Overview

We own producing and nonproducing mineral, royalty, overriding royalty, net profits and leasehold interests. We refer to these interests as the Royalty Properties. We currently own Royalty Properties in 573 counties and parishes in 25 states.

Dorchester Minerals Operating LP, a Delaware limited partnership owned directly and indirectly by our general partner, holds working interest properties and a minor portion of mineral and royalty interest properties. We refer to Dorchester Minerals Operating LP as the "operating partnership" or "DMOLP." We directly and indirectly own a 96.97% net profits overriding royalty interest (referred to as Net Profits Interests, or NPIs) in property groups made up of four NPIs created when we commenced operations in 2003 and one immaterial deficit NPI subsequently created. We currently receive monthly payments equaling 96.97% of the preceding month's net profits actually realized by the operating partnership from three of the property groups. The purpose of such Net Profits Interests is to avoid the participation as a working interest or other cost-bearing owner that could result in unrelated business taxable income. Net profits interest payments are not considered unrelated business taxable income for tax purposes. One such Net Profits Interest, referred to as the Minerals NPI, has continuously had costs that exceed revenues. As of March 31, 2009, cumulative operating and development costs presented in the following table, which include amounts equivalent to an interest charge, exceeded cumulative revenues of the Minerals NPI, resulting in a cumulative deficit. All cumulative deficits (which represent cumulative excess of operating and development costs over revenue received) are borne 100% by our general partner until the Minerals NPI recovers the deficit amount. Once in profