comparison of actual compensation received by the general partners to the pro forma compensation of our general partner assuming the combination begins on page 152 of this document. The 3.03% interest in the properties burdened by the Operating ORRIs, in the opinion of the general partners of the combining partnerships and Dorchester Hugoton's Advisory Committee, also approximated the amount of overriding royalty interest an independent third party would be willing to agree to in order to accept a conveyance of a working interest encumbered by such an overriding royalty interest and assume the risks associated with ownership of the properties covered by it. These risks would include the risk that the cash flow from the properties might not cover the short term costs of operation of such properties, including such matters as third party claims, casualty losses or environmental issues and the risk that a catastrophic loss or claim for which a working interest owner would be liable might exceed the total value of the properties. The parties did not engage an appraiser to assist in the determination of the amount of the overriding royalty interest or attempt to find an independent third party who would acquire the working interests subject to an overriding royalty interest, and the amount of the overriding royalty interest may not reflect the amount that would be established by an arm's-length transaction.

However, under the partnership agreement of Dorchester Hugoton, because the transaction may be deemed to be with an affiliate of the general partners of Dorchester Hugoton, and they may be deemed to have an interest in the transaction, the conveyance of Dorchester Hugoton's working interests and creation of the overriding royalty interest in them was considered and approved by the Advisory Committee of Dorchester Hugoton as to its fairness to the depositary receipt holders of Dorchester Hugoton. The Advisory Committee of Dorchester Hugoton is charged with reviewing such transactions from the standpoint of their fairness to the depositary receipt holders of Dorchester Hugoton. Its approval does not represent any review or judgment on its part as to the fairness of the transaction to the limited partners of Republic or Spinnaker or as to the fairness to any of the limited partners or depositary receipt holders of the conveyances of the minor working interests conveyed by Republic and Spinnaker to Dorchester Minerals Operating LP on similar terms.

The Operating ORRIs also include provisions for a reimbursement of overhead expenses in connection with working interest operations. Such overhead reimbursement will be determined by using cents-per-mile and dollars-per-well-per-month methods customary in the industry. It will be included in production costs and not in management expenses and, therefore, will not be subject to the limit on management expense reimbursements. In no event will the combination of overhead and management expense reimbursements exceed actual costs incurred. See "The Combination--Preparatory Steps--Creation of Overriding Royalty Interests" beginning on page 53 of this document for a description of the terms of the Operating ORRIs.

Transfer of Certain Management and Operating Assets. Dorchester Hugoton will convey its management and remaining operating assets to Dorchester Minerals Operating LP in exchange for a promissory note and the assumption by Dorchester Minerals Operating LP of certain obligations. The terms of this transfer and the promissory note and the appraisal which will determine the amount of the promissory note are discussed under the caption "The Combination--Transfer of Assets by Dorchester Hugoton and Liquidation" at page 57 of this document. In addition, the terms of this transfer, the promissory note and the use of an appraisal (but not the actual appraisal amount) were reviewed and approved as to fairness by the Advisory Committee of Dorchester Hugoton on the same basis as their review and approval as to fairness of the creation of the overriding royalty interest and subject to the same limitations and qualifications discussed above.

Indemnification and Insurance. We will indemnify the partners, affiliates of the partners, directors, officers and employees of the combining partnerships following the consummation of the combination for matters occurring prior to the combination to the extent the applicable combining partnership would have been required to do so under its partnership agreement. See "The Combination Agreement--Additional Agreements." Further, Dorchester Hugoton has agreed to purchase continuing directors and officers liability coverage covering the general partners, officers and Advisory Committee of Dorchester Hugoton. See "The Combination Agreement--Certain Covenants." The terms of these indemnification and insurance obligations were reviewed and approved as to fairness by the Advisory Committee of Dorchester Hugoton on the same basis as their review

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and approval as to fairness of the creation of the overriding royalty interest and subject to the same limitations and qualifications discussed above.

Financial Interests. As a result of their beneficial ownership of interests in Dorchester Minerals Management LP and its affiliates, the general partners of the combining partnerships will have a financial interest in us in the form of an interest in the cash distributions that will be made to Dorchester Minerals Management LP with respect to its general partnership interest in us. The following table presents the actual management fees, cash distributions and expense reimbursements actually paid or payable by each of the combining partnerships to their general partners during the last three fiscal years and compares those payments to the amounts, as listed in the pro forma column, that would have been paid to them for each of those categories. Amounts shown in the pro forma columns of the table do not include compensation which may be paid to William Casey McManemin, H.C. Allen, Jr. or James E. Raley for service as executive officers of Dorchester Minerals Operating LP. These amounts are paid by Dorchester Minerals Management LP and could be reimbursed by us to the extent total reimbursements for general and administrative expenses are less than the limitation of reimbursement. See "Management--Absence of Management Fees; Reimbursement of General Partner--Limits upon Management Expenses." Please note that the following table assumes that pro forma cash distributions will be made as provided by our Partnership Agreement, which differs from the distribution policy set forth in Dorchester Hugoton's partnership agreement. See "The Partnership Agreement--Distributions of Available Cash."

                                                                                    Years Ended
                                                         -----------------------------------------------------------------
                                                           December 31, 2001     December 31, 2000     December 31, 1999
                                                         --------------------- --------------------- ---------------------
                                                                       Pro                   Pro                   Pro
                                                           Actual     Forma      Actual     Forma      Actual     Forma
                                                         ---------- ---------- ---------- ---------- ---------- ----------
P.A. Peak, Inc./           Management Fee (1)........... $  145,896 $        0 $  137,905 $        0 $   88,509 $        0
P.A.Peak Holdings, Inc.    Cash Distributions (2)....... $   66,745 $  345,649 $   48,837 $  388,463 $   39,070 $  217,924
                           Expense Reimbursement (3) (4) $    9,714 $    9,714 $    8,441 $    8,441 $    7,185 $    7,185
                                                         ---------- ---------- ---------- ---------- ---------- ----------
                               Total.................... $  222,355 $  355,363 $  195,183 $  396,904 $  134,764 $  225,109
James E. Raley, Inc./      Management Fee (1)........... $  458,896 $        0 $  450,905 $        0 $  401,509 $        0
James E. Raley General     Cash Distributions (2)....... $   66,745 $  345,649 $   48,837 $  388,463 $   39,070 $  217,924
Partnership                Expense Reimbursement (3).... $   41,703 $   41,703 $   32,294 $   32,294 $   33,026 $   33,026
                                                         ---------- ---------- ---------- ---------- ---------- ----------
                               Total.................... $  567,344 $  387,352 $  532,036 $  420,757 $  473,605 $  250,950
Subtotal--General Partners Management Fee............... $  604,792 $        0 $  588,810 $        0 $  490,018 $        0
Of Dorchester Hugoton      Cash Distributions........... $  133,490 $  691,298 $   97,674 $  776,926 $   78,140 $  435,848
                           Expense Reimbursement........ $   51,417 $   51,417 $   40,735 $   40,735 $   40,211 $   40,211
                                                         ---------- ---------- ---------- ---------- ---------- ----------
                               Total.................... $  789,699 $  742,715 $  727,219 $  817,661 $  608,369 $  476,059
SAM Partners, Ltd.         Management Fee (5)........... $        0 $        0 $        0 $        0 $        0 $        0
                           Cash Distributions (6)....... $  341,490 $  363,375 $  421,008 $  408,385 $  190,651 $  229,100
                           Expense Reimbursement (7).... $  267,540 $  267,540 $  227,957 $  227,957 $  210,346 $  210,346
                                                         ---------- ---------- ---------- ---------- ---------- ----------
                               Total.................... $  609,030 $  630,915 $  648,965 $  636,342 $  400,997 $  439,446
Vaughn Petroleum, Ltd.     Management Fee (5)........... $        0 $        0 $        0 $        0 $        0 $        0
                           Cash Distributions (6)....... $  341,490 $  363,375 $  421,008 $  408,385 $  190,651 $  229,100
                           Expense Reimbursement (7).... $        0 $        0 $        0 $        0 $        0 $        0
                                                         ---------- ---------- ---------- ---------- ---------- ----------
                               Total.................... $  341,490 $  363,375 $  421,008 $  408,385 $  190,651 $  229,100
Subtotal--General          Management Fee............... $        0 $        0 $        0 $        0 $        0 $        0
Partners Of Republic       Cash Distributions........... $  682,980 $  726,750 $  842,016 $  816,770 $  381,302 $  458,200
                           Expense Reimbursement........ $  267,540 $  267,540 $  227,957 $  227,957 $  210,346 $  210,346
                                                         ---------- ---------- ---------- ---------- ---------- ----------
                               Total.................... $  950,520 $  994,290 $1,069,973 $1,044,727 $  591,648 $  668,546
Smith Allen Oil & Gas,     Management Fee (8)........... $        0 $        0 $        0 $        0 $        0 $        0
Inc.                       Cash Distributions (9)....... $  435,052 $  354,512 $  408,624 $  398,424 $  320,916 $  223,512
                           Expense Reimbursement (10)... $  306,000 $  306,000 $  267,002 $  267,002 $  239,000 $  239,000
                                                         ---------- ---------- ---------- ---------- ---------- ----------
                               Total.................... $  741,052 $  660,512 $  675,626 $  665,426 $  559,916 $  462,512
Total--Owners of Our       Management Fee............... $  604,792 $        0 $  588,810 $        0 $  490,018 $        0
General Partner            Cash Distributions........... $1,251,522 $1,772,560 $1,348,314 $1,992,120 $  780,358 $1,117,560
                           Expense Reimbursement........ $  624,957 $  624,957 $  535,694 $  535,694 $  489,557 $  489,557
                                                         ---------- ---------- ---------- ---------- ---------- ----------
                               Total.................... $2,481,271 $2,397,517 $2,472,818 $2,527,814 $1,759,933 $1,607,117

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(1) The general partners of Dorchester Hugoton are entitled to a management fee each year equal to $350,000 plus 1% of the gross income of Dorchester Hugoton for services rendered in operating and managing Dorchester Hugoton. The 1% component of the fee is paid 50% to P.A. Peak, Inc. and 50% to James E. Raley, Inc. The allocation of the $350,000 component of the fee among the two general partners varies from year to year based on agreement of the general partners. In each of the years 1999 through 2001 the fee was reduced to $337,000, of which $325,000 was paid to James E. Raley, Inc. and $12,000 was paid to P.A. Peak, Inc.
(2) The general partners of Dorchester Hugoton each hold a 0.5% general partner interest in Dorchester Hugoton. The general partners of Dorchester Hugoton will each hold a 19.48% interest in profits and a 6.98% interest in capital in the general partner of our partnership, which will (i) be entitled to receive a 1% interest in cash flow attributable to the Operating ORRIs and a 4% interest in cash flow attributable to the properties formerly held by Republic and Spinnaker and (ii) own all of Dorchester Minerals Operating LP. Dorchester Minerals Operating LP will own 100% of the working interests in the properties formerly owned by the combining partnerships that will be burdened by the Operating ORRIs owned by our partnership. See "The Combination--Preparatory Steps--Creation of Overriding Royalty Interests." The amounts shown in the pro forma columns of the table represent the distributions that would have been received (i) by Dorchester Minerals Management LP multiplied by the 19.48% beneficial ownership interest (based on profits) of each of the general partners of Dorchester Hugoton in Dorchester Minerals Management LP and (ii) by Dorchester Minerals Operating LP, after the deduction of the Operating ORRIs, multiplied by the 19.48% beneficial ownership interest (based on profits) of each of the general partners of Dorchester Hugoton in Dorchester Minerals Management LP. The amounts shown in the actual and pro forma columns do not include cash distributions with respect to limited partner interests held by affiliates of a general partner. Distributions to Dorchester Hugoton general partners are based in part on the amount of cash distributions to its limited partners pursuant to the general partners' policy of building some cash reserves rather than distributing all available cash.
(3) The general partners of Dorchester Hugoton are also reimbursed for all out-of-pocket costs and general and administrative expenses incurred by them on behalf of Dorchester Hugoton. General and administrative costs include the costs incurred for employee benefits on behalf of the general partners. The amounts shown in the actual columns of the table include all general partner reimbursements. General and administrative expenses incurred in connection with Dorchester Hugoton's operations are incurred for the most part directly by Dorchester Hugoton and paid directly by it instead of being incurred by its general partners and then reimbursed. The general partners of Republic and Spinnaker, however, incur directly all general and administrative and other overhead expenses and are reimbursed for these expenses by the partnerships in accordance with their respective partnership agreements. Dorchester Minerals will have no employees (other than officers), offices or other activities that directly generate general and administrative expenses. Instead those expenses will be incurred by its general partner and Dorchester Minerals Operating LP and then reimbursed by Dorchester Minerals to the general partner or Dorchester Minerals Operating LP. Accordingly, a comparison of actual and pro forma expenses reimbursed would result in an inconsistent presentation. In the table, as presented, actual expense reimbursements reflect actual amounts paid by the general partners of the combining partnerships and to which they are entitled to reimbursement in accordance with the partnership agreement of their respective combining partnership. Pro forma expense reimbursements reflect actual amounts that would have been paid by the partners of our general partner and reimbursement of those amounts in accordance with our general partner's partnership agreement. The actual amount of expense reimbursements differs from the percentage allocation of cash distributions
(and production costs included in the determination of Operating ORRIs) because reimbursements are made to our general partner's partners in accordance with actual costs paid and without regard to the partners' interest in capital and profits.
(4) Includes general and administrative expense reimbursement of $484 for 1999, $507 for 2000 and $601 for 2001 for expenses of Hugoton Nominee, Inc., which is wholly-owned by P.A. Peak, Inc.
(5) The general partners of Republic are not entitled to receive a management fee.
(6) The general partners of Republic each hold a 2% general partner interest in Republic assuming the Republic reorganization has occurred. The general partners of Republic will each hold a 20.48% interest in profits and a 28.98% interest in capital in the general partner of our partnership, which will (i) be entitled to receive a 1% interest in cash flow attributable to the Operating ORRIs and a 4% interest in cash flow attributable to the properties formerly held by Republic and Spinnaker and (ii) own all of Dorchester Minerals Operating LP. Dorchester Minerals Operating LP will own 100% of the working interests in the properties formerly owned by the combining partnerships that will be burdened by the Operating ORRIs owned by our partnership. See "The Combination--Preparatory Steps--Creation of Overriding Royalty Interests." The amounts shown in the pro forma columns of the table represent the distributions that would have been received (i) by Dorchester Minerals Management LP multiplied by the 20.48% beneficial ownership interest (based on profits) of each of the general partners of Republic in Dorchester Minerals Management LP and (ii) by Dorchester Minerals Operating LP, after the deduction of the Operating ORRIs, multiplied by the 20.48% beneficial ownership interest (based on profits) of each of the general partners of Republic in Dorchester Minerals Management LP. The amounts shown in the actual columns of the table include all general partner compensation other than expense reimbursements. The amounts shown in the actual and pro forma columns do not include cash distributions with respect to limited partner interests held by a general partner.
(7) The general partners of Republic are also reimbursed for all actual general and administrative expenses incurred by them on behalf of Republic, subject to an overhead reimbursement limit of 4% of Republic's cash flow. General and administrative expenses incurred in connection with Dorchester Hugoton's operations are incurred for the most part directly by Dorchester Hugoton and paid directly by it instead of being incurred by its general partners and then reimbursed. The general partners of Republic and Spinnaker, however, incur directly all general and administrative and other overhead expenses and are reimbursed for these expenses by the partnerships in accordance with their respective partnership agreements. Dorchester Minerals will have no employees (other than officers), offices or other activities that directly generate general and administrative expenses. Instead those expenses will be incurred by its general partner and Dorchester Minerals Operating LP and then reimbursed by Dorchester Minerals to the general partner or Dorchester Minerals Operating LP. Accordingly, a comparison of actual and pro forma expenses reimbursed would result in an inconsistent presentation. In

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the table, as presented, actual expense reimbursements reflect actual amounts paid by the general partners of the combining partnerships and to which they are entitled to reimbursement in accordance with the partnership agreement of their respective combining partnership. Pro forma expense reimbursements reflect actual amounts that would have been paid by the partners of our general partner and reimbursement of those amounts in accordance with our general partner's partnership agreement. The actual amount of expense reimbursements differs from the percentage allocation of cash distributions (and production costs included in the determination of Operating ORRIs) because reimbursements are made to our general partner's partners in accordance with actual costs paid and without regard to the partners' interest in capital and profits.
(8) The general partner of Spinnaker is not entitled to receive a management fee.
(9) The general partner of Spinnaker holds a 4% general partner interest in Spinnaker assuming the Spinnaker reorganization has occurred. The general partner of Spinnaker will hold a 19.98% interest in profits and a 28.26% interest in capital in the general partner of our partnership, which will
(i) be entitled to receive a 1% interest in cash flow attributable to the Operating ORRIs and a 4% interest in cash flow attributable to the properties formerly held by Republic and Spinnaker and (ii) own all of Dorchester Minerals Operating LP. Dorchester Minerals Operating LP will own 100% of the working interests in the properties formerly owned by the combining partnerships that will be burdened by the Operating ORRIs owned by our partnership. See "The Combination--Preparatory Steps--Creation of Overriding Royalty Interests." The amounts shown in the pro forma columns of the table represent the distributions that would have been received (i) by Dorchester Minerals Management LP multiplied by the 19.98% beneficial ownership interest (based on profits) of the general partner of Spinnaker in Dorchester Minerals Management LP and (ii) by Dorchester Minerals Operating LP, after the deduction of the Operating ORRIs, multiplied by the 19.98% beneficial ownership interest (based on profits) of the general partner of Spinnaker in Dorchester Minerals Management LP. The amounts shown in the actual columns of the table include all general partner compensation other than expense reimbursements. The amounts shown in the actual and pro forma columns do not include cash distributions with respect to limited partner interests held by a general partner.
(10) The general partner of Spinnaker is also reimbursed for its actual and allocable general and administrative expenses attributable to Spinnaker's properties and business, subject to a limit of 5% of Spinnaker's cash flow excluding any salary for its executive officers and directors. General and administrative expenses incurred in connection with Dorchester Hugoton's operations are incurred for the most part directly by Dorchester Hugoton and paid directly by it instead of being incurred by its general partners and then reimbursed. The general partners of Republic and Spinnaker, however, incur directly all general and administrative and other overhead expenses and are reimbursed for these expenses by the partnerships in accordance with their respective partnership agreements. Dorchester Minerals will have no employees (other than officers), offices or other activities that directly generate general and administrative expenses. Instead those expenses will be incurred by its general partner and Dorchester Minerals Operating LP and then reimbursed by Dorchester Minerals to the general partner or Dorchester Minerals Operating LP. Accordingly, a comparison of actual and pro forma expenses reimbursed would result in an inconsistent presentation. In the table, as presented, actual expense reimbursements reflect actual amounts paid by the general partners of the combining partnerships and to which they are entitled to reimbursement in accordance with the partnership agreement of their respective combining partnership. Pro forma expense reimbursements reflect actual amounts that would have been paid by the partners of our general partner and reimbursement of those amounts in accordance with our general partner's partnership agreement. The actual amount of expense reimbursements differs from the percentage allocation of cash distributions (and production costs included in the determination of Operating ORRIs) because reimbursements are made to our general partner's partners in accordance with actual costs paid and without regard to the partners' interest in capital and profits.

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THE BUSINESS OPPORTUNITIES AGREEMENT

Renunciation of Business Opportunities

In a Business Opportunities Agreement among:

. our partnership;

. Dorchester Minerals Management LP;

. Dorchester Minerals Management GP LLC;

. the general partners of the combining partnerships, referred to in this section as the GP Parties; and

. in their individual capacities as officers of Dorchester Minerals Management GP LLC, William Casey McManemin, James E. Raley and H.C. Allen, Jr.

effective as of and conditioned upon the closing of the combination, we have agreed that following consummation of the combination, except with the consent of Dorchester Minerals Management LP, which it may withhold in its sole discretion, we will not engage in any business not permitted by the partnership agreement as in effect immediately upon the closing of the combination, and we will have no interest or expectancy in any business opportunity that does not consist exclusively of the Oil and Gas Business, as defined in the Business Opportunities Agreement, within a designated area that includes portions of Texas County, Oklahoma and Stevens County, Kansas. All opportunities which are outside the designated area or are not Oil and Gas Business activities are called renounced opportunities. For purposes of the agreement, "Oil and Gas Business" means the acquisition, management, ownership and sale of oil and natural gas assets or properties, including but not limited to mineral fee interests, net profits interests and royalty and overriding interests, but excluding working interests.

We also have agreed in the Business Opportunities Agreement that affiliates of Dorchester Minerals Management LP, the GP Parties and their affiliates and the persons designated by the GP Parties as managers of Dorchester Minerals Management GP LLC, whom we refer to in this section as the management committee designees, shall not be restricted by the relationship between us and Dorchester Minerals Management LP and/or Dorchester Minerals Operating LP or Dorchester Minerals Operating GP LLC from engaging in any business even though it is in competition with our business or activities, so long as their actions do not conflict with specified standards of conduct, which are summarized below, or is a renounced opportunity.

The parties also have agreed in the Business Opportunities Agreement that, as long as the activities of Dorchester Minerals Management LP, the GP Parties and their affiliates or management committee designees are conducted in accordance with the specified standards, which are summarized in the next paragraph, or are renounced opportunities:

. Dorchester Minerals Management LP, the GP Parties and their affiliates or the management committee designees will not be prohibited from engaging in the Oil and Gas Business or any other business, even if such activity is in direct or indirect competition with our business activities;

. affiliates of Dorchester Minerals Management LP, the GP Parties and their affiliates and the management committee designees will not have to offer us any business opportunity;

. we will have no interest or expectancy in any business opportunity pursued by affiliates of Dorchester Minerals Management LP, the GP Parties or their affiliates and the management committee designees; and

. we waive any claim that any business opportunity pursued by Dorchester Minerals Management LP, the GP Parties or their affiliates and the management committee designees constitutes a corporate opportunity of Dorchester Minerals that should have been presented to us.

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The standards specified in the Business Opportunities Agreement generally provide that the GP Parties and their affiliates and management committee designees must conduct their business through the use of their own personnel and assets and not with the use of any personnel or assets of us, Dorchester Minerals Management LP or Dorchester Minerals Operating LP. The Business Opportunities Agreement will not allow a management committee designee of Dorchester Minerals Management GP LLC or personnel of a company in which any affiliate of Dorchester Minerals Management LP or any GP Party or their affiliates has an interest or in which a management committee designee is an owner, director, manager, partner or employee (except for Dorchester Minerals Management GP LLC, Dorchester Minerals Management LP and their subsidiaries) to usurp a business opportunity solely for his or her personal benefit, as opposed to pursuing, for the benefit of the separate party an opportunity in accordance with the specified standards.

Contractual Obligations of Certain Affiliates

In addition to the renunciation of business opportunities and related matters described immediately above, the Business Opportunities Agreement contains two kinds of contractual undertakings by the GP Parties and by Messrs. McManemin, Raley and Allen: an obligation for the affiliate to offer us the opportunity to consummate specified types of transactions under binding agreement with the affiliate; and an obligation for the affiliate to offer us the opportunity to purchase from the affiliate specified types of properties in the designated area described above under " --Renunciation of Business Opportunities." These obligations do not alter our ability, under our Partnership Agreement, to take certain actions. In other words, in some situations the contractual undertakings in the business opportunities might give us an opportunity that we are prohibited from pursuing because of restrictions in our Partnership Agreement.

Offer of Right to Negotiate

The Business Opportunities Agreement provides that if a GP Party, an officer of Dorchester Minerals Management GP LLC or any of their subsidiaries signs a binding agreement to purchase oil and natural gas interests, excluding oil and natural gas working interests, and the purchase price for the oil and natural gas interests exceeds 10% of our market capitalization on the date of the purchase agreement, then the purchasing party must notify us prior to the consummation of the transactions so that we may determine whether to pursue the purchase of the oil and natural gas interests directly from the seller. If the purchase price to be paid is other than cash, our Advisory Committee will determine the value of the purchase price. If we elect to pursue the purchase of the oil and natural gas interests directly from the seller and seller notifies the purchasing party that seller desires to sell the oil and natural gas interests to us instead of the purchasing party, the purchasing party must take reasonable action to effect the termination of the purchase agreement between it and the seller, although the termination will be conditioned upon our entering into a binding purchase agreement with seller. The Advisory Committee will make any determination regarding whether we elect to pursue such an opportunity. If we do not pursue the purchase of the oil and natural gas interests or fail to respond to the purchasing party's notice within the provided time, the opportunity will also be considered a renounced opportunity.

Offer of Owned Properties

The agreement also provides that if any GP Party or one of their subsidiaries acquires an oil and natural gas interest, including oil and natural gas working interests, in the designated area, it will offer to sell these interests to us within one month of completing the acquisition. This obligation also applies to any package of oil and natural gas interests, including oil and natural gas working interests, if at least 20% of the net acreage of the package is within the designated area, but this obligation does not apply to interests purchased in a transaction in which the procedures described immediately above under "--Offer of Right to Negotiate" applied and were followed by the applicable affiliate. The interests required to be offered to us are referred to as restricted assets.

If we elect not to purchase any offered restricted assets, our Advisory Committee must approve that election. If we elect to purchase the restricted assets, the purchase price that we pay will be equal to the purchase

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price paid by the offering party for the interests. If the purchase price paid by the offering party was other than cash and we and the offering party cannot agree on the value of the purchase price, we and the offering party must appoint a mutually-agreed-upon appraiser to determine the value of the purchase price. We and the offering party must each pay one-half of the appraiser's fees and expenses. We may revoke our election to purchase the restricted assets within five days of receiving the appraisal, although we must pay all of the appraiser's fees and expenses in the event we revoke our election.

General

Contractual obligations in the Business Opportunities Agreement do not apply to (i) the ownership of our common units or (ii) securities of any class registered under the Securities Exchange Act of 1934 if, in the case of (ii), following the purchase the party owns less than 5% of such class of securities.

With respect to business opportunities that are presented to or become known to any person restricted by the Business Opportunities Agreement after the general partner is no longer our general partner, the restrictions imposed by the Business Opportunities Agreement on such any person terminate at the time that the general partner no longer serves as the general partner. The restrictions imposed by the Business Opportunities Agreement on any person terminate six months after the general partner no longer serves as our general partner with respect to all other matters.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth information regarding the beneficial ownership of our common units as of January 1, 2002 and the pro forma ownership of our common units after completion of the combination based on the estimated combination exchange ratios and assuming (a) 27,040,431 common units are issued in the combination, (b) no limited partners elect to exercise dissenters' rights, and (c) the consummation of the combination on that date. This information is set forth for (i) each nominee 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 nominee 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. Please note that the percentage of common units to be owned after the combination by a given holder does not entitle that holder to a like sharing percentage of our profits nor are the partnership interests attributable to the general partner interests included in the pro forma column of this table. See "The Combination--Ownership Structure of Dorchester Minerals" beginning on page 60 for a more detailed discussed of these matters.

                                                                               Pro Forma
                                                         Current               Estimated
                                                   Beneficial Ownership Beneficial Ownership(1)
                                                   -------------------- ----------------------
                                                        Percentage      Number of   Percentage
Name of Beneficial Owner                                 Of Total         Units     of Total(2)
------------------------                           -------------------- ---------   -----------
Dorchester Minerals Management, L.P...............           1%               N/A        N/A
Dorchester Minerals Management GP LLC.............          99%                --         --
Named Executive Officers and Nominee Managers(5):
   William Casey McManemin(4)(10).................         N/A          5,542,465      20.50%
   James E. Raley.................................         N/A             14,706       0.05%
   H.C. Allen, Jr.(5)(10).........................         N/A          1,634,714       6.05%
   Preston A. Peak(6)(10).........................         N/A          1,577,412       5.83%
   Robert C. Vaughn(7)(10)........................         N/A          1,695,992       6.27%
All executive officers and nominee managers as a
  group (5 persons)...............................         N/A          9,940,501      36.76%
Holders of 5% or More Not Named Above
   Lucent Technologies Master Pension Trust(8)(9).         N/A          4,241,293      15.69%
   Red Wolf Partners(9)...........................         N/A          3,781,934      13.99%
   AT&T Long Term Investment Trust(8)(9)..........         N/A          3,038,820      11.24%
   Delta Airlines Master Trust(8)(9)..............         N/A          2,061,951       7.63%
   Boeing Master Retirement Plans Trust(8)(9).....         N/A          1,886,609       6.98%
   Bell Atlantic Master Trust(8)(9)...............         N/A          1,886,609       6.98%
   Kodak Retirement Income Plan(8)(9).............         N/A          1,616,574       5.98%


(1) Based on estimated combination exchange ratios and assuming no limited partners elect to exercise dissenters' rights.
(2) Based on 27,040,431 common units.
(3) The business address of each manager and executive officer of Dorchester Minerals Management GP LLC is c/o Dorchester Minerals Management GP LLC, 3738 Oak Lawn Ave., Suite 300, Dallas, Texas 75219.
(4) Includes 5,542,465 common units owned by various entities of which Mr. McManemin is an officer, manager or general partner or for the benefit of Mr. McManemin and his family, although Mr. McManemin does not have an economic interest in all of these units. Mr. McManemin disclaims beneficial ownership of 599,726 common units to be owned upon consummation of the combination by SAM Partners, Ltd. and Smith Allen Oil & Gas, Inc. Mr. McManemin is Vice-President of Smith Allen Oil & Gas, Inc. and SAM Partners Management, Inc., the general partner of SAM Partners, Ltd. Mr. McManemin in this capacity may be deemed to beneficially own these units based on shared voting and dispositive power. Does not include 1,009,897 units that Mr. McManemin does not beneficially own, but in which may have an economic interest through the APO Partnership.

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(5) Mr. Allen disclaims beneficial ownership of 599,726 common units to be owned upon consummation of the combination by SAM Partners, Ltd. and Smith Allen Oil & Gas, Inc. Mr. Allen is Secretary of Smith Allen Oil & Gas, Inc. and SAM Partners Management, Inc., the general partner of SAM Partners, Ltd. Mr. Allen in this capacity may be deemed to beneficially own these units based on shared voting and dispositive power. Does not include 1,009,897 units that Mr. Allen does not beneficially own, but in which he may have an economic interest in through the APO Partnership.
(6) Includes 1,577,412 common units owned by various entities for the benefit of Mr. Peak and his family.
(7) Includes 674,903 units owned by various entities of which Mr. Vaughn is an officer, manager or general partner. Does not include 1,009,897 units that Mr. Vaughn does not beneficially own, but in which he may have an economic interest in through the APO Partnership.
(8) Includes 1,009,897 common units to be owned upon the consummation of the combination by the APO Partnership, which the holder may be deemed to beneficially own based on shared voting or dispositive power. (9) The business address of each party is c/o Republic Royalty Company, 3738 Oak Lawn, Suite 300, Dallas, Texas 75219.
(10) Includes 83,057 common units to be owned upon the consummation by RRC NPI Holdings, LP, whose co-general partners following the combination will be SAM Partners, Ltd. and Vaughn Petroleum, Ltd.

THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our Amended and Restated Agreement of Limited Partnership, referred to throughout this document as our Partnership Agreement or the Partnership Agreement. Our Partnership Agreement is included as an exhibit to the registration statement of which this document constitutes a part. We will provide you with a copy of this agreement upon request. For information on how this document may be obtained, see "Where You Can Find More Information" on the inside front cover page of this document.

We summarize the following provisions of the Partnership Agreement elsewhere in this prospectus:

. with regard to the transfer of common units, see "Description of Units of Dorchester Minerals--Transfer of Common Units;" and

. with regard to allocations of taxable income and taxable loss, see "Material United States Federal Income Tax Consequences--Consequences of Ownership of our Units After the Combination."

Organization

We were organized on December 12, 2001 and will have a perpetual existence.

Purpose

Our purpose under the Partnership Agreement is to acquire, manage, operate, and sell the assets now owned or hereafter acquired and to distribute all "available cash" to unitholders or partners according to their respective interests and to engage in business activities approved by the general partner. See "--Distributions of Available Cash" below for the definition of available cash.

Power of Attorney

Each limited partner, and each person who acquires a unit from a unitholder and executes and delivers a transfer application or is deemed to have done so, grants to the general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants the general partner the authority to amend, and to make consents and waivers under, the Partnership Agreement.

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Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under "--Limited Liability."

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the Partnership Agreement, his liability under the Delaware Act will be limited, subject to possible exceptions to the amount of capital he is obligated to contribute for his common units plus his share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by the limited partners as a group:

. to remove or replace the general partner;

. to approve some amendments to the Partnership Agreement; or

. to take other action under the Partnership Agreement;

constituted "participation in the control" of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as the general partner. This liability would extend to persons who transact business with us who reasonably believe that the limited partner is a general partner. Neither the Partnership Agreement nor the Delaware Act specifically provides for legal recourse against the general partner if a limited partner were to lose limited liability through the fault of the general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to the specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years Under the Delaware Act, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except the assignee is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the Partnership Agreement.

Issuance of Additional Securities

The Partnership Agreement authorizes us to issue an unlimited number of additional limited partner interests and other equity securities for the consideration and on the terms and conditions established by the general partner in its sole discretion without the approval of any limited partners. However, without the approval of the holders of a majority of the common units, we may not issue in a single transaction or series of related transactions any partnership securities representing limited partner interests if, after giving effect to such issuance, such newly issued partnership securities would represent over 20% of the outstanding limited partner interests.

It is possible that we will fund acquisitions through the issuance of additional common units or other equity securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional partnership interests may dilute the value of the interests of the then-existing holders of common units in our net assets.

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In accordance with Delaware law and the provisions of our Partnership Agreement, we may also issue additional partnership securities interests that, in the sole discretion of the general partner, have special voting rights to which the common units are not entitled.

The general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units or other equity securities whenever, and on the same terms that, we issue those securities to persons other than the general partner and its affiliates, to the extent necessary to maintain its percentage interest that existed immediately prior to each issuance. The holders of common units will not have preemptive rights to acquire additional common units or other partnership interests.

Distributions of Available Cash

We will distribute to our general partner and limited partners according to their respective interests, within 45 days of the end of each fiscal quarter, an amount equal to all "available cash" with respect to that quarter. Available cash means all cash and cash equivalents on hand at the end of that quarter, less any amount of cash reserves that our general partners determines is necessary or appropriate to provide for the conduct of our business or to comply with applicable law or agreements or obligations to which we are subject. Delaware law generally prohibits any distribution to partners if, after giving effect to the distribution, all liabilities of the partnership exceed the fair value of the assets of the partnership. In the event of a liquidation or dissolution of our partnership, available cash will be deemed to be zero in the quarter in which the events giving rise to the liquidation or dissolution occur and in subsequent quarters. Our general partner may treat taxes that we pay on behalf of, or amounts withheld with respect to, our general partner or limited partners as a distribution of available cash to those partners.

Amendment of the Partnership Agreement

General

Amendments to the Partnership Agreement may be proposed only by or with the consent of the general partner, which consent may be given or withheld in its sole discretion. In order to adopt a proposed amendment, other than the amendments discussed below, the general partner must seek written approval of the holders of the number of common units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as we describe below, an amendment must be approved by a majority of the common units, unless a greater or different percentage is required.

Prohibited Amendments

No amendment may be made that would:

. enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected;

. enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to the general partner or any of its affiliates without the consent of the general partner, which may be given or withheld in its sole discretion;

. change the term of our partnership;

. provide that our partnership is not dissolved upon an election to dissolve our partnership by the general partner that is approved by the holders of a majority of the outstanding common units; or

. give any person the right to dissolve our partnership other than the general partner's right to dissolve our partnership with the approval of the holders of a majority of the outstanding common units.

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The provision of the Partnership Agreement preventing the amendments having the effects described in the bullet points above can be amended upon the approval of the holders of at least 90% of the outstanding common units.

No Unitholder Approval

The general partner may generally make amendments to the Partnership Agreement without the approval of any limited partner or assignee to reflect:

. a change in our name, the location of our principal place of business, our registered agent or our registered office;

. the admission, substitution, withdrawal or removal of partners in accordance with the Partnership Agreement;

. a change that, in the sole discretion of the general partner, is necessary or advisable for us to qualify or to continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that the partnership will not be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

. an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees, from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or "plan asset" regulations adopted under the Employee Retirement Income Security Act of 1974, whether or not substantially similar to plan asset regulations currently applied or proposed;

. subject to the limitations on the issuance of additional common units or other limited or general partner interests described above, an amendment that in the discretion of the general partner is necessary or advisable for the authorization of additional limited or general partner interests;

. any amendment expressly permitted in the Partnership Agreement to be made by the general partner acting alone;

. an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of the Partnership Agreement;

. any amendment that, in the discretion of the general partner, is necessary or advisable for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by the Partnership Agreement;

. a change in our fiscal year or taxable year and related changes; and

. any other amendments substantially similar to any of the matters described in the immediately preceding bullet points above.

In addition, the general partner may make amendments to the Partnership Agreement without the approval of any limited partner or assignee if those amendments, in the discretion of the general partner:

(1) do not adversely affect the limited partners in any material respect;

(2) are necessary or advisable to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

(3) are necessary or advisable to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading, compliance with any of which the general partner deems to be in our best interest and the best interest of limited partners; or

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(4) are required to effect the intent expressed in this prospectus or the intent of the provisions of the Partnership Agreement or are otherwise contemplated by the Partnership Agreement.

Unitholder Approval

Any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a unit majority. Any amendment that reduces the voting percentage required to take action must be approved by the affirmative vote of limited partners constituting not less than the voting requirement sought to be reduced.

Merger, Sale or Disposition of Assets

The Partnership Agreement generally prohibits the general partner, without the prior approval of the holders of common units representing a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets of our subsidiaries. If conditions specified in the Partnership Agreement are satisfied, the general partner may merge us or any of our subsidiaries into, or convey some or all of our assets to, a newly formed entity if the sole purpose of that merger or conveyance is to change our legal form into another limited liability entity. The unitholders are not entitled to dissenters' rights of appraisal under the Partnership Agreement or applicable Delaware law in the event of a merger or consolidation, a sale of substantially all of our assets or any other transaction or event.

Termination and Dissolution

We will continue as a limited partnership until terminated under the Partnership Agreement. We will dissolve upon:

. the approval by the holders of common units representing a unit majority;

. the sale of all or substantially all of our assets and properties;

. the entry of a decree of judicial dissolution of us; or

. the withdrawal or removal of our general partner or any other event that results in its ceasing to be the general partner other than by reason of a transfer of its general partner interest in accordance with the Partnership Agreement or withdrawal or removal following approval and admission of a successor.

Upon a dissolution as described in the last bullet point above, the holders of common units representing a unit majority may also elect, within specific time limitations, to reconstitute us and continue our business on the same terms and conditions described in the Partnership Agreement by forming a new limited partnership on terms identical to those in the Partnership Agreement and having as general partner an entity approved by the holders of a majority of the outstanding common units, subject to our receipt of an opinion of counsel to the effect that (i) the action would not result in the loss of limited liability of any limited partner, and (ii) neither us or the reconstituted limited partnership would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.

Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are reconstituted and continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of the general partner that the liquidator deems necessary or desirable in its judgment, liquidate our assets. The liquidator will pay off or make provision for the discharge of our debts and liabilities. Liabilities to creditors will be paid off before liabilities to partners. After the discharge of all liabilities, the liquidator will distribute to our partners the excess property and cash, if

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any, in accordance with and to the extent of their respective capital accounts, as determined after taking into account all capital account adjustments. In addition, the liquidator may dispose of our assets by public or private sale or by distribution in kind. The liquidator may defer liquidation of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to the partners.

Withdrawal or Removal of the General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to December 31, 2010 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by the general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after December 31, 2010 our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days' written notice, and that withdrawal will not constitute a violation of the Partnership Agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days' notice to the limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates other than the general partner and its affiliates. In addition, the Partnership Agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. See "--Transfer of General Partner Interest" below. Upon the withdrawal of the general partner under any circumstances, other than as a result of a transfer by the general partner of all or a part of its general partner interest in us, the holders of a majority of the outstanding common units may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within 180 days after that withdrawal, the holders of a majority of the outstanding common units agree in writing to continue our business and to appoint a successor general partner. See"--Termination and Dissolution" below. The general partner may not be removed unless that removal is approved by the vote of the holders of a majority of the unitholders, including units held by the general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of the general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units. The ownership of more than 50% of the outstanding common units by the general partner and its affiliates would give it the practical ability to prevent its removal. At the closing of this offering, affiliates of the general partner will own 29.2% of the outstanding common units.

The Partnership Agreement also provides that if the general partner is removed as our general partner where cause does not exist and common units held by the general partner and its affiliates are not voted in favor of that removal, the general partner will have the right to require its successor to purchase its general partner interest and either (i) purchase all of the equity interests of Dorchester Minerals Operating LP or (ii) purchase all of the assets of the Dorchester Minerals Operating LP and assume all of its liabilities in exchange for an amount equal to the fair market value of those interests.

In the event of removal of a general partner under circumstances where cause exists or withdrawal of a general partner where that withdrawal violates the Partnership Agreement, a successor general partner will have the option to purchase the general partner interest and either (i) all of the equity interests of Dorchester Minerals Operating LP or (ii) all of the assets of Dorchester Minerals Operating LP and assume all of its liabilities of the departing general partner for a payment equal to the fair market value of those interests.

In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

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If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner's general partner interests will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph. In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Interest

Except for transfer by our general partner of all, but not less than all, of its general partner interest in us to:

. an affiliate of the general partner, or

. another person as part of the merger or consolidation of the general partner with or into another person or the transfer by the general partner of all or substantially all of its assets to another person,

our general partner may not transfer all or any part of its general partner interest in us to another person prior to December 31, 2010 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by the general partner and its affiliates. As a condition of this transfer, the transferee must assume the rights and duties of the general partner to whose interest that transferee has succeeded, agree to be bound by the provisions of the Partnership Agreement, furnish an opinion of counsel regarding limited liability and tax matters, agree to purchase all or the appropriate portion thereof, if applicable, of the partnership interest of the general partner as the general partner of our partnership and the general partner sells to the transferee either (i) all of the equity interests in Dorchester Minerals Operating LP or (ii) all of the assets of Dorchester Minerals Operating LP, such price for the equity interests and/or the assets of Dorchester Minerals Operating LP shall be the fair market value. The general partner and its affiliates may at any time, however, transfer common units to one or more persons, without unitholder approval. At any time, the members of the general partner may sell or transfer all or part of their membership interests in the general partner to an affiliate without the approval of the unitholders.

Change of Management Provisions

The Partnership Agreement contains specific provisions that are intended to discourage a person or group from attempting to remove our general partner or otherwise change management. Without approval of a majority of the unitholders, the partnership shall not issue in a single transaction or series of related transactions partnership securities representing limited partner interests, if, immediately after giving effect to such issuance, such newly issued partnership securities would represent over of 20% of the outstanding limited partner interests. If any person or group other than the general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner.

Members; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, unitholders or assignees who are record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. Common units that are owned by an assignee who is a record holder, but who has not yet been admitted as a limited partner, will be voted by the general partner at the written direction of the record holder. Absent direction of this kind, the common units will not be voted, except that, in the case of common units held by the general partner on behalf of non-citizen assignees, the general partner will distribute the votes on those common units in the same ratios as the votes of limited partners on other units are cast.

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The general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units as would be necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by the general partner or by unitholders owning at least 50% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, but not including partnership interests deemed held by the general partner on behalf of assignees for which written instructions have not been received by the general partner, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. See "--Issuance of Additional Securities" above. However, if at any time any person or group, other than the general partner and its affiliates, or a direct or subsequently approved transferee of the general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under the Partnership Agreement will be delivered to the record holder by us or by the transfer agent.

Status of Limited Partner or Assignee

Except as described above under "--Limited Liability," the common units will be fully paid, and unitholders will not be required to make additional contributions. An assignee of a common unit, after executing and delivering a transfer application, or being deemed to have done so, but pending its admission as a substituted limited partner, is entitled to an interest equivalent to that of a limited partner for the right to share in allocations and distributions from us, including liquidating distributions. The general partner will vote and exercise other powers attributable to common units owned by an assignee or deemed assignee that has not become a substitute limited partner at the written direction of the assignee. See "--Members; Voting" above. Transferees that do not execute and deliver a transfer application, or who are not otherwise deemed to have done so, will be treated neither as assignees nor as record holders of common units, and will not receive cash distributions, federal income tax allocations or reports furnished to holders of common units. See "Description of the Common Units--Transfer of Common Units."

Non-Citizen Assignees; Redemption

If we are or become subject to federal, state or local laws or regulations that, in the reasonable determination of the general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner or assignee, we may redeem the common units held by the limited partner or assignee at their current market price. In order to avoid any cancellation or forfeiture, the general partner may require each limited partner or assignee to furnish information about his nationality, citizenship or related status. If a limited partner or assignee fails to furnish information about this nationality, citizenship or other related status within 30 days after a request for the information or the general partner determines after receipt of the information that the limited partner or assignee

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is not an eligible citizen, the limited partner or assignee may be treated as a non-citizen assignee. In addition to other limitations on the rights of an assignee that is not a substituted limited partner, a non-citizen assignee does not have the right to direct the voting of his common units and may not receive distributions in kind upon our liquidation.

Indemnification

Under the Partnership Agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

. the general partner;

. any departing general partner;

. any person who is or was an affiliate of a general partner or any departing general partner;

. any person who is or was a member, partner, officer, director, employee, agent or trustee of the general partner or any departing general partner or any affiliate of a general partner or any departing general partner; or

. any person who is or was serving at the request of a general partner or any departing general partner or any affiliate of a general partner or any departing general partner as an officer, director, employee, member, partner, agent or trustee of another person.

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees in its sole discretion, the general partner will not be personally liable for, or have any obligation to contribute or loan funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under the Partnership Agreement.

Books and Reports

The general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and financial reporting purposes, our fiscal year is the calendar year. We will furnish or make available to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter. We will furnish each record holder of a unit with information reasonably required for federal tax reporting purposes within 90 days after the close of each calendar year.

Right to Inspect Books and Records

The Partnership Agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable demand and at his own expense, have furnished to him:

. a current list of the name and last known address of each partner;

. a copy of our tax returns;

. information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each became a partner;

. copies of the Partnership Agreement, the certificate of limited partnership of the partnership, related amendments and powers of attorney under which they have been executed;

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. information regarding the status of our business and financial condition; and

. any other information regarding our affairs as is just and reasonable.

The general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which the general partner believes in good faith is not in our best interests or which we are required by law or by agreements with third parties to keep confidential.

Registration Rights

Under our Partnership Agreement, the general partner and its affiliates have the right to cause us to register under the Securities Act of 1933 and state laws the offer and sale of any units that they hold if an exemption from the registration rights is not otherwise available. See "The Combination Agreement--Resales of Common Units."

Subject to the terms and conditions of our Partnership Agreement, these registration rights allow the general partner and its affiliates or their assignees holding any common units to require registration of any of these units and to include any of these units in a registration by us of other units, including units offered by us or by any unitholder. The general partner will continue to have these registration rights for two years following its withdrawal or removal as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act of 1933 or any state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and commissions. Except as described below, the general partner and its affiliates may sell their units in private transactions at any time, subject to compliance with applicable laws.

Each of the general partners of the combining partnerships, each manager of Dorchester Minerals Management LP and each officer of Dorchester Minerals Operating LP and their affiliates have agreed not to sell any common units they beneficially own for a period of one year from the date of closing of the combination.

COMPARISON OF RIGHTS OF PARTNERS

The rights of our limited partners will be governed by the Delaware Revised Uniform Limited Partnership Act, which is referred to as the Delaware Act, and our Partnership Agreement. The rights of the limited partners of Dorchester Hugoton and Spinnaker are each currently governed by the Texas Revised Limited Partnership Act, which is referred to as the Texas Act, and the respective partnership agreement of each of Dorchester Hugoton and Spinnaker. The rights of the partners of Republic are currently governed by the Texas Revised Partnership Act and the partnership agreement of Republic, although it is expected that, prior to the consummation of the combination, Republic will reorganize as a Texas limited partnership, making it subject to the Texas Act and a new agreement of limited partnership. Accordingly, on completion of the combination, the rights of our limited partners, and of the limited partners of the combining partnerships who become limited partners of our partnership in the combination, will be governed by the Delaware Act and our Partnership Agreement. The following is a summary of the material differences between the rights of our limited partners the rights of the limited partners of Dorchester Hugoton and Spinnaker. However, we have not included information with respect to Republic in this section because the Republic ORRI owners that become limited partners of Republic as a result of the Republic reorganization will only have rights as limited partners for a brief period of time and then only if the combination is approved and consummated.

The following summary of the material differences between the Delaware Act, our Partnership Agreement, the Texas Act and the partnership agreements of each of Dorchester Hugoton and Spinnaker may not contain all the information that is important to you. To review all provisions of and differences among these partnership agreements in full detail, please read the full text of these documents, the Delaware Act and the Texas Act.

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Copies of the our certificate of limited partnership and Partnership Agreement, and the partnership agreement for each combining partnership in which you own an interest will be sent to you upon request. For information on how these documents may be obtained, see "Where You Can Find More Information" on the inside front cover page of this document.

               COMBINING PARTNERSHIPS                                  DORCHESTER MINERALS
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                                               Distributions
-------------------------------------------------------------------------------------------------------------

The Dorchester Hugoton partnership agreement          Our Partnership Agreement provides that cash and
provides that distributions will be determined by     cash equivalent distributions will be determined by
the general partners at least as of the end of each   the general partner at the end of each quarter.
calendar quarter and more frequently if the general
partners deem it appropriate.

The Spinnaker partnership agreement provides that
cash distributions will be determined by the general
partner monthly. The general partner may also
distribute certain oil and natural gas interests if
deemed desirable.
------------------------------------------------------------------------------------------------------------

The frequency of distributions will be the same as those made by Dorchester Hugoton, but less frequent than
those made by Spinnaker. The amount of distributions payable with respect to the partnership interests of
the combining partnerships depends upon the performance of the partnerships, which will continue to be the
case for our partnership.
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                                     Dissolution and Liquidation Rights
-------------------------------------------------------------------------------------------------------------

In the event of winding up, dissolution and           The provisions of our Partnership Agreement with
liquidation, the partnership agreements provide for   respect to winding up, dissolution and liquidation
the appointment of a liquidator, who generally will   are substantially similar to the partnership
be the general partner. The liquidator will pay off   agreements of the combining partnerships. In
or make provision for the discharge of the debts      addition, the liquidator has discretion to dispose of
and liabilities of the partnerships. Liabilities to   assets by public or private sale or by distribution in
creditors will be paid off before liabilities to      kind. The liquidator may also defer liquidation or
partners. After the discharge of all liabilities, the distribution for a reasonable period of time it if
excess property and cash, if any, will be distributed determines that an immediate sale or distribution of
to the partners in accordance with and to the extent  all or some of the assets would be impractical or
of the positive balances in their respective capital  cause undue loss to the partners.
accounts, as determined after taking into account
all capital account adjustments. All distributions
must be made by either the end of the current
taxable year or within 90 days of the date of the
liquidation.
------------------------------------------------------------------------------------------------------------

The liquidation rights of the limited partners in our partnership will be substantially the same as the
liquidation rights of the limited partners of the combining partnerships.

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                                                 Voting Rights
----------------------------------------------------------------------------------------------------------------

The Dorchester Hugoton partnership agreement           Our Partnership Agreement generally provides that
provides that the holders of 50% of the depositary     the holders of a majority of the common units be
receipts must be present to constitute a quorum at a   present to constitute a quorum at a meeting.
meeting. The favorable vote of more than 80% of        However, if any action by the limited partners
the holders of the depositary receipts is required for requires approval by holders of a greater
the dissolution of the partnership, removal of the     percentage, the quorum must be that greater
general partner and the approval or rejection of the   percentage. Our Partnership Agreement provides
sale of all or substantially all of the partnership's  that the favorable vote of the holders of at least a
real property. However, if the general partners        majority of the common units is required to
approve or recommend the sale, the limited             approve (i) the dissolution of the partnership, (ii)
partners no longer have this voting right. The         the sale, exchange or disposition of all or
partnership agreement does not permit the merger       substantially all of the partnership's assets, (iii) the
of Dorchester Hugoton. The favorable vote of the       election of a successor general partner, (iv) the
holders of more than 50% of the depositary receipts    acquisition of certain oil and gas interests or (v) the
is required to (i) disapprove the selection of a       issuance of limited partnership interests, if after
successor general partner by the remaining general     giving effect to such issuance, those newly issued
partner(s) after the withdrawal of a general partner,  limited partnership interests would represent over
(ii) approve certain transactions with the general     20% of the outstanding limited partnership
partners or their affiliates, including unwritten      interests.
transactions, sale or leases of property and loans,
(iii) expand the partnership's business outside the
Hugoton area, (iv) approve the expansion of
liability of limited partners, or (v) approve
transactions that provide a creditor of the
partnership an interest other than as a secured
creditor.

The Spinnaker partnership agreement provides that
the favorable vote of the holders of at least
85.9883% of the sharing percentages of the limited
partners is required to (i) make certain borrowings,
mortgages, pledges, assignments and guarantees,
(ii) sell certain oil and natural gas interests, (iii)
make advance payments to the general partner, (iv)
bind or obligate the partnership with respect to
matters outside its scope of business, (v) merge or
consolidate or exchange interests subject to limited
partner approval, or (vi) make expenditures or
settle controversies in excess of $50,000, in
addition to certain other restrictions.
---------------------------------------------------------------------------------------------------------------

The partnership actions requiring approval by the limited partners are similar to the partnership actions
requiring approval by the limited partners of the combining partnerships. However, the percentage of votes
of approval required by our partnership agreement is substantially less than the percentage of votes of
approval required by the combining partnerships' agreements. Further, because the former limited partners
of the combining partnerships will hold a smaller percentage interest in our partnership than they did in their
respective partnerships, the former limited partners will experience a corresponding decrease in their
relative voting power once they become common unitholders in our partnership.
----------------------------------------------------------------------------------------------------------------

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                                     Amendments to Partnership Agreements
----------------------------------------------------------------------------------------------------------------

The Dorchester Hugoton partnership agreement           Our Partnership Agreement allows the general
allows amendments to be proposed by holders of         partner to make amendments without the approval
more than 50% of the depositary receipts. The          of the limited partners at any time, if those
Dorchester Hugoton partnership agreement               amendments do not adversely affect the rights of
provides that amendments must be approved by the       the limited partners in any material respect. All
holders of more than 80% of the depositary             other amendments may be proposed only by or
receipts.                                              with the consent of the general partner, which
                                                       consent may be given or withheld in its sole
The Spinnaker partnership agreement provides that      discretion. Except in certain circumstances,
amendments must be approved by at least                amendments must be approved by the holders of a
85.9883% of the sharing percentages. The general       majority of the common units.
partners of either partnership may make
amendments without the approval of the limited
partners at any time, if those amendments do not
adversely affect the rights of the limited partners in
any material respect. The written agreement of all
partners is necessary to approve amendments with
respect to allocations and distributions under both
partnership agreements. However, if such an
amendment treats all partners the same, the
Spinnaker partnership agreement only requires
approval of at least 85.9883% of the sharing
percentages.
---------------------------------------------------------------------------------------------------------------

With the exception of our general partner's ability to disallow proposal of amendments and the reduced
approval percentage for amendments, the ability of the limited partners to amend the partnership agreement
will be similar to the ability of the limited partners to amend the partnership agreements of the combining
partnerships.
----------------------------------------------------------------------------------------------------------------

                                   Withdrawal or Removal of General Partner
----------------------------------------------------------------------------------------------------------------

The Dorchester Hugoton partnership agreement           With limited exceptions, our Partnership
provides that the general partner may withdraw at      Agreement provides that the general partner will
any time and may be removed by the favorable           not withdraw voluntarily on or before December
vote of more than 80% of the holders of depositary     31, 2010. Similar provisions restrict certain
receipts at any time. Such withdrawal will cause       transfers of all of the general partner's interest prior
the dissolution of the partnership unless the          to December 31, 2010. After December 31, 2010,
remaining general partners elect to continue the       the general partner may withdraw only upon 90
partnership and elect a successor general partner(s).  days notice to the limited partners.
The limited partners must ratify the election of the
successor general partner to continue the              The general partner may not be removed except
partnership. If the holders of more than 50% of the    upon approval and selection of a successor general
depositary receipts disapprove of the successor        partner by holders of a majority of the common
general partner(s), the remaining general partner      units (including common units owned by the
may select one or more successors, subject to the      general partner and its affiliates), subject to the
limited partners' ratification right.                  satisfaction of certain conditions. Upon withdrawal
                                                       in accordance with our Partnership Agreement or
The Spinnaker partnership agreement provides that      removal without cause, the general partner will
the general partner may withdraw at any time or be     have the option to require the successor to purchase

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removed and its successor  its general partner
may be elected by the      interest and purchase
favorable vote of the      Dorchester Minerals
limited partners holding   Operating LP or all its
greater than 50% of the    assets with an assumption
sharing percentages. The   of liabilities for fair
removal is effective only  market value. If the
if and when a successor    general partner withdraws
is elected and agrees in   in violation of the
writing to accept the      partnership agreement or
responsibilities under     is removed for cause,
the partnership            then the successor
agreement. Upon            general partner shall
withdrawal, all of the     have the option to
limited partners may.      purchase the general
appoint a successor        partnership interest and
general partner and        the interest in
reconstitute the           Dorchester Minerals
partnership. Upon          Operating LP for fair
removal, the removed       market value. If the
general partner will       general partnership
continue as a limited      interest of the
partner and no winding up  withdrawing or removed
of the partnership will    general partner is not
occur as a result of the   purchased, then it will
removal and replacement.   be converted into a
                           limited partnership
                           interest having the same
                           value as determined by an
                           independent expert.
----------------------------------------------------

Our general partner has a limited ability to withdraw from our partnership prior to December 21, 2010. Our limited partners may remove our general partner with the same percentage of limited partner approval as required by the Spinnaker partnership agreement, although the percentage approval required is lower than that required to remove a Dorchester Hugoton general partner under its partnership agreement. In addition, our general partner may have or be subject to certain repurchase rights following withdrawal or removal that do not apply to the general partners of the combining partnerships.

              Continuity of Existence
------------------------------------------------------

The Dorchester Hugoton     Our Partnership Agreement
partnership agreement      provides for the
provides for the           dissolution of the
dissolution of the         partnership upon the
partnership upon the       earliest to occur of (i)
earliest to occur of (i)   the sale of all or
the failure of the         substantially all of the
partnership to own any     assets and properties of
oil and natural gas        the partnership, (ii) an
properties, (ii) the       event of withdrawal of
withdrawal of the general  the general partner,
partner (subject to        unless a successor is
potential                  elected and other
reconstitution), (iii)     conditions satisfied,
the agreement of the       (iii) the agreement of
holders of more than 80%   the holders of a majority
of the depositary          of the common units or
receipts or (iv) the       (iv) the entry of a
agreement of all general   decree of judicial
partners or December 31,   dissolution of the
2050.                      partnership pursuant to
                           the provisions of the
The Spinnaker partnership  Delaware Act.
agreement provides for
the dissolution of the
partnership upon the
earliest to occur of (i)
the sale or disposition
of all or substantially
all of its assets, (ii)
the withdrawal of the
general partner (subject
to potential
reconstitution), (iii)
the consent of the
general partner and
limited partners holding
greater than 50% of the
sharing percentages, (iv)
the occurrence of an
event which causes the
dissolution of a limited
partnership under the
Texas Act or (v) March
31, 2046.
----------------------------------------------------

Since our partnership has a perpetual term of existence, holders of the common units have more of an opportunity to share in any future growth of our partnership beyond the dates on which the respective partnerships would have terminated.

172

Limited Liability of Limited Partners

The Dorchester Hugoton     Our Partnership Agreement
and Spinnaker partnership  provides that the limited
agreements provide that    partners will have no
limited partners will      liability under the
have no liability under    partnership agreement
the partnership agreement  except to the extent that
except to the extent that  a limited partner is also
a limited partner is also  a general partner or
a general partner or       participates in the
participates in the        control of our
control of the             partnership. Our
partnership. The           Partnership Agreement
partnership agreements     contains provisions
provide that no limited    substantially similar to
partner shall have any     the provisions to the
right, power or authority  Dorchester Hugoton and
to take part in the        Spinnaker partnership
management or control of   agreements regarding the
the business or bind the   inability of the limited
partnership. In addition,  partners to participate
the Spinnaker partnership  in the control of our
agreement provides that    partnership.
limited partners will not
be liable to the
partnership or other
partners for any act or
omission that does not
constitute gross
negligence or willful
misconduct. The
Dorchester Hugoton and
Spinnaker partnership
agreements also provide
for indemnification of
the limited partners to
the extent permitted
under the Texas Act.
-----------------------------------------------------

The limitation on personal liability of the limited partners of our partnership will be substantially similar to the limitations provided for in Dorchester Hugoton's partnership agreement, but will include fewer limitations than are applicable to limited partners of Spinnaker.

                  Fiduciary Duties
------------------------------------------------------

The fiduciary duties the   The fiduciary duties the
general partners of        general partner owes the
Dorchester Hugoton and     limited partners include
Spinnaker owe the limited  loyalty, care and good
partners include loyalty,  faith. It shall not be
care and good faith. The   deemed a breach of any
Spinnaker partnership      fiduciary duty for the
agreement limits the       general partner to engage
general partner's duty of  in certain business
loyalty by providing that  interests and activities
the scope of Spinnaker's   in preference to or to
business operations is     the exclusion of the
limited to the oil and     partnership. The general
natural gas properties     partner has no obligation
acquired in connection     to present business
with the partnership's     opportunities to the
formation and those that   partnership, provided
may be acquired in         that the general partner
accordance with the        does not engage in
partnership agreement.     business activities in
The general partner of     preference to or to the
Spinnaker has no           exclusion of the
obligation to present      partnership with respect
business opportunities to  to the business
the partnership.           opportunities. However,
                           the general partners of
                           the combining
                           partnerships, who will be
                           the members of Dorchester
                           Minerals GP LLC, and
                           Messrs. McManemin, Allen
                           and Raley are
                           contractually obligated
                           to present certain
                           business opportunities to
                           us pursuant to the
                           Business Opportunities
                           Agreement. The general
                           partner can resolve in
                           conflict of interest that
                           may arise and such
                           resolution will not
                           constitute a breach of
                           the partnership agreement
                           or any fiduciary duty if
                           the resolution is fair
                           and reasonable to the
                           partnership.
-----------------------------------------------------

The fiduciary duties owed to the limited partners by the general partner of our partnership are similar to the fiduciary duties owed to the limited partners of Spinnaker, but are less stringent than the fiduciary duties owed to the limited partners of Dorchester Hugoton.

173

Anti-Takeover Provisions

The Dorchester Hugoton Our Partnership Agreement and Spinnaker partnership provides that for any agreements contain no person or group anti-takeover provisions. beneficially owning more However, a super majority than 20% of any class of vote would be required to securities then

remove a Dorchester       outstanding, all
Hugoton general partner   partnership securities
or to amend the           owned by that person or
Dorchester Hugoton or     group will not be
Spinnaker partnership     eligible to be voted on
agreements. See           any matter and will not
"--Withdrawal or Removal  be considered to be
of General Partner" and   outstanding. This
"--Amendments to          anti-takeover measure
Partnership Agreements"   will not apply to any
in this table. Either of  person or group acquiring
these provisions could    such securities from (i)
have a similar effect to  the general partner or
an anti-takeover          its affiliates or (ii)
provision.                any person or group
                          acquiring such securities
                          from a person or group
                          described in (i), or
                          (iii) any person or group
                          acquiring such securities
                          in a transaction approved
                          by the unitholders,
                          provided that the general
                          partner notifies the
                          person or group in
                          writing that the
                          limitation will not apply.
----------------------------------------------------

The unitholders of our partnership are subject to anti-takeover provisions in the Partnership Agreement, which the limited partners were not subject to in the combining partnerships. These anti-takeover provisions could work to delay or frustrate the assumption of control of our partnership.

United States Income Tax

Dorchester Hugoton and Dorchester Minerals will Spinnaker are not subject not be subject to federal

to federal or state       or state income taxes.
income taxes. Each of     Each unitholder will be
their partners is         allocated a pro rata
allocated a pro rata      share of the
share of their respective partnership's taxable
partnerships' taxable     income, gains, losses,
income, gains, losses,    and deductions,
and deductions,           regardless of whether
regardless of whether     they receive cash
they receive cash         distributions. However,
distributions. The        certain Built-in Gain and
taxable income, gains,    Built-in Loss of
losses and deductions     properties transferred to
allocated to these        Dorchester Minerals will
partners must be included be specially allocated to
on their individual       the former partners of
federal and state income  the partnerships that
tax returns.              contributed such
                          properties. In
                          particular, the adjusted
                          tax basis of oil and
                          natural gas properties
                          contributed to Dorchester
                          Minerals by the combining
                          partnerships will be
                          allocated to the partners
                          of the contributing
                          partnerships for the
                          purpose of separately
                          determining depletion
                          deductions, and any gain
                          or loss recognized by
                          Dorchester Minerals on
                          the disposition of the
                          contributed property will
                          be allocated to the
                          partners of the
                          contributing partnerships
                          to the extent of the
                          Built-in Gain and
                          Built-in Loss.
----------------------------------------------------

The federal income tax consequences of a unitholder of Dorchester Minerals will be similar to the tax consequences to the limited partners of Spinnaker and Dorchester Hugoton. However, each partner will share in the income, gains, losses and deductions of a larger pool of assets and special allocations may be made to contributing partners to allocate existing gains and losses in the contributed property to the contributing partner.

174

                 Operating Strategy
-------------------------------------------------------

The purpose of Dorchester   The purpose of our
Hugoton is to own, hold,    partnership is to
explore, develop and        acquire, manage, operate,
operate the properties      and sell the assets
acquired pursuant to the    conveyed to it in the
partnership agreement and   combination (and any
to do all things            similar assets or
necessary, appropriate or   properties acquired by
incidental to this end,     it) and to distribute all
although its ability to     available cash to the
acquire additional          partners according to
properties is limited.      their respective
The purpose of Spinnaker    percentage interests and
is to invest in, acquire,   engage in any other
own, develop, lease,        business activities the
sublease, farm out,         general partner approves.
operate, manage, exchange   Our partnership is
or otherwise dispose of     subject to some
its oil and natural gas     restrictions on the
properties and to do all    methods of financing our
things necessary,           activities. Without the
appropriate or incidental   approval of the holders
to this end.                of a majority of our
                            common units, we may not
                            issue additional
                            partnership securities if
                            such newly issued
                            securities would
                            represent over 20% of our
                            outstanding limited
                            partner interests
                            immediately after giving
                            effect to such issuance.
------------------------------------------------------

The basic operating strategy of our partnership will be substantially similar to the operating strategies of the partnerships, although acquisitions of additional properties are permitted and contemplated by our partnership agreement. However, our partnership's oil and natural gas interests will be substantially larger and more diversified than either of the combining partnership's oil and natural gas interests.

                     Management
-------------------------------------------------------

The partnership             Our Partnership Agreement
agreements of Dorchester    is similar to the
Hugoton and Spinnaker       partnership agreements of
provide that, except in     the combining
certain circumstances,      partnerships, but
the general partners have   requires limited partner
all management power over   approval of fewer actions
the partnerships'           than the Spinnaker
business and affairs,       partnership agreement.
subject to certain voting
rights of Spinnaker's
limited partners
described in "Voting
Rights".
------------------------------------------------------

The limited partners of the combining partnerships have similar rights with respect to the management of the partnership as the limited partners of our partnership, except that limited partners of Spinnaker will have the right to approve fewer actions by our general partner.

Compensation and Expense Reimbursement

The Dorchester Hugoton      Our Partnership Agreement
and Spinnaker partnership   provides that the general
agreements provide that     partner will be
the general partners will   reimbursed for all costs
be reimbursed for all       and expenses incurred on
costs and expenses          behalf of the
incurred on behalf of the   partnership, however, the
partnerships.               general partner will not
                            be compensated for its
The Dorchester Hugoton      services to the
partnership agreement       partnership, with certain
provides that the general   exceptions. With certain
partners are entitled to    exceptions, the
receive reasonable          reimbursement for these
compensation from the       expenses during any
partnership in an annual    fiscal year shall not
aggregate amount equal to   exceed 5% of the
$350,000 plus one percent   partnership's adjusted
(1%) of annual gross        distribution amount. Our
income, or a lesser         Partnership Agreement
amount as the general       also provides that no
partners may from time to   officer of the
time determine              partnership will be
appropriate. The            compensated for serving
                            as an officer or employee
                            of the partnership, but
                            such

175

compensation payable to    persons may hold
the general partners is    positions with the
to be divided among the    general partner or its
general partners equally   affiliates and may be
or as they may otherwise   compensated for that
mutually agree.            position and that
                           compensation may be
The Spinnaker general      reimbursed by the
partnership agreement      partnership.
provides that the general
partner's reimbursement
of expenses shall not
exceed 5% of the net
operating cash flow for
the fiscal year. The
general partner may be
reimbursed for all
expenses incurred by it
for activities outside
the scope of its normal
activities as general
partner if approved by
the limited partners
holding at least 85.9883%
of the sharing
percentages. The general
partner will not receive
any management fee or
other compensation for
its services unless
approved by the limited
partners holding at least
85.9883% of the sharing
percentages.
-----------------------------------------------------

The compensation of our general partner will be substantially similar to the compensation of the general partner of Spinnaker, but will differ from the compensation of the general partners of Dorchester Hugoton because we will not pay a management fee in addition to the reimbursement of expenses.

                Financial Reporting
------------------------------------------------------

Dorchester Hugoton is      Our partnership will be
subject to the reporting   subject to the reporting
requirements of the        requirements of the
Securities Exchange Act    Securities Exchange Act
and files periodic         and will be required to
reports with the SEC,      file periodic reports
copies of which are        with the SEC, copies of
available to holders of    which will be made
its depositary receipts.   available to holders of
                           our common units.
The limited partners of
Spinnaker are entitled to
receive quarterly and
annual financial
statements and an annual
engineering report with
respect to Spinnaker's
oil and gas reserves.
-----------------------------------------------------

Holders of our common units will receive substantially the same information in periodic financial reports than they currently receive as limited partners of Dorchester Hugoton or Spinnaker.

Limitations on Liability of Management

The Dorchester Hugoton     Our Partnership Agreement
and Spinnaker partnership  is substantially similar
agreements provide that    to the Dorchester Hugoton
the general partner will   and Spinnaker partnership
not be liable to the       agreements.
partnership for acts or
omissions that do not
constitute gross
negligence or willful
misconduct. Both
partnership agreements
provide for
indemnification of the
general partner.
-----------------------------------------------------

The limitation on liability of management of our partnership will be substantially the same as the limitation on liability of management of Dorchester Hugoton and Spinnaker.

176

Liquidity, Marketability and Restrictions on Transfer

Dorchester Hugoton's        Our common units will be
depository receipts are     traded on the Nasdaq
traded on the Nasdaq        National Market System
National Market System      under the symbol "DMLP"
under the symbol "DHULZ".   and will generally be
The depository receipts     freely tradable. However,
are freely transferable.    to become a substitute
Record holders of           limited partner of our
depository receipts may     partnership, a transferee
become a substituted        of common units must
limited partner upon        execute a transfer
the satisfaction of         application and be
certain conditions. A       admitted as a substitute
limited partner's           limited partner by our
interest may be             general partner. Our
transferred, however,       general partner may not
such transfer may not       transfer any part of its
confer the right to         general partner interest
become a substituted        in our partnership prior
limited partner. Certain    to December 31, 2010
conditions must be          without approval of the
satisfied prior to such     holders of a majority of
transferee becoming a       our common units
limited partner. The        (including common units
general partner's           held by the general
interest may only be        partner and its
transferred with the        affiliates.)
consent of the other
general partners, except
in certain circumstances.

There is no established
trading market for the
Spinnaker limited
partnership interests.
Spinnaker's partnership
agreement does not allow
transfer of limited
partner interests without
the consent by the
limited partners holding
greater than 50% of the
sharing percentages.
However, if such transfer
is permitted, the
transferee automatically
becomes a limited
partner. Spinnaker's
general partner may not
transfer any part of its
general partner interest
without approval of at
least 85.9883% of the
sharing percentages.
------------------------------------------------------

Because our common units will traded on the Nasdaq National Market System, our limited partners will have substantially more liquidity than the limited partners of Spinnaker. Because our common units will also be traded on the Nasdaq National Market System, the liquidity of our common units should be similar to the liquidity of Dorchester Hugoton's depositary receipts.

Inspection of Books and Records

The Dorchester Hugoton      Our Partnership Agreement
and Spinnaker partnership   is similar to the
agreements require the      Dorchester Hugoton and
books and records to be     Spinnaker partnership
maintained at the           agreements.
principal place of
business for inspection
and copying at the
expense of the limited
partner. The Dorchester
Hugoton Depositary
Agreement requires that
the list of depositary
receipt holders of record
be open for inspection as
long as such inspection
is not for the purpose of
communicating with
holders in the interest
of a business other than
the partnership business.
------------------------------------------------------

The rights of the unitholders of our partnership to inspect the books and records of the partnership will be substantially the same as the rights of the limited partners of the combining partnerships to inspect the books and records of those partnerships.

177

DESCRIPTION OF COMMON UNITS OF DORCHESTER MINERALS

General

The common units represent limited partner interests in us. The holders of the units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units in and to partnership distributions, see "The Partnership Agreement--Distributions of Available Cash". For a description of the other rights and privileges of limited partners under our partnership agreement, including voting rights, see "The Partnership Agreement." For a description of the initial issuance of our common units, see "The Combination Agreement--Issuance of Units; Fractional Units."

Transfer Agent and Registrar

Duties

EquiServe Trust Company, N.A. will serve as registrar and transfer agent for the common units. We pay all fees charged by the transfer agent for transfers of common units except the following that must be paid by unitholders:

. surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

. special charges for services requested by the holder of a common unit; and

. other similar fees or charges.

There is no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Termination

The transfer agent may terminate the agreement under which it serves as transfer agent upon material breach which is not cured within 30 days of notice of the breach or bankruptcy by us or upon 60 days notice prior to September 1, 2004 or any year thereafter. We may terminate upon material breach by the transfer agent which is not cured within 30 days of notice of the breach or upon 60 days notice prior to September 1, 2004 or any year thereafter. If no successor has been appointed and accepted the appointment, the general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

A transfer of a common unit will not be recorded by the transfer agent or recognized by us unless the transferee executes and delivers a transfer application, or is deemed to have done so. By executing and delivering a transfer application, the transferee, or deemed transferee of common units:

. becomes the record holder of the common units and is an assignee until admitted into our partnership as a substituted limited partner;

. automatically requests admission as a substituted limited partner in our partnership;

. agrees to be bound by the terms and conditions of, and executed, our partnership agreement;

178

. represents that the transferee has the capacity, power and authority to enter into the partnership agreement;

. grants powers of attorney to officers of our general partner and any liquidator of us as specified in the partnership agreement; and

. makes the consents and waivers contained in the partnership agreement.

An assignee will become a substituted limited partner of our partnership for the transferred common units upon the consent of our general partner and the recording of the name of the assignee on our books and records. The general partner may withhold its consent in its sole discretion.

A transferee's broker, agent or nominee may complete, execute and deliver a transfer application. We are entitled to treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder's rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and are transferable according to the laws governing the transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to request admission as a substituted limited partner in our partnership for the transferred common units. A purchaser or transferee of common units that does not execute and deliver a transfer application, or is not deemed to have done so, obtains only:

. the right to assign the common unit to a purchaser or other transferee; and

. the right to transfer the right to seek admission as a substituted limited partner in our partnership for the transferred common units.

Thus, a purchaser or transferee of common units who does not execute and deliver a transfer application, or is not deemed to have done so:

. will not receive cash distributions or federal income tax allocations, unless the common units are held in a nominee or "street name" account and the nominee or broker has executed and delivered a transfer application; and

. may not receive some federal income tax information or reports furnished to record holders of common units.

The transferor of common units has a duty to provide the transferee with all information that may be necessary to transfer the common units. The transferor does not have a duty to insure the execution of the transfer application by the transferee and has no liability or responsibility if the transferee neglects or chooses not to execute and forward the transfer application to the transfer agent.

Until a common unit has been transferred on our books, we and the transfer agent, may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

LEGAL MATTERS

Thompson & Knight L.L.P., Dallas, Texas, as counsel to our partnership, will pass upon the validity of our common units to be issued in the combination. Locke Liddell & Sapp LLP, counsel to Dorchester Hugoton, and Thompson & Knight L.L.P., counsel to Republic and Spinnaker, will pass upon the material federal income tax consequences related to the combination.

179

EXPERTS

The financial statements of Dorchester Hugoton, Ltd. as of December 31, 2001 and 2000, and for each of the three years ended December 31, 2001, have been included in this document and in the registration statement in reliance upon the report of Grant Thornton LLP, independent certified public accountants, appearing elsewhere in this document, and upon the authority of such firm as experts in accounting and auditing.

The financial statements of Republic Royalty Company and Affiliated Partnership, Republic Unaffiliated ORRI Owners, and Spinnaker Royalty Company, L.P. as of December 31, 2001 and 2000, and for each of the three years in the three-year period ended December 31, 2001, have been included in this document and in the registration statement in reliance upon the reports of KPMG, LLP, independent accountants, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.

Calhoun, Blair & Associates, independent petroleum consultants, estimated Dorchester Hugoton's reserves as of December 31, 2001 and 2000 and the present value of the estimated future net reserves from those estimated reserves included in this document and are included in reliance upon their reports given upon their authority as experts on the matters covered by the summary reserve report.

Huddleston & Co., Inc., independent petroleum consultants, estimated each of Republic's and Spinnaker's reserves as of December 31, 2001 and 2000 and the present value of the estimated future net reserves from those estimated reserves included in this document and are included in reliance upon their reports given upon their authority as experts on the matters covered by the summary reserve report.

Certain owners and officers of Huddleston & Co., Inc. are owners and officers of Peter Paul Petroleum Company, the general partner of New Triton Royalty, Ltd., which is a limited partner of Spinnaker that owns a 13.7% sharing percentage in Spinnaker.

FORWARD LOOKING STATEMENTS

This document includes "forward looking statements" as defined by the Securities and Exchange Commission. These statements concern Dorchester Minerals' and each combining partnership's plans, expectations and objectives for future operations. All statements, other than statements of historical facts, included in this document that address activities, events or developments that Dorchester Minerals and each combining partnership expect, believe or anticipate will or may occur in the future are forward looking statements and include the following:

. completion of the combination;

. reserve estimates;

. future production of oil and natural gas; and

. future financial performance and cash distributions by our partnership.

These forward looking statements are based on assumptions, which Dorchester Minerals and each combining partnership believe are reasonable, but which are open to a wide range of uncertainties and business risks. Factors that could cause actual results to differ materially from those anticipated are discussed in (i) "Risk Factors" beginning on page 14 of this document, (ii) periodic filings with the Securities and Exchange Commission, including Annual Reports on Form 10-K for the year ended December 31, 2001 for Dorchester Hugoton and
(iii) "Management's Discussion and Analysis of Combined Financial Condition and Results of Operations" for the year ended December 31, 2001 beginning on page 121 of this document for Republic and "Management's Discussion and Analysis of Financial Condition and Results of Operations" for the year ended December 31, 2001 beginning on page 134 of this document for Spinnaker.

180

"Safe Harbor" Statement under the Private Securities Litigation Reform Act of 1995: Statements in this document regarding each combining partnership's or our partnership's business which are not historical facts are "forward looking statements" that involve risks and uncertainties. For a discussion of these risks and uncertainties, which could cause actual results to differ from those contained in the forward looking statements, see "Risk Factors" beginning on page 14 of this document.

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.

"BOE" means a barrel-of-oil-equivalent and is a customary convention used in the United States to express oil and natural gas volumes on a comparable basis. It is determined on the basis of the estimated relative energy content of natural gas to oil, being approximately six Mcf (or MMBTU) of natural gas per Bbl of oil.

"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 waterflooding 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.

181

"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.

"MBbl" means one thousand Bbls.

"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.

"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" (also referred to as a "net overriding royalty interest") means a non-operating interest that creates a share in gross production from an operating or working interest in oil and natural gas properties. The share is measured by net profits from the sale of production.

"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 "carved" out of a working or operating interest. Its term extends for the same term as the working interest from which it is carved.

"Proved developed reserves" means proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

"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 power 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.

182

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

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

"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.

183

UNAUDITED PRO FORMA FINANCIAL INFORMATION

The following unaudited pro forma combined financial information gives effect to the combination of Dorchester Hugoton, Republic, the Republic ORRIs, and Spinnaker ("the Combining Entities"), to be accounted for using the purchase method of accounting. The pro forma balance sheet has been prepared as if the combination occurred on December 31, 2001. The pro forma statement of operations has been prepared as if the combination occurred on January 1, 2001.

The pro forma financial information is presented for illustrative purposes only and is not necessarily indicative of what the combined financial position or results of operations would actually have been if the combination had, in fact, occurred on those dates, or what the financial position or results of operations may be for any future date or period. This pro forma financial information is based upon the respective historical financial statements of the Combining Entities and related notes included in this prospectus and should be read in conjunction with those statements and notes.

P-1

UNAUDITED PRO FORMA COMBINED BALANCE SHEET
DECEMBER 31, 2001
(IN THOUSANDS)

                                                            Dorchester          Republic              Pro forma      Pro forma
                                                             Hugoton   Republic  ORRIs    Spinnaker  adjustments     combined
                                                            ---------- -------- --------  ---------  -----------     ---------
Current Assets:
   Cash and cash equivalents...............................   18,439       579       --        371     (19,389)  b         --
   Investments--available for sale.........................    5,030                                    (5,030)  b         --
   Accounts receivable, net................................    1,472     2,286     2,254       978      (2,487)  a
                                                                                                          (497)  b       4,006
   Prepaid expenses and other current assets...............      453                                      (453)  b         --
                                                             -------   -------  --------   -------     -------       ---------
       Total current assets................................   25,394     2,865     2,254     1,349     (27,856)          4,006
                                                             -------   -------  --------   -------     -------       ---------
Property and equipment.....................................   34,996     6,254    64,961    30,501      96,738   c     233,450
   Less depreciation, depletion and amortization...........  (18,936)   (3,408)  (35,367)  (17,845)     56,620   c
                                                                                                       (94,514)  d    (113,450)
                                                             -------   -------  --------   -------     -------       ---------
       Net property and equipment..........................   16,060     2,846    29,594    12,656      58,844         120,000
                                                             -------   -------  --------   -------     -------       ---------
       Total assets........................................   41,454     5,711    31,848    14,005      30,988         124,006
                                                             =======   =======  ========   =======     =======       =========
Current liabilities:
   Accounts payable and other current liabilities..........      648       273       233       150        (233)  a
                                                                                                        (1,071)  b         --
   Production and property taxes payable...................      230                                      (230)  b         --
   Nonaffiliated ORRI owner payable........................              2,254                          (2,254)  a         --
   Royalties payable.......................................      309                                      (309)  b         --
   Distributions payable...................................    2,931                                    (2,931)  b          --
                                                             -------   -------  --------   -------     -------       ---------
       Total current liabilities...........................    4,118     2,527       233       150      (7,028)
Partnership capital
   General partners........................................      271     3,184       --       (303)      1,293   e       4,445
   Limited partners........................................   34,552       --     31,615    14,158     (18,315)  b
                                                                                                       153,358   c
                                                                                                       (94,514)  d
                                                                                                        (1,293)  e     119,561
   Accumulated other comprehensive income..................    2,513       --        --         --      (2,513)  b         --
                                                             -------   -------  --------   -------     -------       ---------
       Total partnership capital...........................   37,336     3,184    31,615    13,855      38,016         124,006
                                                             -------   -------  --------   -------     -------       ---------
Total liabilities and partnership capital..................   41,454     5,711    31,848    14,005      30,988         124,006
                                                             =======   =======  ========   =======     =======       =========

See notes to pro forma combined financial information.

P-2

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2001
(IN THOUSANDS, EXCEPT PER UNIT DATA)

                                         Dorchester           Republic            Pro forma      Pro forma
                                          Hugoton   +Republic  ORRIs   Spinnaker adjustments     combined
                                         ---------- --------- -------- --------- -----------     ---------
Net operating revenues:
   Net profits interest.................                                            20,524   b     20,524
   Natural gas sales....................   27,153                                  (27,153)  b        --
   Royalties............................              2,549    15,218   10,871                     28,638
   Lease bonus..........................                 22       128       34                        184
   Facilitation amount..................                604                           (604)  a        --
   Other................................      192        49       291       39        (192)  b        379
   Production payment...................     (566)                                     566   b        --
                                           ------    ------    ------   ------     -------       --------
       Total net operating revenues.....   26,779     3,224    15,637   10,944      (6,859)        49,725
Cost and expenses
   Operating............................    3,160                                   (3,160)  b        --
   Production taxes.....................    1,721       231     1,520      827      (1,721)  b      2,578
   Depreciation, depletion and
     amortization.......................    2,105       298     3,102    1,442      14,466   c     21,413
   General and administrative:..........    1,764       425       776      613        (461)  b
                                                                                    (1,178)  e      1,939
   Facilitation amount..................                          604                 (604)  a        --
   Management fees......................      605                           --        (605)  b        --
   Impairment of assets.................                                            73,101   d     73,101
                                           ------    ------    ------   ------     -------       --------
   Operating expenses...................    9,355       954     6,002    2,882      79,838         99,031
                                           ------    ------    ------   ------     -------       --------
       Operating income (loss)..........   17,424     2,270     9,635    8,062     (86,697)       (49,306)
Other
   Investment income....................     (897)                                     897   b        --
   Interest expense.....................       36                                      (36)  b        --
   Other expense (income)...............      (66)      --                  --          22   b        (44)
                                           ------    ------    ------   ------     -------       --------
       Total other (income)
         expenses.......................     (927)      --                             883            (44)
                                           ------    ------    ------   ------     -------       --------
Net earnings (loss).....................   18,351     2,270     9,635    8,062     (87,580)       (49,262)
                                           ======    ======    ======   ======     =======       ========
Allocation of net earnings (loss)
       General Partners.................                                                           (2,523)
                                                                                                 ========
       Limited Partners.................                                                          (46,739)
                                                                                                 ========
Net earnings (loss) per unit............                                                            (1.73)
                                                                                                 ========
Weighted average common units
  outstanding...........................                                                           27,040
                                                                                                 ========

See notes to pro forma combined financial information.

P-3

UNAUDITED PRO FORMA STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2001
(IN THOUSANDS)

                                                            Dorchester          Republic              Pro forma      Pro forma
                                                             Hugoton   Republic  ORRIs    Spinnaker  adjustments     combined
                                                            ---------- -------- --------  ---------  -----------     ---------
Cash flows from operating activities:
Net earnings (loss)........................................    18,351    2,270     9,635     8,062     (87,580)  a    (49,262)
Adjustments to reconcile net earnings to net cash provided
  by operating activities:
   Depreciation, depletion and amortization................     2,105      298     3,102     1,442      14,466   d     21,413
   Asset impairment........................................       --       --        --        --       73,101   d     73,101
   Gain on sale of property and equipment..................       (22)     --        --                     22   a        --
   Other...................................................       (62)     --        --                     62   a        --
Changes in operating assets and liabilities:
   Restricted cash.........................................       409      --        --                   (409)  a        --
   Accounts receivable.....................................     2,620    1,522     2,560     1,300      (2,993)  a      5,009
   Prepaid expenses and other current assets...............      (169)     --        --                    169   a        --
   Accounts payable, taxes and royalties payable...........    (2,203)  (2,329)      203        47       4,282   a        --
                                                             --------  -------  --------  --------     -------       --------
Net cash provided by operating activities..................    21,029    1,761    15,500    10,851       1,120         50,261
                                                             --------  -------  --------  --------     -------       --------
Cash flows from investing activities:
   Capital expenditures....................................    (5,587)     --        --         --         272   a     (5,315)
   Cash received on sale of property and equipment.........        37      --        --         --         (37)  a        --
                                                             --------  -------  --------  --------     -------       --------
Net cash used by investing activities......................    (5,550)     --        --        --          235         (5,315)
                                                             --------  -------  --------  --------     -------       --------
Cash flows from financing activities:
   Distributions paid......................................   (12,807)  (3,089)  (15,500)  (11,529)      3,777   c    (39,148)
                                                             --------  -------  --------  --------     -------       --------
Increase (decrease) in cash and cash equivalents...........     2,672   (1,328)      --       (678)      5,132          5,798
Cash and cash equivalents at beginning of year.............    15,767    1,907       --      1,049     (18,723)  b        --
                                                             --------  -------  --------  --------     -------       --------
Cash and cash equivalents at end of year...................    18,439      579       --        371     (13,591)         5,798
                                                             ========  =======  ========  ========     =======       ========

See notes to pro forma combined financial information.

P-4

Notes to Pro Forma Combined Financial Information
(in thousands)

1. Basis of Presentation

The pro forma financial information presents the combination using the purchase method of accounting. Dorchester Hugoton is deemed to be the acquiror because its depository receipt holders are the ownership group that will receive the largest ownership interest in Dorchester Minerals, L.P. Accordingly, the assets of Republic, the Republic ORRIs and Spinnaker are adjusted to fair value in the pro forma balance sheet.

For accounting purposes, the fair value (new basis) of the assets of Republic ($19,341), the Republic ORRIs ($114,048) and Spinnaker ($65,064) is based on the market price of Dorchester Hugoton units on May 3, 2001, and the share of the total units of Dorchester Minerals, L.P. that the partners of Republic, the Republic ORRIs and Spinnaker will receive.

However, the resulting new basis of the oil and gas properties of Dorchester Minerals exceeds the full cost ceiling by approximately $95,000. Accordingly, the properties have been written down by that amount.

2. Pro Forma Adjustments

Balance sheet adjustments:

(a) Eliminate intercompany receivables and payables.

(b) Eliminate assets and liabilities that will not be transferred to Dorchester Minerals, L.P.

(c) Adjust historical book values of property and equipment of Republic, the Republic ORRIs, and Spinnaker to fair value, as follows:

Purchase accounting fair value...............         $198,454
Historical cost:
   Republic.................................. $ 2,846
   Republic ORRIs............................  29,594
   Spinnaker.................................  12,656   45,096
                                              ------- --------
                                                      $153,358
                                                      ========
Allocation:
   Property and equipment....................         $ 96,738
   Accumulated depreciation, depletion and
     amortization............................           56,620
                                                      --------
                                                      $153,358
                                                      ========

(d) Write down oil and gas properties to estimated discounted future net cash flows, as follows:

New basis............................................. $ 214,514
Estimated discounted future net cash flows............  (120,000)
                                                       ---------
Write-down............................................ $  94,514
                                                       =========

(e) Adjust equity accounts to reflect capital structure of Dorchester Minerals, L.P.

Statement of operations adjustments

(a) Eliminate intercompany transactions

(b) Reflect the income and expenses of Dorchester Hugoton as a 96.97% net profits interest.

(c) Adjust depreciation, depletion, and amortization based on the new basis of oil and gas properties.

P-5

(d) Write down oil and gas properties, based on estimated discounted future net cash flows at December 31, 2001 as follows:

New basis for properties at January 1, 2001....................... $ 214,514
Less depreciation, depletion and amortization expense for the year   (21,413)
                                                                   ---------
                                                                     193,101
Estimated discounted future net cash flows at December 31, 2001...  (120,000)
                                                                   ---------
Write-down........................................................ $  73,101
                                                                   =========

(e) Eliminate nonrecurring transaction costs.

Statement of cash flows adjustments

(a) Reflect the net adjustments to the pro forma statement of operations for assets excluded from the acquisition, liabilities not assumed or intercompany eliminations affecting the reconciliation of net earnings
(loss) to net cash provided by (used in) operating and investing activities.

(b) Eliminate historical cash balances not transferred in the acquisition.

(c) Adjust distributions paid to pro forma amounts.

(d) Adjustment for non-cash items affected by pro forma adjustments to statement of operations.

3. Pro Forma Information on Oil and Gas Operations

The pro forma reserve information set forth below assumes the combination transactions were completed on January 1, 2001. There are many uncertainties inherent in estimating reserve quantities, and in projecting future production rates and the timing of future development expenditures. Accordingly, estimates are subject to change as additional information becomes available. Revisions of estimates can have a significant impact on the results.

Proved oil and natural gas reserves are the estimated quantities of crude oil, condensate, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic conditions. Proved developed oil and gas reserves are those reserves expected to be recovered through existing equipment and operating methods.

All reserves are located in the United States.

P-6

SUMMARY OF CHANGES IN PRO FORMA COMBINED PROVED RESERVES

                                                Dorchester          Republic            Pro forma  Pro forma
Oil (MBbls)                                      Hugoton   Republic  ORRIs   Spinnaker adjustments combined
-----------                                     ---------- -------- -------- --------- ----------- ---------
Proved reserves
   Estimated quantity, beginning of year.......    --        698     2,793     1,002       --        4,493
   Revisions of previous estimates.............    --         37       151        60       --          248
   Production..................................    --        (55)     (223)      (88)      --         (366)
                                                   ---       ---     -----     -----       ---       -----
   Estimated quantity, end of year.............    --        680     2,721       974       --        4,375
                                                   ===       ===     =====     =====       ===       =====
Proved developed reserves
   Beginning of year...........................    --        662     2,650       966       --        4,278
   End of year.................................    --        645     2,582       931       --        4,158

                                                Dorchester          Republic            Pro forma  Pro forma
Gas (MMcf)                                       Hugoton   Republic  ORRIs   Spinnaker adjustments combined
----------                                      ---------- -------- -------- --------- ----------- ---------
Proved reserves
   Estimated quantity, beginning of year.......   54,127    3,793    15,173    15,000    (1,640)a    86,453
   Revisions of previous estimates.............      743      757     3,148     1,784       (23)a     6,409
   Production..................................   (6,568)    (519)   (2,198)   (2,247)      200 a   (11,332)
                                                  ------    -----    ------   -------    ------     -------
   Estimated quantity, end of year.............   48,302    4,031    16,123    14,537    (1,463)     81,530
                                                  ======    =====    ======   =======    ======     =======
Proved developed reserves
   Beginning of year...........................   54,127    3,509    14,038    12,669    (1,640)a    82,703
   End of year.................................   48,302    3,716    14,863    12,297    (1,463)a    77,715

a) to adjust Dorchester Hugoton amounts to 96.97% of historical amounts.

P-7

PRO FORMA COMBINED STANDARDIZED MEASURE
OF DISCOUNTED FUTURE NET CASH FLOWS
(IN THOUSANDS)

                                                            Dorchester           Republic              Pro forma      Pro forma
                                                             Hugoton   Republic   ORRIs    Spinnaker  adjustments     combined
                                                            ---------- --------  --------  ---------  -----------     ---------
Future estimated gross revenues............................   117,029   109,736    87,789    52,935     (87,789)  a
                                                                                                         (3,546)  b     276,154
Net proceeds interest to unaffiliated ORRI owner...........       --    (87,789)      --         --      87,789   a         --
Less future estimated production taxes.....................              (1,689)   (6,758)   (4,237)        --          (12,684)
Future estimated production and development costs..........   (51,083)      --        --         --       1,548   b     (49,535)
                                                             --------  --------  --------   -------    --------       ---------
Future estimated net revenues..............................    65,946    20,258    81,031    48,698      (1,998)        213,935
10% annual discount for estimated timing of cash flows.....   (21,220)  (10,240)  (40,958)  (21,871)        643   b     (93,646)
                                                             --------  --------  --------   -------    --------       ---------
Standardized measure of discounted future estimated net
  revenues.................................................    44,726    10,018    40,073    26,827      (1,355)        120,289
                                                             ========  ========  ========   =======    ========       =========

Beginning of year..........................................   140,003    25,812   103,249    92,416      (4,242)  b     357,238
Sales of natural gas produced, net of production costs.....   (21,899)   (2,318)  (13,698)  (10,044)        664   b     (47,295)
Net changes in prices and production costs.................   (89,233)  (14,913)  (59,651)  (60,964)      2,704   b    (222,057)
Revisions of previous quantity estimates...................     3,488     1,277     5,107     2,290        (106)  b      12,056
Accretion of discount......................................    12,471     2,581    10,325     9,242        (378)  b      34,241
Other......................................................      (104)   (2,421)   (5,259)   (6,113)          3   b     (13,894)
                                                             --------  --------  --------   -------    --------       ---------
Net change in standardized measure of discounted future
  estimated net revenues...................................   (95,277)  (15,794)  (63,176)  (65,589)      2,887        (236,949)
                                                             --------  --------  --------   -------    --------       ---------
End of year................................................    44,726    10,018    40,073    26,827      (1,355)        120,289
                                                             ========  ========  ========   =======    ========       =========

a) to eliminate intercompany amounts
b) to adjust Dorchester Hugoton amounts to 96.97% of historical amounts.

P-8

DORCHESTER MINERALS, L.P.

INDEX TO FINANCIAL STATEMENTS

Dorchester Hugoton, Ltd.
   Report of Independent Accountants..................................  F-2
   Balance Sheets, December 31, 2001 and 2000.........................  F-3
   Statements of Earnings, Years ended December 31, 2001, 2000 and
     1999.............................................................  F-4
   Statements of Comprehensive Income, Years ended December 31, 2001,
     2000 and 1999....................................................  F-4
   Statements of Changes in Partnership Capital, Years ended December
     31 1999, 2000 and 2001...........................................  F-5
   Statement of Cash Flows, Years ended December 31, 2001, 2000 and
     1999.............................................................  F-6
   Notes to Financial Statements......................................  F-7

Republic Royalty Company and Affiliated Partnership
   Independent Auditor's Report....................................... F-12
   Combined Balance Sheets, December 31, 2001 and 2000................ F-13
   Combined Statements of Operations, Years ended December 31, 2001,
     2000 and 1999.................................................... F-14
   Combined Statements of Owners' Capital, Years ended December 31,
     2001, 2000 and 1999.............................................. F-15
   Combined Statements of Cash Flows, Years ended December 31, 2001,
     2000 and 1999.................................................... F-16
   Notes to Combined Financial Statements............................. F-17

Republic Royalty Company--Unaffiliated Republic ORRIs Owners
   Independent Auditor's Report....................................... F-23
   Balance Sheets, December 31, 2000 and 2001......................... F-24
   Statements of Operations, Years ended December 31, 2001, 2000 and
     1999............................................................. F-25
   Statements of ORRIs Owners' Equity, Years ended December 31, 2001,
     2000 and 1999.................................................... F-26
   Statements of Cash Flows, Years ended December 31, 2001, 2000 and
     1999............................................................. F-27
   Notes to Financial Statements...................................... F-28

Spinnaker Royalty Company, L.P.
   Independent Auditor's Report....................................... F-34
   Balance Sheets, December 31, 2000 and 2001......................... F-35
   Statements of Operations, Years ended December 31, 2001, 2000 and
     1999............................................................. F-36
   Statements of Partners' Capital, Years ended December 31, 2001,
     2000 and 1999.................................................... F-37
   Statements of Cash Flows, Years ended December 31, 2001, 2000 and
     1999............................................................. F-38
   Notes to Financial Statements...................................... F-39

F-1

REPORT OF INDEPENDENT ACCOUNTANTS

To the General Partners and Unitholders of Dorchester Hugoton, Ltd.:

We have audited the financial statements of Dorchester Hugoton, Ltd. listed under Financial Information above. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Dorchester Hugoton, Ltd. as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.

                                          /s/  Grant Thornton LLP
                                          -----------------------------
                                          GRANT THORNTON LLP

Dallas, Texas
February 8, 2002

F-2

BALANCE SHEETS
December 31, 2001 and 2000
(Dollars in Thousands)

                          ASSETS
                                                            2001    2000
                                                           ------- -------
Current assets:
 Cash and cash equivalents................................ $18,439 $15,767
 Restricted cash (Note 4).................................      --     409
 Investments--available for sale..........................   5,030   5,564
 Accounts receivable......................................   1,472   4,092
 Prepaid expenses and other current assets................     453     284
                                                           ------- -------
     Total current assets.................................  25,394  26,116
                                                           ------- -------
Property and equipment--at cost:
 Natural gas properties (full cost method)................  34,008  28,467
 Other....................................................     988   1,122
                                                           ------- -------
     Total................................................  34,996  29,589
Less accumulated depreciation, depletion and amortization:
 Full cost depletion......................................  18,561  16,534
 Other....................................................     375     462
                                                           ------- -------
     Total................................................  18,936  16,996
                                                           ------- -------
Net property and equipment................................  16,060  12,593
                                                           ------- -------
     Total assets......................................... $41,454 $38,709
                                                           ======= =======

                   LIABILITIES AND PARTNERSHIP CAPITAL
Current liabilities:
 Accounts payable......................................... $   648 $   443
 Production and property taxes payable....................     230     996
 Royalties payable........................................     309   1,851
 Distributions payable to Unitholders.....................   2,931   2,389
                                                           ------- -------
     Total current liabilities............................   4,118   5,679
Notes payable--long-term..................................      --     100
                                                           ------- -------
     Total liabilities....................................   4,118   5,779
                                                           ------- -------
Commitments and contingencies (Note 4)
 Partnership capital:
 General partners.........................................     271     222
 Unitholders..............................................  34,552  29,661
 Accumulated other comprehensive income...................   2,513   3,047
                                                           ------- -------
   Total partnership capital..............................  37,336  32,930
                                                           ------- -------
     Total liabilities and partnership capital............ $41,454 $38,709
                                                           ======= =======

See Notes to Financial Statements

F-3

STATEMENTS OF EARNINGS
For the Years Ended December 31, 2001, 2000 and 1999
(Dollars in Thousands)

                                                               Year Ended December 31
                                                             -------------------------
                                                              2001     2000     1999
                                                             -------  -------  -------
Net operating revenues:
  Natural gas sales......................................... $27,153  $26,368  $15,849
  Other.....................................................     192      221      198
  Production payment (ORRI).................................    (566)  (1,407)    (745)
                                                             -------  -------  -------
     Total net operating revenues...........................  26,779   25,182   15,302
                                                             -------  -------  -------
Costs and expenses:
  Operating.................................................   3,160    2,840    2,678
  Production taxes..........................................   1,721    1,529      910
  Depreciation, depletion and amortization..................   2,105    1,783    1,903
  General and administrative:
   Tax and regulatory reporting.............................     323      320      176
   Depositary and transfer agent fees.......................      22       22       24
   Other....................................................     634      448      363
  Management fees...........................................     605      589      490
  Merger costs..............................................     785      339       --
  Investment income.........................................    (897)    (664)    (318)
  Interest expense..........................................      36       39       37
  Other income, net.........................................     (66)     (25)      (7)
                                                             -------  -------  -------
     Total costs and expenses...............................   8,428    7,220    6,256
                                                             -------  -------  -------
Net earnings................................................ $18,351  $17,962  $ 9,046
                                                             =======  =======  =======
Net earnings per Unit....................................... $  1.69  $  1.66  $  0.83
                                                             =======  =======  =======

                          STATEMENTS OF COMPREHENSIVE INCOME
                 For the Years Ended December 31, 2001, 2000 and 1999
                                (Dollars in Thousands)
                                                               Year Ended December 31
                                                             -------------------------
                                                              2001     2000     1999
                                                             -------  -------  -------
Net earnings................................................ $18,351  $17,962  $ 9,046
Unrealized holding gain (loss) on available for sale
  securities................................................    (534)     408      476
                                                             -------  -------  -------
Comprehensive income........................................ $17,817  $18,370  $ 9,522
                                                             =======  =======  =======

See Notes to Financial Statements

F-4

STATEMENTS OF CHANGES IN PARTNERSHIP CAPITAL
For the Years Ended December 31, 1999, 2000 and 2001
(Dollars in Thousands)

                                                                  Accumulated
                                                                     Other
                                            General              Comprehensive
Year                                        Partners Unitholders    Income      Total
----                                        -------- ----------- ------------- --------
1999
 Balance at January 1, 1999................  $ 128    $ 20,350      $2,163     $ 22,641
 Net earnings..............................     90       8,956          --        9,046
 Net unrealized holding gain on investments
   available for sale......................     --          --         476          476
 Distributions ($0.72 per Unit)............    (78)     (7,736)         --       (7,814)
 Other.....................................     --         (11)         --          (11)
                                             -----    --------      ------     --------
 Balance at December 31, 1999..............    140      21,559       2,639       24,338
                                             -----    --------      ------     --------

2000
 Net earnings..............................    180      17,782          --       17,962
 Net unrealized holding gain on investments
   available for sale......................     --          --         408          408
 Distributions ($0.90 per Unit)............    (98)     (9,670)         --       (9,768)
 Other.....................................     --         (10)         --          (10)
                                             -----    --------      ------     --------
 Balance at December 31, 2000..............    222      29,661       3,047       32,930
                                             -----    --------      ------     --------

2001
 Net earnings..............................    183      18,168          --       18,351
 Net unrealized holding loss on investments
   available for sale......................     --          --        (534)        (534)
 Distributions ($1.23 per Unit)............   (133)    (13,216)         --      (13,349)
 Other.....................................     (1)        (61)         --          (62)
                                             -----    --------      ------     --------
 Balance at December 31, 2001..............  $ 271    $ 34,552      $2,513     $ 37,336
                                             =====    ========      ======     ========

See Notes to Financial Statements

F-5

STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2001, 2000, and 1999
(Dollars in Thousands)

                                                                           2001     2000     1999
                                                                         --------  -------  -------
Cash flows from operating activities:
 Net earnings........................................................... $ 18,351  $17,962  $ 9,046
 Adjustments to reconcile net earnings to net cash provided by operating
   activities:
   Depreciation, depletion and amortization.............................    2,105    1,783    1,903
   Gain on sale of property and equipment...............................      (22)     (29)      (8)
   Other................................................................      (62)     (10)     (11)
   Changes in operating assets and liabilities:
     Restricted cash....................................................      409      (19)     (11)
     Accounts receivable................................................    2,620   (2,537)      90
     Prepaid expenses and other current assets..........................     (169)    (143)      11
     Accounts payable, taxes and royalties payable......................   (2,203)   1,519       25
                                                                         --------  -------  -------
Net cash provided by operating activities...............................   21,029   18,526   11,045
                                                                         --------  -------  -------
Cash flows from investing activities:
 Capital expenditures...................................................   (5,587)    (496)    (391)
 Cash received on sale of property and equipment........................       37       54       12
                                                                         --------  -------  -------
Net cash used by investing activities...................................   (5,550)    (442)    (379)
                                                                         --------  -------  -------
Cash flows from financing activities:
 Distributions paid to Unitholders......................................  (12,807)  (9,334)  (7,816)
                                                                         --------  -------  -------
Increase in cash and cash equivalents...................................    2,672    8,750    2,850
Cash and cash equivalents at beginning of year..........................   15,767    7,017    4,167
                                                                         --------  -------  -------
Cash and cash equivalents at end of year................................ $ 18,439  $15,767  $ 7,017
                                                                         ========  =======  =======
Supplemental cash flow and other information:
 Interest paid (no interest was capitalized)............................ $     28  $    39  $    37
                                                                         ========  =======  =======
 Distributions declared but not paid.................................... $  2,931  $ 2,389  $ 1,956
                                                                         ========  =======  =======

See Notes to Financial Statements

F-6

NOTES TO FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999

1. General and Summary of Significant Accounting Policies

Nature of Operations--The Partnership's operations consist principally of the operation of natural gas properties located in Kansas and Oklahoma.

Basis of Presentation--Per-Unit information is calculated by dividing the 99% interest owned by Unitholders by the 10,744,380 Units outstanding.

Reclassification--Certain amounts in the 1999 and 2000 financial statements have been reclassified to conform to the 2001 presentation.

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

Cash and Cash Equivalents--The Partnership's principal banking and short-term investing activities are with major financial institutions. Short-term investments with a maturity of three months or less are considered to be cash equivalents and are carried at cost, which approximates fair value. Cash balances in these accounts may, at times, exceed federally insured limits. The Partnership has not experienced any losses in such cash accounts or investments and does not believe it is exposed to any significant risk on cash and cash equivalents.

Concentration of Credit Risks--The Partnership sells its natural gas to major corporate gas purchasers in the United States and either requires major corporate guarantees, good credit history with the Partnership, letters of credit, or performs on-going credit evaluations or review of financial statements on a regular basis. The Partnership has incurred minimal credit losses.

Investments--The Partnership's investments consist of 128,000 shares of Exxon Mobil Corporation (previously Exxon Corporation) common stock and are classified as available for sale. At December 31, 2001 and 2000, the carrying value of this stock, based on the quoted market price, was $5,030,400 and $5,564,000, respectively, and the cost was $2,517,455 for both years.

Property and Equipment--The Partnership follows the full cost method of accounting prescribed by the United States Securities and Exchange Commission under which all costs relating to the acquisition, exploration and development of natural gas properties (both productive and nonproductive) are capitalized (not to exceed estimated discounted future net cash flows) by the country (United States) in which the costs are incurred. Natural gas properties are being depleted on the unit-of-production method using estimates of proved gas reserves. Other assets are being depreciated or amortized using straight-line methods for financial reporting purposes over estimated useful lives of 3 to 40 years.

Gains or losses are recognized upon the disposition of natural gas properties involving a significant portion of the Partnership's reserves. Proceeds from other dispositions of natural gas properties are credited to the full cost account.

General Partners--The Partnership's General Partners have the overall responsibility for the management, operation and future development of the properties. Each General Partner is entitled to receive reasonable compensation in the form of a management fee, to be divided among the General Partners in an annual aggregate amount of $350,000 plus 1% of the gross income from the Partnership properties for services rendered in

F-7

NOTES TO FINANCIAL STATEMENTS--(Continued)

operating and managing the Partnership. The General Partners are also reimbursed for all general and administrative expenses incurred by them on behalf of the Partnership.

Operating Agreement--The Partnership operates substantially all of its natural gas properties. Efforts are made to balance each working interest owner's share of production to gas marketed by increasing or decreasing the volumes of gas allocated to each working interest owner in subsequent months so that each such working interest owner shall be able to share in the actual cumulative production in proportion to its interest in the properties. The Partnership receives in-kind the Partnership's share of gas produced from 11 wells in Oklahoma (10 operated by others and one operated by the Partnership). At December 31, 2001, the net balance owed the Partnership is approximately 14,000 MCF compared to approximately 300 MCF at December 31, 2000.

Other Agreements--Effective May 1, 1997, the Partnership's Kansas gas was committed for sale and processing to PanEnergy Field Services, Inc. (now Duke Energy Field Services, Inc.) for a period of three years and year to year thereafter. Duke Energy will pay based on an index of the market price in the field plus a premium. Similarly, effective July 1, 2000 the Partnership's Oklahoma gas was committed for sale to Williams Energy Marketing and Trading Company ("WEM & TC") for a one-year period at a premium over the market price index. Since July 1, 2001, such sales have been on a month-to-month basis at varying market price indexes. During 1996, the Partnership's Oklahoma gas began a five-year commitment to Williams Field Services Company for delivery through a processing facility. During 2001, the commitment was extended another five years. Effective February 28, 2002 Williams Field Services will sell the processing facility to Duke Energy Field Services L.P. who intends to shift the processing to its facility near Liberal, Kansas. The quantity sold to WEM & TC is determined by nominations at the processing facility outlet. Imbalances with actual deliveries to Williams Field Services Company are corrected in each subsequent month. At December 31, 2001, the imbalance was approximately 3,000 MMBTU owed the Partnership compared to 7,000 MMBTU owed the Partnership at December 31, 2000.

Operating Revenue--Natural gas revenues are recognized as production and sales take place (the "sales method"). The Partnership's purchasers (including their affiliates) who accounted for more than 10% of natural gas revenues for each of the years ended December 31, 2001, 2000, and 1999 are as follows:

     Purchaser Purchaser
Year    "A"       "B"
---- --------- ---------
2001    83%       16%
2000    83%       16%
1999    80%       19%

The Partnership believes that the loss of any single customer would not have a material adverse effect on the results of its operations because the transmission (and gathering) pipelines connected to the Partnership's facilities are required by the Federal Energy Regulatory Commission or state regulations to provide continued equal access for shipment of natural gas. Additionally, there are numerous buyers available on each pipeline.

Income Taxes--The Partnership is treated as a partnership for income tax purposes and, as a result, income or loss of the Partnership is includible in the tax returns of the individual Unitholders. Accordingly, no recognition has been given to income taxes in the financial statements.

An investment in the Partnership by certain tax-exempt entities (such as IRA's, pension plans, etc.) may produce Unrelated Business Taxable Income ("UBTI"). Many tax-exempt entities are subject to tax on UBTI. Tax-exempt entities subject to the tax on UBTI must file with the IRS for each tax year that the entity has gross income of $1,000 or more from an unrelated trade or business. Additionally, the Partnership reports Unitholders' share of depreciation adjustments for alternative minimum tax ("AMT") purposes. The AMT adjustment must be taken into account when figuring Unitholder passive activity gains and losses for AMT purposes. UBTI and

F-8

NOTES TO FINANCIAL STATEMENTS--(Continued)

AMT are specialized areas of the tax law--Unitholders should consult tax advisors concerning their own tax situation. Finally, depletion of natural gas properties is an expense allowable to each individual partner and the depletion expense as reported on the financial statements will not be indicative of the depletion expense an individual partner or Unitholder may be able to deduct for income tax purposes.

Simplified Employee Pension Plan--Contributions aggregating $150,980, $136,065, and $135,125 were made to eligible employees' accounts for 2001, 2000, and 1999, respectively under the Partnership's simplified employee pension plan. Employees become eligible in their third calendar year of employment. The Partnership does not have any other post-retirement benefit plans.

Operating Leases--The Partnership rents administrative office space under leases expiring at various dates through 2007. The Partnership also rents nine skid-mounted field gas compressor units on a month-to-month basis. The Partnership also has various prepaid site leases in Kansas and Oklahoma. Total rental expense was $311,000, $337,000, and $333,000 for the years ended December 31, 2001, 2000, and 1999, respectively.

2. Loans And Long-Term Debt

On July 19, 1994, the Partnership entered into a $15,000,000 unsecured revolving credit facility (the "Credit Agreement") with Bank One, Texas, NA (the "Bank") which will expire July 31, 2002. The current borrowing base is $6,000,000, which will be re-evaluated by the Bank at least annually. If, on any such date, the aggregate amount of outstanding loans and letters of credit exceed the current borrowing base, the Partnership is required to repay the excess. This credit facility includes both cash advances and any letters of credit that the Partnership may need, with interest being charged at the Bank's base rate, which was 4.75% on December 31, 2001. All amounts borrowed under this facility become due and payable on July 31, 2002. As of December 31, 2001, no letters of credit were issued under the credit facility. The Partnership is required to maintain certain minimum defined financial ratios with respect to its current ratio and the ratio of net cash flow to debt service. In addition, Partnership capital must be maintained above specified amounts. This note has been guaranteed by the General Partners. Since July 1994 the maximum amount borrowed under the Credit Agreement has been $5,800,000. During 2001 and 2000 the amount borrowed under the Credit Agreement was $100,000 (the minimum borrowing necessary to maintain the credit facility).

3. Agreement To Combine Businesses And Properties.

As disclosed on a Form 8-K filed on December 14, 2001, the Partnership has signed definitive agreements to combine the businesses and/or properties of the Partnership, Republic Royalty Company, and Spinnaker Royalty Company, L.P., in a non-taxable transaction, into a new publicly traded limited partnership. During 2001, approximately $785,000 was expensed related to the combination compared to $339,000 in 2000. The combination is subject to a number of conditions including (1) approval by a majority of Dorchester Hugoton Unitholders, (2) approvals by the owners of Spinnaker Royalty and Republic Royalty and affiliated partnerships and interest holders, and (3) filings with and/or clearances by various securities and governmental authorities.

4. Commitments And Contingencies

Since its first annual payment in 1997, each May the Partnership paid an Oklahoma production payment (calculated through the prior February) that is based upon the difference between market gas prices compared to a table of rising prices and based upon a table of declining volumes. On August 9, 2001, the Partnership paid $5,270,000 to acquire, effective March 1, 2001, the Oklahoma production payment.

Through 1998 the Partnership recorded $450,000 (which included related interest) towards a request from Panhandle Eastern Pipe Line Company ("PEPL") for refund of Kansas tax reimbursements received by the Partnership during the years 1983 to 1987. These charges resulted from a ruling by the United States Court of

F-9

NOTES TO FINANCIAL STATEMENTS--(Continued)

Appeals for the District of Columbia, which overruled a previous order by the Federal Energy Regulatory Commission ("FERC"). On March 9, 1998, $151,757 was paid to PEPL. An additional $366,633, which was still awaiting possible settlement/regulatory/judicial/ legislative action, was placed into an escrow account. On March 2, 1999, $2,840 was released from escrow to PEPL. On June 22, 2001, the Partnership, along with others, reached a Settlement Agreement with PEPL which became final October 15, 2001 upon approval by the FERC. The Partnership reduced its accrued liability from approximately $419,000 to approximately $320,000 during the third quarter of 2001. Pursuant to that Settlement, during October 2001, the Partnership returned all funds collected from royalty owners (approximately $35,000) who had paid their refund obligation to the Partnership. Also, in connection with the Settlement, on November 20, 2001 the Partnership paid from the escrow account approximately $285,000 to PEPL and approximately $135,000 to the Partnership, subsequently closing the escrow account.

The Partnership is involved in a few other legal and/or administrative proceedings arising in the ordinary course of its gas business, none of which have predictable outcomes and none of which are believed to have any significant effect on financial position or operating results.

The Partnership adopted a severance policy during the first quarter of 1998. Benefits are generally payable to employees and General Partner(s) in the event the Partnership incurs reduction in force or the elimination of a position or group of positions. The policy provides for up to approximately $2.8 million of severance payments if
such obligations occur. Pursuant to the Combination Agreement referred to in Note 3 such severance payments, estimated to be $2.7 million, will be paid by the Partnership prior to closing of the transaction.

5. Unaudited Natural Gas Reserve Information

Proved natural gas reserves are estimated quantities which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. The Partnership retained Calhoun, Blair & Associates, Inc., an independent petroleum engineering consulting firm, to provide annual estimates as of December 31 of each year of the Partnership's future net recoverable natural gas reserves. The Partnership has no known reserves of crude oil. There have been no events that have occurred since December 31, 2001 that would have a material effect on the estimated proved developed natural gas reserves.

In accordance with SFAS No. 69 and Securities and Exchange Commission ("SEC") rules and regulations, the following information is presented with regard to the Partnership's gas reserves, all of which are proved, developed and located in the United States.

The SEC has adopted SFAS No. 69 disclosure guidelines for oil and gas producers. These rules require the Partnership to include as a supplement to the basic financial statements a standardized measure of discounted future net cash flows relating to proved oil and gas reserves.

The standardized measure, in management's opinion, should be examined with caution. The basis for these disclosures is an independent petroleum engineer's reserve study which contains imprecise estimates of quantities and rates of production of reserves. Revision of prior year estimates can have a significant impact on the results. Also, exploration and production improvement costs in one year may significantly change previous estimates of proved reserves and their valuation. Values of unproved properties and anticipated future price and cost increases or decreases are not considered. Therefore, the standardized measure is not necessarily a "best estimate" of the fair value of the Partnership's gas properties or of future net cash flows.

F-10

NOTES TO FINANCIAL STATEMENTS--(Continued)

The following summaries of changes in reserves and standardized measure of discounted future net cash flows were prepared from estimates of proved reserves developed by independent petroleum engineers.

Summary of Changes in Proved Developed Reserves

                                                                           Natural Gas (MMCF)
                                                                      ----------------------------
                                                                        2001      2000      1999
                                                                      --------  --------  --------
Estimated quantity, beginning of year................................   54,127    58,209    64,147
Revisions in previous estimates......................................      743     3,012     1,478
Production...........................................................   (6,568)   (7,094)   (7,416)
                                                                      --------  --------  --------
Estimated quantity, end of year......................................   48,302    54,127    58,209
                                                                      ========  ========  ========
Depletion of natural gas properties (per MCF)........................ $   0.31  $   0.24  $   0.24
                                                                      ========  ========  ========
Development costs incurred (in thousands of dollars)................. $    240  $    301  $    332
                                                                      ========  ========  ========
Leasehold acquisitions (in thousands of dollars)..................... $  5,297  $     23  $     16
                                                                      ========  ========  ========

                     Standardized Measure of Discounted Future Net Cash Flows
                                      (Dollars in Thousands)
                                                                        2001      2000      1999
                                                                      --------  --------  --------
Future estimated gross revenues...................................... $117,029  $313,890  $118,516
Future estimated gross production payment (ORRI)*....................       --   (18,613)   (5,353)
Future estimated production and development costs....................  (51,083)  (71,661)  (45,930)
                                                                      --------  --------  --------
Future estimated net revenues........................................   65,946   223,616    67,233
10% annual discount for estimated timing of cash flows...............  (21,220)  (83,613)  (22,851)
                                                                      --------  --------  --------
Standardized measure of discounted future estimated net revenues..... $ 44,726  $140,003  $ 44,382
                                                                      ========  ========  ========
Sales of natural gas produced, net of production costs............... $(21,899) $(20,812) $(11,525)
Net changes in prices and production costs...........................  (89,233)  108,425     8,717
Revisions of previous quantity estimates.............................    3,488     3,964     2,509
Accretion of discount................................................   12,471     3,932     3,627
Other................................................................     (104)      112       445
                                                                      --------  --------  --------
Net change in standardized measure of discounted future estimated net
  revenues........................................................... $(95,277) $ 95,621  $  3,773
                                                                      ========  ========  ========


* The ORRI was acquired during 2001 for $5,270,000. See Note 4 to the Financial Statements.

6. Unaudited Quarterly Financial Data

Quarterly financial data for the last two years (dollars in thousands except per unit data) is summarized as follows:

                         2001 Quarter Ended                        2000 Quarter Ended
              ----------------------------------------- -----------------------------------------
              March 31 June 30 September 30 December 31 March 31 June 30 September 30 December 31
              -------- ------- ------------ ----------- -------- ------- ------------ -----------
Net operating
  revenues... $11,378  $7,014     $4,729      $3,658     $4,161  $5,572     $7,037      $8,412
Net earnings.   9,224   4,830      3,045       1,252      2,638   3,403      5,239       6,682
Net earnings
  per Unit... $  0.85  $ 0.44     $ 0.28      $ 0.12     $ 0.24  $ 0.32     $ 0.48      $ 0.62

F-11

INDEPENDENT AUDITORS' REPORT

The Owners
Republic Royalty Company
and Affiliated Partners of
RRC NPI Holdings, L.P.:

We have audited the accompanying combined balance sheets of Republic Royalty Company (Republic) and RRC NPI Holdings, L.P. (Affiliated Partnership) as of December 31, 2001 and 2000, and the related combined statements of operations, owners' capital, and cash flows for each of the years in the three-year period ended December 31, 2001. These financial statements are the responsibility of Republic's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the combined financial statements referred to above present fairly, in all material respects, the financial position of Republic Royalty Company and Affiliated Partnership as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America.

                                          /s/  KPMG, LLP
                                          -----------------------------
                                          KPMG, LLP
Dallas, Texas
February 8, 2002

F-12

REPUBLIC ROYALTY COMPANY
AND AFFILIATED PARTNERSHIP

COMBINED BALANCE SHEETS
December 31, 2001 and 2000

                                                                     2001         2000
                                                                  -----------  ----------
Assets
Current assets:
   Cash and cash equivalents..................................... $   578,854   1,906,903
   Accounts receivable...........................................   2,286,414   3,808,622
                                                                  -----------  ----------
       Total current assets......................................   2,865,268   5,715,525
                                                                  -----------  ----------
Oil and gas properties, at cost (full-cost method of accounting):
   Proved producing royalty interests............................   6,254,278   6,254,278
   Less accumulated depletion....................................  (3,408,158) (3,109,822)
                                                                  -----------  ----------
       Net oil and gas properties................................   2,846,120   3,144,456
                                                                  -----------  ----------
       Total assets.............................................. $ 5,711,388   8,859,981
                                                                  ===========  ==========
Liabilities and Owners' Capital
Current liabilities:
   Accounts payable.............................................. $   272,829      43,000
   Nonaffiliated ORRI Owner payable..............................   2,254,184   4,813,974
                                                                  -----------  ----------
       Total current liabilities.................................   2,527,013   4,856,974
Owners' capital..................................................   3,184,375   4,003,007
                                                                  -----------  ----------
Contingencies (note 7)...........................................
       Total liabilities and owners' capital..................... $ 5,711,388   8,859,981
                                                                  ===========  ==========

See accompanying notes to combined financial statements.

F-13

REPUBLIC ROYALTY COMPANY
AND AFFILIATED PARTNERSHIP

COMBINED STATEMENTS OF OPERATIONS
Years ended December 31, 2001, 2000, and 1999

                                                   2001      2000      1999
                                                ---------- --------- ---------
Revenues:
   Royalty income.............................. $2,548,775 2,245,534   569,445
   Lease bonus income..........................     21,626    27,678    37,134
   Facilitation amount (note 5)................    604,328   767,313   424,078
   Other income................................     49,390   191,989    15,118
                                                ---------- --------- ---------
       Total revenues..........................  3,224,119 3,232,514 1,045,775
                                                ---------- --------- ---------
Expenses:
   Oil and gas production tax..................    231,123   122,769    58,204
   Depletion expense...........................    298,336   414,634   315,382
   General and administrative expense (note 4).    267,540   227,957   210,346
   Other operating expenses....................    156,817    42,148    14,461
                                                ---------- --------- ---------
       Total expenses..........................    953,816   807,508   598,393
                                                ---------- --------- ---------
       Net income.............................. $2,270,303 2,425,006   447,382
                                                ========== ========= =========

See accompanying notes to combined financial statements.

F-14

REPUBLIC ROYALTY COMPANY
AND AFFILIATED PARTNERSHIP

COMBINED STATEMENTS OF OWNERS' CAPITAL
Years ended December 31, 2001, 2000, and 1999

                                Total
                             -----------
Balance at December 31, 1998 $ 3,931,011
Distributions to owners.....    (637,167)
Net income..................     447,382
                             -----------
Balance at December 31, 1999   3,741,226
Distributions to owners.....  (2,163,225)
Net income..................   2,425,006
                             -----------
Balance at December 31, 2000   4,003,007
Distributions to owners.....  (3,088,935)
Net income..................   2,270,303
                             -----------
Balance at December 31, 2001 $ 3,184,375
                             ===========

See accompanying notes to combined financial statements.

F-15

REPUBLIC ROYALTY COMPANY
AND AFFILIATED PARTNERSHIP

COMBINED STATEMENTS OF CASH FLOWS
Years ended December 31, 2001, 2000, and 1999

                                                                          2001         2000       1999
                                                                       -----------  ----------  ---------
Assets
Cash flow from operating activities:
 Net income........................................................... $ 2,270,303   2,425,006    447,382
 Adjustments to reconcile net income to net cash provided by operating
   activities:
   Depletion expense..................................................     298,336     414,634    315,382
   (Increase) decrease in accounts receivable.........................   1,522,208  (1,791,251)  (950,143)
   Increase (decrease) in accounts and royalty owners payable.........  (2,329,961)  1,944,783  1,520,175
                                                                       -----------  ----------  ---------
       Net cash provided by operating activities......................   1,760,886   2,993,172  1,332,796
Cash flows from financing activities--distribution to owners..........  (3,088,935) (2,163,225)  (637,167)
                                                                       -----------  ----------  ---------
       Net increase (decrease) in cash and cash equivalents...........  (1,328,049)    829,947    695,629
Cash and cash equivalents at beginning of year........................   1,906,903   1,076,956    381,327
                                                                       -----------  ----------  ---------
Cash and cash equivalents at end of year.............................. $   578,854   1,906,903  1,076,956
                                                                       ===========  ==========  =========

See accompanying notes to combined financial statements.

F-16

REPUBLIC ROYALTY COMPANY
AND AFFILIATED PARTNERSHIP

NOTES TO COMBINED FINANCIAL STATEMENTS
December 31, 2001, 2000, and 1999

(1) Organization and Nature of Business

Republic Royalty Company (RRC or the Partnership) is a general partnership formed in September 1993 for the exclusive purpose of acquiring producing and nonproducing mineral and royalty interests and working interests in five exploratory prospects (Properties) from multiple parties. SAM Partners, Ltd. (50% interest) (SAM) and Vaughn Petroleum, Inc. (50% interest) (VPI) are the sole partners of RRC.

Initial capitalization of RRC was comprised of certain contract and management rights of the partners and properties contributed by VPI. Total cash consideration of $61.9 million was paid to the sellers of the Properties, which amount was funded with proceeds derived from the simultaneous sale of Overriding Royalty Interest (ORRI) to certain investors (Nonaffiliated ORRI Owners) and to RRC NPI Holdings, L.P. (Affiliated Partnership or Affiliated ORRI Owner), a limited partnership. RRC is the general partner to the Affiliated Partnership, and various affiliates of SAM and VPI own 100% of the Affiliated Partnership interests. In accordance with the applicable agreements governing these sales (ORRI Conveyance Agreements), RRC receives all revenues and pays all expenses attributable to the Properties and pays amounts to the owners of the ORRI. The ORRI Conveyance Agreements state that the Nonaffiliated ORRI Owners (and/or their successors) and the Affiliated ORRI Owner are entitled to payment of amounts equal to 95.0% and 0.9%, respectively, of Net Proceeds as defined in the ORRI Conveyance Agreements until the aggregate of all payments equals their investment (Payout No. 1), at which time their percentages are reduced to 85.5% and 0.81%. The percentages of Net Proceeds payable to the Affiliated ORRI Owner and the Nonaffiliated ORRI Owners will reduce to 76.95% and 0.73%, respectively, when the aggregate of all payments equals a 14% annual return on their investment (Payout No. 2) as set forth in the ORRI Conveyance Agreements ($83,659,226 at December 31, 2001). Payout No. 1 was reached in August 2000. The percentages remained at 85.5% during 2001.

For the period September 27, 1993 through December 31, 2001, net proceeds distributed to the Nonaffiliated ORRI Owners for purposes of determining payout totaled $82,255,803.

RRC recorded its interest in the Properties at fair values based on the amounts paid by the Nonaffiliated ORRI Owners and the Affiliated Partnership for the ORRI.

(2) Basis of Presentation

The accompanying combined financial statements include the Partnership's share and the Affiliated Partnership's share of revenues, expenses, and distributions for 2001, 2000, and 1999. The revenues, expenses, and amounts payable by and/or due to these parties varied during this time in accordance with the ORRI Conveyance Agreements. Significant interaffiliate balances and transactions have been eliminated in combination. Revenues, expenses, and distributions attributable to the Nonaffiliated ORRI Owners are excluded from the accompanying combined financial statements.

(3) Summary of Significant Accounting Policies

A summary of the significant accounting policies followed by RRC and the Affiliated Partnership is as follows:

(a) Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported

F-17

REPUBLIC ROYALTY COMPANY
AND AFFILIATED PARTNERSHIP

NOTES TO COMBINED FINANCIAL STATEMENTS
December 31, 2001, 2000, and 1999

amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Oil and gas reserve estimates are used in the calculation of depletion expense and the full-cost ceiling limitation for oil and gas properties and are inherently imprecise. Actual results could differ from those estimates.

(b) Capitalization Policy for Oil and Gas Activities

RRC and the Affiliated Partnership utilize the full-cost method of accounting for its oil and gas properties. Under the full cost method, all productive and nonproductive costs incurred in connection with the acquisition, exploration, and development of oil and gas reserves are capitalized and amortized on the units-of-production method based upon total proved reserves of the underlying properties. Conveyances of properties, including gains or losses on abandonments of properties, are treated as adjustments to the cost of oil and gas properties, with no gain or loss recognized.

Under the full cost method, the net book value of oil and gas properties may not exceed the estimated future net revenues from proved oil and gas properties, discounted at 10% per year (the ceiling limitation). In arriving at estimated future net revenues, estimated lease operating expenses, development costs, abandonment costs, and certain production-related and ad valorem taxes are deducted. In calculating future net revenues, prices and costs in effect at the time of the calculation are held constant indefinitely, except for changes which are fixed and determinable by existing contracts. The net book value is compared to the ceiling limitation on an annual basis. The excess, if any, of the net book value above the ceiling limitation is required to be written off as a noncash expense. RRC and the Affiliated Partnership did not incur ceiling limitation writedowns during 2001, 2000, or 1999. There can be no assurance that there will not be writedowns in future periods under the full cost method of accounting as a result of sustained decreases in oil and gas prices or other factors.

(c) Depletion

RRC and the Affiliated ORRI Owner provide for depletion of proved producing oil and gas properties on a unit-of-production method, based upon studies by independent engineers for proved oil and gas reserves.

(d) Cash Equivalents

At December 31, 2001 and 2000, cash equivalents consist of money market accounts ($262,367 and $1,831,934, respectively). RRC and the Affiliated Partnership consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

(e) Concentration of Credit Risk

Accounts receivable balances represent revenue accruals from companies which operate primarily in the oil and gas industry. RRC and the Affiliated Partnership do not require collateral for their receivable balances. RRC and the Affiliated Partnership, as well as the companies they do business with, are subject to fluctuations and trends in the oil and gas industry. Customers that accounted for more than 10% of revenues for the year ended December 31 follow:

Years Customer A Customer B
----- ---------- ----------
2001    18.7%      12.3%
2000    32.5%      9.1%
1999    13.3%      14.8%

F-18

REPUBLIC ROYALTY COMPANY
AND AFFILIATED PARTNERSHIP

NOTES TO COMBINED FINANCIAL STATEMENTS
December 31, 2001, 2000, and 1999

(f) Revenue Recognition

RRC and the Affiliated Partnership use the sales method of accounting for oil and gas revenues. Under the sales method, revenues are recognized based on actual volumes of oil and gas sold to purchasers.

(g) Income Taxes

RRC and the Affiliated Partnership are not subject to federal income taxes because the tax effect of their activities accrues to the partners and owners. Taxable income or loss of RRC and the Affiliated Partnership is allocated to each partner and owner in accordance with the applicable Partnership and ORRI Conveyance Agreements, respectively. Accordingly, there is no provision for federal income taxes reflected in the accompanying combined financial statements.

(h) Derivative Instruments

Effective January 1, 2001, RRC and Affiliated Partnership adopted the provisions of statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (Statement 133). Statement 133, as amended, standardizes the accounting for derivative instruments, including certain derivative instruments embedded in other contracts. Under the standard, entities are required to report all derivative instruments in the statement of financial position at fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, on the reason for holding the instrument. If certain conditions are met, entities may elect to designate a derivative instrument as a hedge of exposures to changes in fair value, cash flows, or foreign currencies. RRC and Affiliated Partnerships held no fair value hedge or foreign currency hedge derivative instruments at December 31, 2001, 2000, or 1999.

(4) Transactions With General Partner

RRC and the Affiliated Partnership incurred general and administrative expense of $267,540, $227,957, and $210,346 for the years ended December 31, 2001, 2000, and 1999, respectively. These amounts are an allocation of SAM's general, administrative, and overhead expenses in accordance with the Partnership agreement.

(5) Facilitation Amount

The Facilitation amount, as described in the ORRI Conveyance Agreements, is a fee for managing the properties and royalty arrangements and is equal to an agreed-upon percentage (4%) of the total annual gross proceeds less certain defined production costs and is deducted from distributions to royalty owners. For 2001, 2000, and 1999, the total Facilitation amounts were $706,816, $839,879, and $446,398 respectively. Payments to the ORRI owners are adjusted for the Facilitation amount as set forth in the ORRI Conveyance Agreements; accordingly, RRC and the Affiliated ORRI Owner's share of the amounts for 2001, 2000, and 1999 were $604,328, $767,313, and $424,078, respectively. Pursuant to the full cost method of accounting, these fees are recognized as income provided the aggregate development expenditures related to production of existing proved reserves on managed properties does not exceed 10% of the partnership's recorded cost of such managed properties. Aggregate development expenditures during 2001, 2000, and 1999 did not exceed the 10% threshold. Accordingly, the Facilitation amount is recorded as income in the combined statement of operations for fiscal years 2001, 2000, and 1999.

F-19

REPUBLIC ROYALTY COMPANY
AND AFFILIATED PARTNERSHIP

NOTES TO COMBINED FINANCIAL STATEMENTS
December 31, 2001, 2000, and 1999

(6) Owners' Capital

Revenues and expenses are allocated to the partners and owners in accordance with their respective sharing percentages.

On a monthly basis, all cash funds of RRC which the general partner reasonably determines are not needed for the payment of existing or foreseeable (within 60 days) Partnership obligations and expenditures are distributed to the partners in accordance with their respective sharing percentages.

As provided in the Partnership agreement, upon liquidation, gains or losses from the sale of Partnership properties will be allocated to the partners utilizing their respective sharing percentages.

(7) Litigation Settlements

RRC is or was a party to litigation concerning various contracts and other claims. RRC and the Affiliated Partnership's share of proceeds from litigation settlements and awards (included in other income) during the years ended 2001, 2000, and 1999 was $5,737, $178,825, and $9,321, respectively.

(8) Commitments and Contingencies

In the normal course of business, RRC and the Affiliated Partnership are involved in various lawsuits and claims related to their royalty properties. In the opinion of RRC's management, the ultimate resolution of such matters will not have a material adverse effect on the combined financial position or results of operations of RRC and Affiliated Partnership.

(9) Recent Accounting Pronouncements

In July 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 141, Business Combinations, and No. 142, Goodwill and Other Intangible Assets. Statement 141 requires that all business combinations initiated after June 30, 2001 be accounted for under the purchase method, and Statement 142 requires that goodwill no longer be amortized to earnings, but instead be reviewed for impairment. RRC and the Affiliated Partnership believe there is no impact of adopting this standard on their financial statements.

In June 2001, the FASB issued Statement No. 143, Accounting for Asset Retirement Obligations, which establishes requirements for the accounting of removal-type costs associated with asset retirements. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. RRC and the Affiliated Partnership are currently assessing the impact on their financial statements.

In August 2001, the FASB issued Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which establishes requirements for the accounting for the impairment or disposal of long-lived assets. The standard is effective for fiscal years beginning after December 15, 2001. RRC and Affiliated Partnership believe there will be no impact on their financial statements from adopting this standard.

(10) Supplemental Oil and Gas Data--Unaudited

Proved crude oil and natural gas reserves are estimated quantities, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing

F-20

REPUBLIC ROYALTY COMPANY
AND AFFILIATED PARTNERSHIP

NOTES TO COMBINED FINANCIAL STATEMENTS
December 31, 2001, 2000, and 1999

economic and operating conditions. The Partnership retained an independent petroleum engineering consulting firm to provide annual estimates as of December 31 of each year of RRC and the Affiliated Partnership's future net recoverable crude oil and natural gas reserves for the underlying properties burdened by the ORRI.

The following table presents RRC and the Affiliated Partnership's estimate of their proved oil and gas reserves, all of which are located in the United States. RRC and the Affiliated Partnership emphasize that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, the estimates are expected to change as future information becomes available. The estimates have been prepared by RRC and the Affiliated Partnership's independent petroleum reservoir engineers.

Estimates of reserves attributable to RRC and Affiliated Partnership are shown below using the regulations issued by the Securities and Exchange Commission; however, there is no precise method of allocating estimates of physical quantities of reserves between RRC and Affiliated Partnership and the Unaffiliated ORRI Owner, since the royalty received by the ORRI owners is a net proceeds ORRI interest, and the ORRI owners do not own, and are not entitled to receive, any specific volume of reserves. Net reserves attributable to the net royalties were estimated by allocating to RRC and the Affiliated Partnership a 20% portion of the estimated combined net reserves of the subject royalties based on an expected Payout No. 2 being reached in 2002 (see note 1). The quantities of reserves indicated will be affected by future changes in various economic factors utilized in estimating future gross revenues and net income from the subject royalties. Therefore, the estimates of reserves set forth below are to a large extent hypothetical and are not comparable to estimates of reserves attributable to a working interest.

                                     Gross underlying royalties Net royalties
                                     -------------------------- ------------
                                                        Gas      Oil   Gas
                                     Oil MBbls          MMcf    MBbls  MMcf
                                     ---------         ------   -----  -----
Estimated balance, December 31, 1998   3,895         21,901      778   4,380
Revisions in previous estimates.....     200          3,653       41     698
Production..........................    (307)        (2,396)     (61)   (446)
                                       -----           ------    ---   -----
Estimated balance, December 31, 1999   3,788         23,158      758   4,632
Revisions in previous estimates.....      (3)          (450)      (1)   (140)
Production..........................    (294)        (3,742)     (59)   (699)
                                       -----           ------    ---   -----
Estimated balance, December 31, 2000   3,491         18,966      698   3,793
Revisions in previous estimates.....     188          3,905       37     757
Production..........................    (278)        (2,717)     (55)   (519)
                                       -----           ------    ---   -----
Estimated balance, December 31, 2001   3,401         20,154      680   4,031
                                       =====           ======    ===   =====

Oil reserves, which include condensate, are stated in thousands of barrels and gas reserves, which include natural gas products, are stated in millions of cubic feet.

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves--Unaudited

The following table, which presents a standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves, is presented pursuant to SFAS No. 69, Disclosure About Oil and

F-21

REPUBLIC ROYALTY COMPANY
AND AFFILIATED PARTNERSHIP

NOTES TO COMBINED FINANCIAL STATEMENTS
December 31, 2001, 2000, and 1999

Gas Producing Activities. In computing this data, assumptions other than those required by this accounting standard could produce different results. Accordingly, the data should not be construed as representative of the fair value of RRC and the Affiliated Partnership's proved oil and gas reserves.

Future cash inflows were computed by applying year end prices of oil and gas to the estimated year end quantities of proved reserves. Future price changes were considered only to the extent provided by contractual arrangements in existence at year end. Future production costs were computed by estimating the expenditures to be incurred in producing the proved oil and gas reserves at the end of the year, based on year-end costs. The standardized measure of discounted future cash flows represents the present value of estimated future net cash flows using a 10% annual discount rate (in thousands).

                                                                         December 31,
                                                                 ----------------------------
                                                                   2001      2000      1999
                                                                 --------  --------  --------
Future estimated gross revenues................................. $109,736   269,689   140,830
Net proceeds interest to unaffiliated ORRI owner................  (87,789) (215,859) (112,776)
Future estimated production taxes...............................   (1,689)   (4,346)   (2,402)
                                                                 ========  ========  ========
Future estimated net revenues...................................   20,258    49,484    25,652
Discount at 10% per annum.......................................  (10,240)  (23,672)  (12,655)
                                                                 ========  ========  ========
Standardized measure of discounted future estimated net revenues $ 10,018    25,812    12,997
                                                                 ========  ========  ========
Beginning of year:.............................................. $ 25,812    12,997     7,220
   Sales of oil and gas, net of production costs................   (2,318)   (2,123)     (511)
   Net changes in prices and production costs...................  (14,913)   18,847     5,750
   Revisions of previous quantity estimates.....................    1,277      (447)    1,354
   Accretion of discount........................................    2,581     1,299       722
   Other........................................................   (2,421)   (4,761)   (1,538)
                                                                 --------  --------  --------
End of year..................................................... $ 10,018    25,812    12,997
                                                                 ========  ========  ========

Depletion expense per barrel of oil equivalent was $2.11, $1.88, and $2.33 for the years ended December 31, 2001, 2000, and 1999, respectively.

F-22

INDEPENDENT AUDITORS' REPORT

Republic Unaffiliated ORRI Owners:

We have audited the accompanying balance sheets of Republic Unaffiliated ORRI Owners (Royalty Owners) as of December 31, 2001 and 2000, and the related statements of operations, ORRI owner' equity, and cash flows for each of the years in the three-year period ended December 31, 2001. The financial statements are the responsibility of Royalty Owners' management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statement referred to above present fairly, in all material respects, the financial position of Republic Unaffiliated ORRI Owners as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America.

                                          /s/  KPMG, LLP
                                          -----------------------------
                                          KPMG, LLP
Dallas, Texas
February 8, 2002

F-23

REPUBLIC UNAFFILIATED ORRI OWNERS

BALANCE SHEETS
December 31, 2001 and 2000

                                                                      2001         2000
                                                                  ------------  -----------
Assets
Current assets--accounts receivable.............................. $  2,254,184    4,813,974
Oil and gas properties, at cost (full-cost method of accounting):
   Proved producing royalty interests............................   64,961,084   64,961,084
   Less accumulated depletion....................................  (35,367,520) (32,265,460)
                                                                  ------------  -----------
       Net oil and gas properties................................   29,593,564   32,695,624
                                                                  ------------  -----------
       Total assets.............................................. $ 31,847,748   37,509,598
                                                                  ============  ===========
Liabilities and ORRI Owners' Equity
Current liabilities--accounts payable............................ $    233,269       30,147
ORRI owner' equity...............................................   31,614,479   37,479,451
Contingencies (note 7)
                                                                  ------------  -----------
   Total liabilities and ORRI owner' equity...................... $ 31,847,748   37,509,598
                                                                  ============  ===========

See accompanying notes to financial statements.

F-24

REPUBLIC UNAFFILIATED ORRI OWNERS

STATEMENTS OF OPERATIONS
Years ended December 31, 2001, 2000, and 1999

                                    2001        2000       1999
                                 ----------- ---------- ----------
Revenues:
   Royalty income............... $15,218,396 20,346,216 11,017,583
   Lease bonus income...........     127,519    292,669    705,544
   Other income.................     291,228  2,030,107    287,255
                                 ----------- ---------- ----------
       Total revenues...........  15,637,143 22,668,992 12,010,382
                                 ----------- ---------- ----------
Expenses:
   Oil and gas production tax...   1,520,081  1,356,557  1,367,959
   Facilitation amount (note 4).     604,328    767,313    424,078
   Depletion....................   3,102,060  4,311,307  3,279,299
   Other operating expenses.....     775,975    390,247    210,807
                                 ----------- ---------- ----------
       Total expenses...........   6,002,444  6,825,424  5,282,143
                                 ----------- ---------- ----------
       Net income............... $ 9,634,699 15,843,568  6,728,239
                                 =========== ========== ==========

See accompanying notes to financial statements.

F-25

REPUBLIC UNAFFILIATED ORRI OWNERS

STATEMENTS OF ORRI OWNERS' EQUITY
Years ended December 31, 2001, 2000, and 1999

Balance at December 31, 1998.......................... $ 41,334,130
Distributions to ORRI owners..........................   (8,191,540)
Net income............................................    6,728,239
                                                       ------------
Balance at December 31, 1999..........................   39,870,829
Distributions to ORRI owners..........................  (18,234,946)
Net income............................................   15,843,568
                                                       ------------
Balance at December 31, 2000..........................   37,479,451
Distributions to ORRI owners..........................  (15,499,671)
Net income............................................    9,634,699
                                                       ------------
Balance at December 31, 2001.......................... $ 31,614,479
                                                       ============

See accompanying notes to financial statements.

F-26

REPUBLIC UNAFFILIATED ORRI OWNERS

STATEMENTS OF CASH FLOWS
Years ended December 31, 2001, 2000, and 1999

                                                                    2001         2000         1999
                                                                ------------  -----------  ----------
Cash flows from operating activities:
   Net income.................................................. $  9,634,699   15,843,568   6,728,239
   Adjustments to reconcile net income to net cash provided by
     operating activities:
       Depletion...............................................    3,102,060    4,311,307   3,279,299
       (Increase) decrease in accounts receivable..............    2,559,790   (1,926,550) (1,671,879)
       Increase (decrease) in accounts payable and accrued
         expenses..............................................      203,122        6,621    (144,119)
                                                                ------------  -----------  ----------
          Net cash provided by operating activities............   15,499,671   18,234,946   8,191,540
Cash flows from financing activities--distributions to
  ORRI owners..................................................  (15,499,671) (18,234,946) (8,191,540)
                                                                ------------  -----------  ----------
          Net increase (decrease) in cash......................           --           --          --
Cash at beginning of year......................................           --           --          --
                                                                ------------  -----------  ----------
Cash at end of year............................................ $         --           --          --
                                                                ============  ===========  ==========

See accompanying notes to financial statements.

F-27

REPUBLIC UNAFFILIATED ORRI OWNERS

NOTES TO FINANCIAL STATEMENT

December 31, 2001, 2000, and 1999

(1) Organization and Nature of Business

Effective September 27, 1993, certain investors (Republic Unaffiliated ORRI Owners) represented by UBS Asset Management (New York) Inc. acquired a net proceeds overriding royalty interest (ORRI) in certain oil and gas minerals owned by Republic Royalty Company (RRC) pursuant to an ORRI Conveyance Agreement (Agreement).

(2) Basis of Presentation

The accompanying financial statements include the Republic Unaffiliated ORRI Owners' share of the acquired overriding royalty interests and related revenues and expenses.

The Agreement provides for the establishment of a net proceeds account for the purpose of providing a means of computing the amount of the net proceeds overriding royalty interest payments due to the Republic Unaffiliated ORRI Owners from RRC in connection with the Agreement. Generally, the net proceeds account is increased for all cash generated from the subject minerals, as defined in the Agreement (gross proceeds) and decreased for direct operating costs and certain additional costs (production costs).

Cash is distributed as received by the Republic Unaffiliated ORRI Owners to its group members; accordingly, there is no cash balance maintained.

(3) Summary of Significant Accounting Policies

A summary of the significant accounting policies followed by Republic Unaffiliated ORRI Owners are as follows:

(a) Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Oil and gas reserve estimates are used in the calculation of depletion expense and the full-cost ceiling limitation for oil and gas properties and are inherently imprecise. Actual results could differ from those estimates.

(b) Capitalization Policy for Oil and Gas Activities

Republic Unaffiliated ORRI Owners utilize the full cost method of accounting for its ORRI. Under the full cost method, all productive and nonproductive costs incurred in connection with the acquisition, exploration, and development of crude oil and natural gas reserves are capitalized and amortized on the units-of-production method based upon total proved reserves of the underlying properties. Conveyances of properties, including gains or losses on abandonments of properties, are treated as adjustments to the cost of crude oil and natural gas properties, with no gain or loss recognized.

Under the full cost method, the net book value of the ORRI, may not exceed the estimated future net revenues from proved oil and natural gas properties, discounted at 10% per year (the ceiling limitation). In arriving at estimated future net revenues, estimated lease operating expenses, development costs, abandonment

F-28

REPUBLIC UNAFFILIATED ORRI OWNERS

NOTES TO FINANCIAL STATEMENT

December 31, 2001, 2000, and 1999

costs, and certain production related and ad-valorem taxes are deducted. In calculating future net revenues, prices and costs in effect at the time of the calculation are held constant indefinitely, except for changes which are fixed and determinable by existing contracts. The net book value is compared to the ceiling limitation on an annual basis. The excess, if any, of the net book value above the ceiling limitation is required to be written off as a noncash expense. Republic Unaffiliated ORRI Owners did not incur ceiling limitation writedowns during 2001, 2000, or 1999. There can be no assurance that there will not be writedowns in future periods under the full cost method of accounting as a result of sustained decrease in oil and natural gas prices or other factors.

(c) Depletion

Republic Unaffiliated ORRI Owners provide for depletion of the proved producing royalty interest on a unit-of-production method, based upon studies by independent engineers of the proved oil and gas reserves burdened by the net proceeds ORRI.

(d) Concentration of Credit Risk

Accounts receivable balances represent revenue accruals from companies (flow through from RRC) which operate primarily in the oil and gas industry. Republic Unaffiliated ORRI Owners do not require collateral for its receivable balances. Republic Unaffiliated ORRI Owners as well as the companies it does business with are subject to fluctuations and trends in the oil and gas industry. Customers that accounted for more than 10% of revenues for the year ended December 31, follows:

Year Customer A Customer B
---- ---------- ----------
2001   18.7%      12.3%
2000   32.5%       9.1%
1999   13.3%      14.8%

(e) Revenue Recognition

Republic Unaffiliated ORRI Owners use the sales method of accounting for oil and gas revenues. Under the sales method, revenues are recognized based on actual volumes of oil and gas sold to purchasers.

(f) Income Taxes

Republic Unaffiliated ORRI Owners are not subject to federal income taxes because the tax effect of its activities accrues to the individual owners. Taxable income or loss of Republic Unaffiliated ORRI Owners is allocated to each ORRI owner in accordance with their respective ownership percentages. Accordingly, there is no provision for income taxes reflected in the accompanying financial statements.

(g) Derivative Instruments

Effective January 1, 2001, Republic Unaffiliated ORRI Owners adopted the provisions of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (Statement 133). Statement 133, as amended, standardizes the accounting for derivative instruments, including certain derivative instruments embedded in other contracts. Under the standard, entities are required to report all derivative instruments in the statement of financial position at fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as

F-29

REPUBLIC UNAFFILIATED ORRI OWNERS

NOTES TO FINANCIAL STATEMENT

December 31, 2001, 2000, and 1999

a part of a hedging relationship and, if so, on the reason for holding the instrument. If certain conditions are met, entities may elect to designate a derivative instrument as a hedge of exposures to changes in fair value, cash flows, or foreign currencies. Republic Unaffiliated ORRI Owners held no fair value hedge or foreign currency hedge derivative instruments at December 31, 2001, 2000, or 1999.

(4) Facilitation Amount

The Facilitation amount, as described in the Agreement, is a fee paid for managing the properties and royalty arrangements and is equal to an agreed-upon percentage (4%) of the total annual gross proceeds less certain defined production costs and is deducted from distributions to Republic Unaffiliated ORRI Owners. For 2001, 2000, and 1999 the total Facilitation amounts were $706,816, $839,879, and $446,398, respectively, and Republic Unaffiliated ORRI Owners' portion was $604,328, $767,313, and $424,078, respectively.

(5) Distributions and Payout

RRC is required to distribute to the Republic Unaffiliated ORRI Owners within ten days of each month end an amount equal to the Republic Unaffiliated ORRI Owners percentage share. The proceeds percentage is 95% until payout no. 1 is reached, 85.5% after payout no. 1 is reached but before payout no. 2 is reached and 76.95% after payout no. 2 is reached.

Payout no. 1 was reached when the Republic Unaffiliated ORRI Owners were repaid their invested capital at the time of the acquisition, which occurred in August of 2000. Payout no. 2 is reached when the aggregate payments to the Republic Unaffiliated ORRI Owners are equal to their invested capital plus an internal rate of return of 14% ($83,659,226 at December 31, 2001). The percentage remained at 85.5% during 2001.

The initial capital investment paid by the Republic Unaffiliated ORRI Owners totaled $61,288,810. For the period September 27, 1993 (inception) through December 31, 2001, net proceeds distributed to the Republic Unaffiliated ORRI Owners for purposes of determining payout totaled $82,255,803.

(6) Litigation Settlements

RRC is or was a party to litigation concerning various contracts and other claims. The Republic Unaffiliated ORRI Owners' share of proceeds from litigation settlements and awards (included in other income) during 2001, 2000, and 1999 are $6,349, $1,890,909, and $186,590, respectively.

(7) Commitments and Contingencies

In the normal course of business, RRC is involved in various lawsuits and claims, related to its Royalty properties. In the opinion of RRC's management, the ultimate resolution of such matters will not have a material adverse effect on the financial position or results of operations of RRC or the ORRI interests.

(8) Recent Accounting Pronouncements

In July 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 141, Business Combinations, and No. 142, Goodwill and Other Intangible Assets. Statement 141 requires that all business combinations initiated after June 30, 2001 be accounted for under the purchase method, and Statement 142 requires that goodwill no longer be amortized to earnings, but instead be reviewed for impairment. Republic Unaffiliated ORRI Owners believe there is no current impact on their financial statements.

F-30

REPUBLIC UNAFFILIATED ORRI OWNERS

NOTES TO FINANCIAL STATEMENT

December 31, 2001, 2000, and 1999

In June 2001, the FASB issued Statement No. 143, Accounting for Asset Retirement Obligations, which establishes requirements for the accounting of removal-type costs associated with asset retirements. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. Republic Unaffiliated ORRI Owners are currently assessing the impact on their financial statements.

In August 2001, the FASB issued Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which establishes requirements for the accounting for the impairment or disposal of long-lived assets. The standard is effective for fiscal years beginning after December 15, 2001. Republic Unaffiliated ORRI Owners believe there will be no impact on their financial statements from adopting this standard.

(9) Supplemental Oil and Gas Data--Unaudited

Proved oil and gas reserves are estimated quantities, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Republic Unaffiliated ORRI Owners retained an independent petroleum engineering consulting firm to provide annual estimates as of December 31 of each year of Republic Unaffiliated ORRI Owner's future net recoverable oil and gas reserves for the underlying properties burdened by the ORRI.

The following table presents Republic Unaffiliated ORRI Owners' estimate of its proved oil and gas reserves underlying its ORRI, all of which are located in the United States. Republic Unaffiliated ORRI Owners emphasize that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, the estimates are expected to change as future information becomes available. The estimates have been prepared by Republic Royalty Company's independent petroleum reservoir engineers.

Estimates of reserves attributable to Republic Unaffiliated ORRI Owner are shown below using the regulations issued by the Securities and Exchange Commission; however, there is no precise method of allocating estimates of physical quantities of reserves between RRC and Republic Unaffiliated ORRI Owner, since the royalty received by Republic Unaffiliated ORRI Owners is a net proceeds ORRI, and Republic Unaffiliated ORRI Owners does not own, and is not entitled to receive, any specific volume of reserves. Net reserves attributable to the net royalties were estimated by allocating Republic Unaffiliated ORRI Owners an 80% portion of the estimated combined net reserves of the subject royalties based on an expected Payout No. 2 being reached in 2002 (see note 5). The quantities of reserves indicated will be affected by future changes in various economic factors utilized in estimating future gross revenues and net income from the subject royalties. Therefore, the estimates of reserves set forth below attributable to the ORRI are to a large extent hypothetical and are not comparable to estimates of reserves attributable to a working interest.

F-31

REPUBLIC UNAFFILIATED ORRI OWNERS

NOTES TO FINANCIAL STATEMENT

December 31, 2001, 2000, and 1999

                                Gross underlying
                                   royalties     Net royalties
                                ---------------  -------------
                                 Oil      Gas     Oil    Gas
                                MBbls     MMcf   MBbls   MMcf
                                -----    ------  -----  ------
Balance December 31, 1998...... 3,895    21,901  3,117  17,521
Revisions in previous estimates   200     3,653    159   2,955
Production.....................  (307)   (2,396)  (246) (1,950)
                                -----    ------  -----  ------
Balance December 31, 1999...... 3,788    23,158  3,030  18,526
Revisions in previous estimates    (3)     (450)    (2)   (310)
Production.....................  (294)   (3,742)  (235) (3,043)
                                -----    ------  -----  ------
Balance December 31, 2000...... 3,491    18,966  2,793  15,173
Revisions in previous estimates   188     3,905    151   3,148
Production.....................  (278)   (2,717)  (223) (2,198)
                                -----    ------  -----  ------
Balance December 31, 2001...... 3,401    20,154  2,721  16,123
                                =====    ======  =====  ======

Oil reserves, which include condensate, are stated in thousands of barrels and gas reserves, which include natural gas liquids, are stated in millions of cubic feet.

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves--Unaudited

The following table, which presents a standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves, is presented pursuant to SFAS No. 69, Disclosures About Oil and Gas Producing Activities. In computing this data, assumptions other than those required by this accounting standard could produce different results. Accordingly, the data should not be construed as representative of the fair value of Republic Unaffiliated ORRI Owners' proved oil and gas reserves.

Future cash inflows were computed by applying year-end prices of oil and gas to the estimated year end quantities of proved reserves. Future price changes were considered only to the extent provided by contractual arrangements in existence at year end. Future production costs were computed by estimating the expenditures to be incurred in producing the proved oil and gas reserves at the end of the year, based on year end costs. The standardized measure of discounted future cash flows represents the present value of estimated future net cash flows using a 10% annual discount rate (in thousands). The Facilitation amount is not considered in the calculation of future net revenues.

F-32

REPUBLIC UNAFFILIATED ORRI OWNERS

NOTES TO FINANCIAL STATEMENT

December 31, 2001, 2000, and 1999

                                                        2001     2000     1999
                                                      --------  -------  -------
Future estimated gross revenues...................... $ 87,789  215,321  112,215
Future estimated production taxes....................   (6,758) (17,383)  (9,606)
                                                      --------  -------  -------
Future estimated net revenues........................   81,031  197,938  102,609
Discount at 10% per annum............................  (40,958) (94,689) (50,622)
                                                      --------  -------  -------
Standardized measure of future estimated net revenues $ 40,073  103,249   51,987
                                                      ========  =======  =======
Beginning of year.................................... $103,249   51,987   28,880
   Sales of oil and gas, net of production costs.....  (13,698) (18,990)  (9,650)
   Net changes in prices and production costs........  (59,651)  59,388   23,000
   Revisions of previous quantity estimates..........    5,107   (1,786)   5,414
   Accretion of discount.............................   10,325    5,199    2,888
   Other.............................................   (5,259)   7,451    1,455
                                                      --------  -------  -------
End of year.......................................... $ 40,073  103,249   51,987
                                                      ========  =======  =======

Depletion expense per barrel of oil equivalent was $5.27, $5.81, and $5.74 for the years ended December 31, 2001, 2000, and 1999, respectively.

F-33

INDEPENDENT AUDITORS' REPORT

The Partners
Spinnaker Royalty Company, L.P.:

We have audited the accompanying balance sheets of Spinnaker Royalty Company, L.P. (the Partnership) as of December 31, 2001 and 2000, and the related statements of operations, partners' capital, and cash flows for each of the years in the three-year period ended December 31, 2001. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Spinnaker Royalty Company, L.P. as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America.

                                          /s/  KPMG, LLP
                                          -----------------------------
                                          KPMG, LLP
Dallas, Texas
February 8, 2002

F-34

SPINNAKER ROYALTY COMPANY, L.P.

BALANCE SHEETS
December 31, 2001 and 2000

                                                                      2001         2000
                                                                  ------------  -----------
Assets
Current assets:
   Cash and cash equivalents..................................... $    371,000    1,049,000
   Accounts receivable...........................................      978,000    2,278,000
                                                                  ------------  -----------
       Total current assets......................................    1,349,000    3,327,000
                                                                  ------------  -----------
Oil and gas properties, at cost (full-cost method of accounting):
   Proved and producing royalty interests........................   30,263,000   30,263,000
   Unproved royalty interests....................................      238,000      238,000
                                                                  ------------  -----------
                                                                    30,501,000   30,501,000
   Less accumulated depletion....................................  (17,845,000) (16,403,000)
                                                                  ------------  -----------
       Net oil and gas properties................................   12,656,000   14,098,000
                                                                  ------------  -----------
       Total assets.............................................. $ 14,005,000   17,425,000
                                                                  ============  ===========
Liabilities and Partners' Capital
Current liabilities--accounts payable and accrued expenses....... $    150,000      103,000
                                                                  ============  ===========
Partners' capital:
          General partner........................................     (303,000)    (132,000)
          Limited partner........................................   14,158,000   17,454,000
                                                                  ------------  -----------
       Total partners' capital...................................   13,855,000   17,322,000
                                                                  ------------  -----------
Contingencies (note 6)...........................................
                                                                  ------------  -----------
       Total liabilities and partners' capital................... $ 14,005,000   17,425,000
                                                                  ============  ===========

See accompanying notes to financial statements.

F-35

SPINNAKER ROYALTY COMPANY, L.P.

STATEMENTS OF OPERATIONS
Years ended December 31, 2001, 2000, and 1999

                                    2001        2000      1999
                                 ----------- ---------- ---------
Revenues:
   Royalty income............... $10,871,000 11,963,000 8,607,000
   Lease bonus income...........      34,000    166,000     2,000
   Interest and other income....      39,000     83,000    43,000
                                 ----------- ---------- ---------
       Total revenues...........  10,944,000 12,212,000 8,652,000
                                 ----------- ---------- ---------
Expenses:
   Oil and gas production taxes.     827,000    663,000   554,000
   Depletion....................   1,442,000  2,025,000 2,376,000
   Management expense (note 3)..     306,000    267,000   239,000
   Other operating expenses.....     307,000    101,000   118,000
                                 ----------- ---------- ---------
       Total expenses...........   2,882,000  3,056,000 3,287,000
                                 ----------- ---------- ---------
       Net income............... $ 8,062,000  9,156,000 5,365,000
                                 =========== ========== =========

See accompanying notes to financial statements.

F-36

SPINNAKER ROYALTY COMPANY, L.P.

STATEMENTS OF PARTNERS' CAPITAL
Years ended December 31, 2001, 2000, and 1999

                               Limited     General
                               partners    partner      Total
                             ------------  --------  -----------
Balance at December 31, 1998 $ 20,138,000     7,000   20,145,000
Distribution to partners....   (7,002,000) (365,000)  (7,367,000)
Net income..................    5,099,000   266,000    5,365,000
                             ------------  --------  -----------
Balance at December 31, 1999   18,235,000   (92,000)  18,143,000
Distribution to partners....   (9,483,000) (494,000)  (9,977,000)
Net income..................    8,702,000   454,000    9,156,000
                             ------------  --------  -----------
Balance at December 31, 2000   17,454,000  (132,000)  17,322,000
Distribution to partners....  (10,958,000) (571,000) (11,529,000)
Net income..................    7,662,000   400,000    8,062,000
                             ------------  --------  -----------
Balance at December 31, 2001 $ 14,158,000  (303,000)  13,855,000
                             ============  ========  ===========

See accompanying notes to financial statements.

F-37

SPINNAKER ROYALTY COMPANY, L.P.

STATEMENTS OF CASH FLOWS
Years ended December 31, 2001, 2000, and 1999

                                                                     2001         2000        1999
                                                                 ------------  ----------  ----------
Assets
Cash flow from operating activities:
 Net income..................................................... $  8,062,000   9,156,000   5,365,000
 Adjustments to reconcile net income to net cash provided by
   operating activities:
   Depletion expense............................................    1,442,000   2,025,000   2,376,000
   (Increase) decrease in accounts receivable...................    1,300,000    (987,000)   (130,000)
   Increase (decrease) in accounts payable and accrued expenses.       47,000      45,000     (36,000)
                                                                 ------------  ----------  ----------
       Net cash provided by operating activities................   10,851,000  10,239,000   7,575,000
Cash flows from financing activities--distributions to partners.  (11,529,000) (9,977,000) (7,367,000)
                                                                 ------------  ----------  ----------
       Net increase (decrease) in cash and cash equivalents.....     (678,000)    262,000     208,000
Cash and cash equivalents at beginning of year..................    1,049,000     787,000     579,000
                                                                 ------------  ----------  ----------
Cash and cash equivalents at end of year........................ $    371,000   1,049,000     787,000
                                                                 ============  ==========  ==========

See accompanying notes to financial statements.

F-38

SPINNAKER ROYALTY COMPANY, L.P.

NOTES TO FINANCIAL STATEMENT
December 31, 2001, 2000, and 1999

(1) Organization and Nature of Business

On September 4, 1997, Spinnaker Royalty Company and others formed Spinnaker Royalty Company, L.P. (the Partnership) by contributing certain oil and gas mineral and royalty interests to the Partnership. Smith Allen Oil & Gas, Inc., is the Partnership's general partner. The primary business of the Partnership is to acquire, own, and manage oil and gas properties.

(2) Summary of Significant Accounting Policies

A summary of the significant accounting policies followed by the Partnership is as follows:

(a) Capitalization Policy for Oil and Gas Activities

The Partnership utilizes the full cost method of accounting for its oil and gas properties. Under the full cost method, all productive and nonproductive costs incurred in connection with the acquisition, exploration, and development of oil and gas reserves are capitalized and amortized on the units-of-production method based upon total proved reserves. Conveyances of properties, including gains or losses on abandonments of properties, are treated as adjustments to the cost of oil and gas properties, with no gain or loss recognized.

Under the full cost method, the net book value of oil and gas properties may not exceed the estimated future net revenues from proved oil and gas properties, discounted at 10% per year (the ceiling limitation). In arriving at estimated future net revenues, estimated lease operating expenses, development costs, abandonment costs, and certain production-related and ad-valorem taxes are deducted. In calculating future net revenues, prices and costs in effect at the time of the calculation are held constant indefinitely, except for changes which are fixed and determinable by existing contracts. The net book value is compared to the ceiling limitation on an annual basis. The excess, if any, of the net book value above the ceiling limitation is required to be written off as a noncash expense. The Partnership did not incur ceiling limitation writedowns during 2001, 2000 and 1999. There can be no assurance that there will not be writedowns in future periods under the full cost method of accounting as a result of sustained decreases in oil and gas prices or other factors.

(b) Depletion

The Partnership provides for depletion of proved and producing oil and gas properties on a unit-of-production method, based upon studies by independent engineers for proved oil and gas reserves.

(c) Cash Equivalents

At December 31, 2001 and 2000, cash equivalents consist of money market accounts ($233,000 and $998,000, respectively). The Partnership considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

(d) Revenue Recognition

The Partnership uses the sales method of accounting for oil and gas revenues. Under the sales method, revenues are recognized based on actual volumes of oil and gas sold to purchasers.

F-39

SPINNAKER ROYALTY COMPANY, L.P.

NOTES TO FINANCIAL STATEMENT
December 31, 2001, 2000, and 1999

(e) Concentration of Credit Risk

Accounts receivable balances represent revenue accruals from companies which operate primarily in the oil and gas industry. The Partnership does not require collateral for its receivable balances. The Partnership as well as the companies it does business with are subject to fluctuations and trends in the oil and gas industry. Customers that accounted for more than 10% of revenues for the periods are presented as follows:

Year Customer A Customer B Customer C
---- ---------- ---------- ----------
2001    18%        11%        23%
2000    23%        38%        --
1999    24%        33%        --

(f) Income Taxes

The Partnership is not subject to federal income taxes because the tax effect of its activities accrues to the partners. Taxable income or loss of the Partnership is allocated to each partner in accordance with the Partnership agreement. Accordingly, there is no provision for income taxes reflected in the accompanying financial statements.

(g) Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Oil and gas reserve estimates are used in the calculation of depletion expense and the full-cost ceiling limitation for oil and gas properties and are inherently imprecise. Actual results could differ from those estimates.

(h) Derivative Instruments

Effective January 1, 2001, the Partnership adopted the provisions of statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (Statement 133). Statement 133, as amended, standardizes the accounting for derivative instruments, including certain derivative instruments embedded in other contracts. Under the standard, entities are required to report all derivative instruments in the statement of financial position at fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, on the reason for holding the instrument. If certain conditions are met, entities may elect to designate a derivative instrument as a hedge of exposures to changes in fair value, cash flows, or foreign currencies. The Partnership held no fair value hedge or foreign currency hedge derivative instruments at December 31, 2001, 2000, or 1999.

(3) Transactions With General Partner

Management expense represents reimbursement to the general partner for allocated general, administrative, and overhead expenses in accordance with the Partnership agreement.

(4) Partners' Capital

As provided in the Partnership agreement, revenues and expenses are allocated to the partners in accordance with their respective sharing percentages. The General Partner has a 4.96% ownership interest in the Partnership.

F-40

SPINNAKER ROYALTY COMPANY, L.P.

NOTES TO FINANCIAL STATEMENT
December 31, 2001, 2000, and 1999

On a monthly basis, all cash funds of the Partnership which the general partner reasonably determines are not needed for the payment of existing or foreseeable (within 60 days) Partnership obligations and expenditures are distributed to the partners in accordance with their respective sharing percentages.

As provided in the Partnership agreement, upon liquidation, gains or losses from the sale of Partnership property will be allocated to the partners utilizing their respective sharing percentages.

(5) Recent Accounting Pronouncements

In July 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 141, Business Combinations, and No. 142, Goodwill and Other Intangible Assets. Statement 141 requires that all business combinations initiated after June 30, 2001 be accounted for under the purchase method, and Statement 142 requires that goodwill no longer be amortized to earnings, but instead be reviewed for impairment. The Partnership is not currently impacted by these statements.

In June 2001, the FASB issued Statement No. 143, Accounting for Asset Retirement Obligations, which establishes requirement for the accounting of removal-type costs associated with asset retirements. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Partnership is currently assessing the impact of its financial statements.

In August 2001, the FASB issued Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which establishes requirements for the accounting for the impairment or disposal of long-lived assets. The standard is effective for fiscal years beginning after December 15, 2001. The Partnership believes there will be no impact on their financial statements from adopting this standard.

(6) Commitments and Contingencies

In the normal course of business, the Partnership is involved in various lawsuits and claims related to its royalty properties. In the opinion of the Partnership's management, the ultimate resolution of such matters will not have a material adverse effect on the financial position or results of operations of the Partnership.

(7) Supplemental Oil and Gas Data - Unaudited

Proved oil and gas reserves are estimated quantities, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The Partnership retained an independent petroleum engineering consulting firm to provide annual estimates as of December 31 of each year of the Partnership's future net recoverable oil and gas reserves.

F-41

SPINNAKER ROYALTY COMPANY, L.P.

NOTES TO FINANCIAL STATEMENT
December 31, 2001, 2000, and 1999

The following table presents the Partnership's estimate of its proved oil and gas reserves, all of which are located in the United States. The Partnership emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, the estimates are expected to change as future information becomes available. The estimates have been prepared by the Partnership's independent petroleum reservoir engineers.

                                    Oil    Gas
                                   MBbls   MMcf
                                   -----  ------
Balance December 31, 1998......... 1,326  15,720
Revisions of previous estimates...   (58)  4,028
Production........................  (115) (3,003)
                                   -----  ------
Balance December 31, 1999......... 1,153  16,745
Revisions of previous estimates...   (54)    853
Production........................   (97) (2,598)
                                   -----  ------
Balance December 31, 200.......... 1,002  15,000
Revisions of previous estimates...    60   1,784
Production........................   (88) (2,247)
                                   -----  ------
Balance December 31, 2001.........   974  14,537
                                   =====  ======

Oil reserves, which include condensate, are stated in thousands of barrels and gas reserves, which include natural gas liquids, are stated in millions of cubic feet.

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves--Unaudited

The following table, which presents a standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves, is presented pursuant to SFAS No. 69, Disclosure About Oil and Gas Producing Activities. In computing this data, assumptions other than those required by this accounting standard could produce different results. Accordingly, the data should not be construed as representative of the fair value of the Partnership's proved oil and gas reserves.

Future cash inflows were computed by applying year-end prices of oil and gas to the estimated year-end quantities of proved reserves. Future price changes were considered only to the extent provided by contractual arrangements in existence at year end. Future production costs were computed by estimating the expenditures to be incurred in producing the proved oil and gas reserves at the end of the year, based on year-end costs. The standardized measure of discounted future cash flows represents the present value of estimated future net cash flows using a 10% annual discount rate (in thousands).

F-42

SPINNAKER ROYALTY COMPANY, L.P.

NOTES TO FINANCIAL STATEMENT
December 31, 2001, 2000, and 1999

                                          Years ended December 31,
                                         --------------------------
                                           2001     2000     1999
                                         --------  -------  -------
Future estimated gross revenues......... $ 52,935  172,224   64,436
Future estimated production taxes.......   (4,237) (15,126)  (5,914)
                                         --------  -------  -------
Future estimated net revenues...........   48,698  157,099   58,522
Discount at 10% per annum...............  (21,871) (64,683) (23,419)
                                         --------  -------  -------
Standardized measure of future
  estimated net revenues................ $ 26,827   92,416   35,103
                                         ========  =======  =======
Beginning of year....................... $ 92,416   35,103   24,024
   Sales of oil and gas, net of
     production costs...................  (10,044) (11,300)  (8,053)
   Net changes in prices and production
     costs..............................  (60,964)  63,231   10,858
   Revisions of previous quantity
     estimates..........................    2,290    1,653    5,461
   Accretion of discount................    9,242    3,510    2,402
   Other................................   (6,113)     219      411
                                         --------  -------  -------
End of year............................. $ 26,827   92,416   35,103
                                         ========  =======  =======

Depletion expense per barrel of oil equivalent was $3.11, $3.82, and $3.86 for the years ended December 31, 2001, 2000, and 1999, respectively.

F-43

LIST OF APPENDICES

FAIRNESS OPINION OF BRUCE E. LAZIER, P.E., DATED JULY 30, 2001........ A1-1

FAIRNESS OPINION OF BRUCE E. LAZIER, P.E., DATED DECEMBER 13, 2001.... A2-1

SUMMARY RESERVE REPORT OF CALHOUN, BLAIR & ASSOCIATES FOR DORCHESTER
  HUGOTON, LTD., AS OF DECEMBER 31, 2001, 2000 AND 1999...............  B-1

SUMMARY RESERVE REPORT OF HUDDLESTON & CO., INC. FOR REPUBLIC ROYALTY
  COMPANY, AS OF JANUARY 1, 2002, 2001 AND 2000.......................  C-1

SUMMARY RESERVE REPORT OF HUDDLESTON & CO., INC. FOR SPINNAKER ROYALTY
  COMPANY, L.P. AS OF JANUARY 1, 2002, 2001 AND 2000..................  D-1

FORM OF PROXY FOR DORCHESTER HUGOTON AND SPINNAKER....................  E-1

FORM OF CONSENT FOR REPUBLIC..........................................  F-1


APPENDIX A-1
TO
PROXY STATEMENT/PROSPECTUS

FAIRNESS OPINION
OF
BRUCE E. LAZIER, P.E.

BRUCE E. LAZIER, P.E.
PETROLEUM INVESTMENTS

ISPYOIL, LLC.

Off: 214-368-9414             Fax: 214-368-9094
Cell: 214-534-7539                                  email: ispyoil@yahoo.com

                                July 30, 2001

Dorchester Hugoton, Ltd.
1919 South Shiloh Road, Suite 600, LB 48 Garland, Texas 75042-8234

Attention: James E. Raley
President
James E. Raley, Inc.

Dear Sirs:

Dorchester Hugoton, Ltd. (the "Company") has engaged Bruce E. Lazier ("Lazier") to act as financial adviser to the Company and issue an opinion (the "Opinion") as to the fairness, from a financial point of view, to the Company and its Unitholders (the "Unitholders") of a transaction (the "Transaction") between and among the Company and the limited partnerships, Republic Royalty Company and Spinnaker Royalty Company, L. P. (collectively the "Partnerships") and including certain interests held by other persons outside the Partnerships in the properties held by the one or more of the Partnerships (the "Interests"). Through the Transaction, the Company and the Partnerships and the Interests would be consolidated into a new entity which would be a publicly-traded limited partnership (the "New Partnership"). The Transaction is described more fully in a draft letter of intent which has been supplied to Lazier.

Credentials of Lazier

Lazier has a degree in petroleum engineering and a Master in Business Administration from Stanford University and has worked in his career both as a petroleum engineer and investment banker. In the course of his 40 year career, Lazier has been frequently engaged in the valuation of oil and gas companies, their properties and securities in connection with mergers and acquisitions, negotiated underwritings, secondary distributions of listed and unlisted securities, private placements, and valuations for estate, corporate and other purposes.

Scope of Review

Lazier has conducted such analyses, investigations, research and testing of assumptions as were considered by him to be appropriate in the circumstances. Lazier was granted access to the Company's management and was not, to his knowledge, denied any type of information which he requested and which might be considered to be material to this Opinion.

6440 N. Central Expressway Turley Law Center, Suite 503 . Dallas, Texas 75206

A1-1


Fairness Considerations

In arriving at his opinion, Lazier has among other things, considered:

(i) the current state of the domestic and international oil and gas industry.;

(ii) the relative value of the net assets, reserves, future production and anticipated future cash flow of the Company and the Partnerships;

(iii) sensitivities of gas prices, reserves, the Company's assets and discount rates to the value of the New Partnership;

(iv) "Estimates of Gas Reserves," dated January 17, 2001 and prepared by Calhoun, Blair & Associates;

(v) "Republic Royalty Company and Spinnaker Royalty Company, L.P. Estimated Reserves and Future Net Revenue, as of January 1, 2001" both prepared by Huddleston & Co., Inc.

(vi) 2000 Net Cash Flow Comparison--Revised 02/21/01;

(vii) Annual Report of Dorchester Hugoton, Ltd. on Form 10-K for the year ended December 31,2000 Quarterly Report of Dorchester Hugoton, Ltd. on Form 10-Q for the quarter ended March 31, 2001, and other publicly available information concerning Dorchester Hugoton, Ltd.;

(vii) Summary of Reserves of the Partnerships from the Company, dated July 5, 2001.

(viii) Opening calculations prepared by Republic and Spinnaker. Based on 1/1/00 SEC type reserve studies and projected year 2000 income.

(ix) Republic & Spinnaker 7/1/2000 Reserve Study @ agreed upon escalated prices.

(x) Dorchester Hugoton 7/1/2000 Reserve Study @ agreed upon escalated prices.

Various reserve studies and analysis prepared by the Company

(xi) Rework of 5/17/00 calculation by Dorchester Hugoton using 7/1/2000 Reserve Studies including probable and possible reserves.

Rework of 5/17/00 calculation by Dorchester Hugoton using 7/1/2000 Reserve Studies proved producing only.

Two reworks Oct. & Nov. 2000 calculations by Dorchester Hugoton.

Adjustment of Oct. 2000 calculations by Dorchester Hugoton for the value of already being publicly traded.

(xii) draft letter of intent.

(xiii) Various transactions involving acquisitions of oil and gas properties through merger and/or purchase and the trading history of public companies subsequent to such acquisitions.

Key Assumptions and Limitations

Lazier has relied upon, and has assumed the completeness, accuracy and fair presentation of all financial and other information, data, advice, opinions, and representations obtained by him from public sources or otherwise pursuant to his engagement, and this Opinion is conditional upon such completeness, accuracy, and fair presentation. Subject to the exercise of professional judgment and except as expressly described herein, Lazier has not attempted to independently verify the accuracy or completeness of any such information, data,

6440 N. Central Expressway Turley Law Center, Suite 503 . Dallas, Texas 75206

A1-2


advise, opinions and representations. Management has represented to Lazier as of the date hereof, among other things, that the information, data, opinions and other materials (the "Information") provided to him on behalf of the Company are complete and correct in all material respects at the date the Information was provided to him and that since the date of the Information, there has been no material change, financially otherwise, in the position of the Company, or in its assets, liabilities (contingent or otherwise), business or operations and there has been no change of any material fact which is of a nature as to render the Information untrue or misleading in any material respect.

This Opinion is rendered on the basis of securities market, economic and general business and financial conditions prevailing as at the date hereof and the condition and prospects, financial and otherwise, of the Company as reflected in the information and documents reviewed by Lazier and as they were represented to it in its discussions with management of the Company. In his analysis and in connection with the preparation of this Opinion, Lazier has made a number of assumptions with respect to industry performance, general business, market and economic conditions and other matters, which assumptions Lazier believes are reasonable to make in the context of the Transaction.

This Opinion is also limited to the fairness, from a financial point of view, of the Transaction to the Company and the Company's Unitholders, and Lazier expresses no opinion, as to the merits of the underlying decision by the Company to engage in the Transaction. This opinion necessarily is based upon market, economic and other conditions as they exist and can be evaluated on the date hereof, and Lazier assumes no responsibility to update or revise my Opinion based upon circumstances or events occurring after the date hereof.

Lazier has acted as financial advisor to the Company in connection with the Transaction and will receive a fee for his services, including for rendering the Opinion. In addition, the Company has agreed to indemnify Lazier for certain potential liabilities arising out of the engagement. Lazier has no other financial advisory or other relationships with the Company, its General Partners and affiliates or with any of the other parties to the Transaction or their affiliates.

This Opinion is given solely for the benefit of and delivered exclusively to the Company, its General Partners, its Unitholders and its Advisory Committee.

Conclusion

Based upon and subject to the foregoing, it is Lazier's opinion that, as of the date hereof, the Transaction is fair to the Company and its Unitholders from a financial viewpoint.

Very truly yours,

/s/  BRUCE E. LAZIER, P.E./M.B.A.
---------------------------------
  Bruce E. Lazier, P.E./M.B.A.

6440 N. Central Expressway Turley Law Center, Suite 503 . Dallas, Texas 75206

A1-3


APPENDIX A-2
TO
PROXY STATEMENT/PROSPECTUS

FAIRNESS OPINION
OF
BRUCE E. LAZIER, P.E.

BRUCE E. LAZIER, P.E.
PETROLEUM INVESTMENTS

ISPYOIL, LLC.

Off: 214-368-9414             Fax: 214-368-9094
Cell: 214-534-7539                                  email: ispyoil@yahoo.com

                              December 13, 2001

Dorchester Hugoton, Ltd.

1919 South Shiloh Road, Suite 600-LB 48
Garland, Texas 75042-8234

Attention: James E. Raley
President
James E. Raley, Inc.

Dear Sirs:

By letter agreement, dated May 11, 2001, Dorchester Hugoton, Ltd. (the "Company") engaged Bruce E. Lazier ("Lazier") to act as financial adviser to the Company and issue an opinion (the "Opinion") as to the fairness to the Company and its Unitholders (the "Unitholders") of a transaction (the "Transaction") between and among the Company and the limited partnerships, Republic Royalty Company and Spinnaker Royalty Company, L. P. (collectively the "Partnerships") and including certain interests held by other persons outside the Partnerships in the properties held by the one or more of the of Partnerships (the "Interests").

Through the Transaction, the Company and the Partnerships and the Interests are to be consolidated into a new entity which will be a publicly-traded limited partnership (the "New Partnership"). The Transaction is described more fully in the draft agreements referenced below at (vii) through (xvii).

On July 30, 2001, Lazier delivered the Opinion to the Company in which he concluded that the Transaction was fair to the Company and its Unitholders from a financial viewpoint. The purpose of this letter (the "Second Opinion") is to update and supplement the Opinion, and terms and definitions in the Opinion shall have the same meaning herein unless otherwise indicated.

A2-1


Scope of Review

Lazier has reviewed the Opinion and the bases on which it was given and, in addition, has conducted such analyses, investigations, research and testing of assumptions as were considered by him to be appropriate to reviewing and updating the Opinion. Lazier was granted access to the Company's management and was not, to his knowledge, denied any type of information which he requested and which might be considered to be material to this Second Opinion, including information regarding the acquisition by the Company on August 9, 2001 of an Oklahoma production payment described more fully in the Company's "Quarterly Report" on Form 10-Q for the quarter ended June 30, 2001.

Fairness Considerations

In arriving at this opinion, Lazier considered in addition to those items reviewed in conjunction with issuance of the Opinion:
(i) the current state of the domestic and international oil and gas industry:
(ii) the present relative value of the net assets, reserves, future production and anticipated future cash flow of the Company and the Partnerships;
(iii) revised sensitivities of gas prices, reserves, the Company's assets and discount rates to the value of the New Partnership;
(iv) balance sheets and income statements, dated June 30, 2001 and September 30, 2001, of the Partnerships;
(v) the Company's "Quarterly Report" on Form 10-Q for the quarters ended June 30, 2001 and September 30, 2001;
(vi) revised reserve study by Calhoun, Blair and Associates, dated August 14, 2001, accounting for the acquisition of the production payment by the Company;
(vii) draft "Partnership Agreement" of the New Partnership
(viii)draft "Combination Agreement" pursuant to which the Company and the Partnerships will combine; and
(ix) draft "Contribution Agreement" pursuant to which the general partners of the Company and the Partnerships will contribute certain limited and/or general Partner interests received in the combination transaction to the general partner of the New Partnership;
(x) draft Exhibit 3.1(a)(i), the "Assignment, Conveyance and Assumption Agreement" from the Company to the New Partnership;
(xi) draft Exhibit 3.1(b), the "Assignment, Conveyance, Bill of Sale and Assumption Agreement" from the Company to the New Partnership;
(xii) draft Exhibit 3.3(c)(i), the "Assignment and Conveyance" Agreement from the Company to the New Partnership;
(xiii)draft Exhibit 3.3(c)(ii), the "Assignment, Conveyance and Assumption Agreement" from the Company to the New Partnership;
(xiv) draft "Amended and Restated Limited Partnership Agreement" of the General Partner of the New Partnership (the "General Partner");
(xv) draft "Amended and Restated Limited Liability Company Agreement" of the general partner of the General Partner;
(xvi) draft "Transfer Restriction Agreement" of the General Partner and its general partner which governs the transfer of interests;
(xvii)draft "Business Opportunities Agreement" that sets forth the rights and responsibilities of the General Partner and related parties and the New Partnership with respect to business opportunities.

Key Assumptions and Limitations

As with the Opinion, Lazier has relied upon and has assumed the completeness, accuracy and fair presentation of all financial and other information, data, advice, opinions, and representations obtained by him from public sources or otherwise pursuant to his engagement, and this Second Opinion is conditional upon such completeness, accuracy, and fair presentation. Subject to the exercise of professional judgment and except as

A2-2


expressly described herein, Lazier has not attempted to verify independently the accuracy or completeness of any such information, data, advice, opinions and representations. Management has represented to Lazier, among other things, that the information, data, opinions and other materials (the "Information") provided to him on behalf of the Company are complete and correct in all material respects at the date the Information was provided to him and that since the date of the Information, there has been no material change, financially or otherwise, in the position of the Company, the Partnerships or in their collective assets, liabilities (contingent or otherwise), business or operations and there has been no change of any material fact which is of a nature as to render the Information untrue or misleading in any material respect.

Also, as with the Opinion, this Second Opinion is rendered on the basis of securities market, economic and general business and financial conditions prevailing as at the date hereof and the condition and prospects, financial and otherwise, of the Company as reflected in the Information and as it represented to him in discussions with management of the Company. In his analysis and in connection with the preparation of this Opinion, Lazier has made a number of assumptions with respect to industry performance, general business, market and economic conditions and other matters, which assumptions Lazier believes are reasonable to make in the context of the Transaction.

This Second Opinion is further limited to the fairness, from a financial point of view, of the Transaction to the Company and the Company's Unitholders, and Lazier expresses no opinion as to the merits of the underlying decision by the Company to engage in the Transaction. This Second Opinion necessarily is based upon market, economic and other conditions as they exist and can be evaluated on the date hereof, and Lazier assumes no responsibility to update or revise either the Opinion or this Second Opinion based upon circumstances or events occurring after the date hereof.

Lazier has acted as financial advisor to the Company in connection with the Transaction and will receive a fee for his services, including the rendering of this Second Opinion. In addition, the Company has agreed to indemnify Lazier for certain potential liabilities arising out of his engagement.

This Second Opinion is given solely for the benefit of and delivered exclusively to the Company, its General Partners, its Unitholders and its Advisory Committee.

Conclusion

Based upon and subject to the foregoing, it is Lazier's opinion that, as of the date hereof, the Transaction remains fair to the Company and its Unitholders from a financial viewpoint.

Very truly yours,

       /s/  BRUCE E. LAZIER, P.E./M.B.A.
-------------------------------------
     Bruce E. Lazier, P.E./M.B.A.

A2-3


APPENDIX B
TO
PROXY STATEMENT/PROSPECTUS

SUMMARY RESERVE REPORT OF
CALHOUN, BLAIR & ASSOCIATES
FOR DORCHESTER HUGOTON, LTD.
As of December 31, 2001, 2000 and 1999

Calhoun, Blair & Associates
Petroleum Consultants
4429 North Central Expressway
Dallas, Texas 75205
Facsimile (214) 526-4764

April 29, 2002

P.A. Peak, Inc., James E. Raley, Inc.
General Partners
Dorchester Hugoton, Ltd.
1919 S. Shiloh Road, Suite 600
Garland, Texas 75042-8234

Gentlemen:

In accordance with your instructions we have previously prepared estimates of gas reserves from certain leasehold and royalty interests owned by Dorchester Hugoton, Ltd., located in the Hugoton Field of Kansas and Oklahoma. We have projected our estimates of future gas production annually, as of December 31, 2001, 2000 and 1999, for these properties.

Information necessary for the preparation of these estimates was obtained from records furnished by Dorchester Hugoton, Ltd., from records on file with the state regulatory bodies, and from our own files. No special tests were obtained to assist in the preparation of this report. For the purpose of this report, the individual well tests and production information as reported in the records on file with the state regulatory bodies were accepted as represented, together with all other factual data provided by Dorchester Hugoton, Ltd., including the extent and character of the interest appraised.

All estimated reserves in this report are considered as proved developed producing. Proved developed producing reserves are those proved to a high degree of certainty by reason of actual completion or successful testing. Estimates of proved reserves were made using standard geological and engineering methods accepted by the petroleum industry. The method, or combination of methods, utilized was tempered by experience in the area, state of development, quality and extent of the basic data and production history.

When the information was available and the method was applicable, natural gas reserves in this report were estimated by the extrapolation of historical trends of pressure decline as a function of cumulative production, gas production decline as a function of time and gas production decline as a function of cumulative gas production. For certain wells having a limited production history, reserves were estimated by analogy with nearby similar wells in the same formation. All gas volumes are raw wellhead gas volumes expressed at 60 degrees Fahrenheit and at a standard pressure base of 14.65 pounds per square inch absolute.

B-1

Reserves in this report are expressed as gross and net gas production. Net gas production represents those reserves net to the appraised interest after deducting all leasehold and royalty interests owned by others. Values of reserves are expressed in terms of net operating revenues, cash flow before taxes, and present worth. Net operating revenue is revenue, which would accrue to the appraised interests from the production and sale of the estimated net reserves. Cash flow before taxes is obtained by deducting severance and ad valorem taxes, net operating expenses and capital costs from net operating revenue. Net operating expenses include an allocation of supervisory costs chargeable to the leases but do not include general and administrative overhead. An allowance for a retained production payment (overriding royalty) related to the 20 percent interest acquired in the Guymon Hugoton Field in 1986 is included in the 1999 and 2000 Oklahoma net operating expenses. Gas prices, net operating expenses and future capital costs were furnished by Dorchester Hugoton, Ltd. Present worth is defined as the future cash flow before taxes discounted at the rate of ten (10.00) percent per year compounded annually. For the purpose of this report no estimate was made of salvage value for the existing lease and well equipment, or costs involved in abandonment of the wells.

The reserves included in this report are estimates only and should not be construed as being exact quantities. The revenues from such reserves and the actual costs related thereto could be more or less than the estimated amounts. The scope of this investigation did not include an environmental study of these properties, nor was an on-site field inspection conducted. For the purpose of this report, it was necessary to assume that these properties are in compliance with existing government regulations. Because of governmental policies and uncertainties of supply and demand, the prices actually received for the reserves included in this report, and the costs incurred in recovering such reserves, may vary from price and cost assumptions in this report. In any case, estimates of reserves may increase or decrease as a result of future operation and as more production history becomes available.

Calhoun, Blair & Associates have not examined the title to these properties, nor has the actual degree or type of interest owned been independently confirmed. We are independent petroleum engineers; we do not own an interest in these properties and are not employed on a contingent basis. Basic field performance data together with our engineering work sheets are maintained on file in our office and are available for review.

Included in this report are summaries of gross and net gas reserves in Kansas and Oklahoma. Also included are projections of estimated cash flow before taxes and present worth for all properties appraised as of December 31, 2001, 2000 and 1999. Present worth of future cash flow is not meant to represent the Fair Market Value of these properties or of Dorchester Hugoton, Ltd.

This report is a summary of our previous reports dated January 17, 2002, January 17, 2001, and January 31, 2000. It was a pleasure to prepare this report for you and we hope that it serves the purpose for which it was prepared. If we can be of any further service to you in this connection, please advise us.

Yours very truly,

/s/  ROBERT G. BLAIR, P.E.
-------------------------
Calhoun, Blair & Associates

B-2

Total Proved Producing    Estimated Reserves and    Calhoun, Blair and
Reserves                  Revenues                  Associates
Dorchester Hugoton, Ltd.                            Dallas, Texas
Kansas and Oklahoma

Year Ended  Gross Production
December 31 Total            Net Production Total Future Net Revenues M$
----------- ---------------- -------------------- --------------------------
                                                               Discounted at
            MBBL     MMCF    MBBL        MMCF     Undiscounted 10% Per Year
            ----  ---------- ----     ----------  ------------ -------------
   2001....  0    59,809.000  0      48,302.268   $ 65,946.232 $ 44,726.409
   2000....  0    66,974.000  0      54,126.957   $223,616.122 $140,003.001
   1999....  0    71,679.000  0      58,209.114   $ 67,233.266 $ 44,381.884

B-3

APPENDIX C
TO
PROXY STATEMENT/PROSPECTUS

SUMMARY RESERVE REPORT OF
HUDDLESTON & CO, INC.
FOR REPUBLIC ROYALTY COMPANY
As of January 1, 2002, 2001 and 2000

Huddleston & Co., Inc.
Petroleum and Geological Engineers
1 Houston Center
1221 McKinney, Suite 3700
Houston, Texas 77010


PHONE (713) 209-1100 . FAX (713) 752-0828 May 2, 2002

Republic Royalty Company
Attention: Mr. William Casey McManemin
3738 Oak Lawn Avenue, Suite 300
Dallas, Texas 75219-4379

Re: Estimated Reserves and Future Net Revenue As of January 1, 2000, 2001, and 2002 SEC Pricing Case Gentlemen:

Pursuant to your request, we have summarized the estimated oil, condensate, natural gas, and plant product reserves and projected revenues net to the interests owned by Republic Royalty Company (RRC) as of January 1, 2000, 2001, and 2002. These estimates were derived from reports prepared for RRC by Huddleston & Co., Inc., under separate cover and are subject to the qualifications stated therein.

A summary of our conclusions follows:

                                         Net to Republic Royalty Company*
                                        -----------------------------------
                                          Proved
                                         Developed    Proved      Total
          SEC Product Prices             Producing  Undeveloped   Proved
          ------------------            ----------- ----------- -----------
As of January 1, 2002
   Estimated Future Net Oil/Cond., bbl.   3,227,074    174,008    3,401,083
   Estimated Future Net Gas, MMcf......    17,433.0    1,575.0     19,008.0
   Estimated Net Plant Products, MMcf..     1,146.2        0.0      1,146.2
   Estimated FNR, Discounted at 10%, $.  46,828,738  3,261,889   50,090,626
As of January 1, 2001
   Estimated Future Net Oil/Cond., bbl.   3,312,583    178,449    3,491,032
   Estimated Future Net Gas, MMcf......    16,088.0    1,419.4     17,507.4
   Estimated Net Plant Products, MMcf..     1,458.5        0.0      1,458.5
   Estimated FNR, Discounted at 10%, $. 120,632,026  8,429,096  129,061,122
As of January 1, 2000
   Estimated Future Net Oil/Cond., bbl.   3,559,994    227,594    3,787,588
   Estimated Future Net Gas, MMcf......    18,290.5    3,350.4     21,640.9
   Estimated Net Plant Products, MMcf..     1,517.0        0.0      1,517.0
   Estimated FNR, Discounted at 10%, $.
--------                                 58,607,621  6,376,584   64,984,205

*Numbers subject to computer rounding.

C-1

Report Preparation

Source of Reserve Projections--The reserves and revenues shown herein have been based on a combination of reserve estimates and projected future production and revenue schedules prepared by our firm and Harlan Consulting for RRC and is a summary of our previous reports dated March 11, 2002, June 12, 2001, and July 18, 2001.

Reporting Requirements--Securities and Exchange Commission (SEC) Regulation S-K, Item 102, and Regulation S-X, Rule 4-10, and Financial Accounting Standards Board (FASB) Statement No. 69 require oil and gas reserve information to be reported by publicly held companies as supplemental financial data. These regulations and standards provide for estimates of Proved reserves and revenues discounted at 10% based on product prices in effect on the "as of" date of the report.

Standards of Practice--The Society of Petroleum Engineers (SPE) requires Proved reserves to be economically recoverable with prices and costs in effect on the "as of" date of the report. In addition, the SPE has issued Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information which sets requirements for qualifications and independence of reserve estimators and auditors and accepted methods to be used for estimating future reserves.

The estimated reserves contained herein were prepared in accordance with our understanding of all the applicable SEC, FASB, and SPE regulation requirements and definitions. We note that we have necessarily included composite projections of net oil and gas reserves given the limited information available to a royalty interest owner and the relatively small net reserves attributable to any specific property within the composite group. SEC Regulation S-X, Rule 4-10, allows large numbers of royalty interests that are not individually significant to be aggregated for purposes of accounting. The SPE does not address the utilization of composite projections.

Reserve Estimates

Reserves for the producing properties were based on extrapolation of production history where there was sufficient data to suggest a decline trend and where this methodology was applicable for the subject reservoirs. The reserves for the remaining producing and nonproducing properties were projected utilizing analogy to offset wells producing from simil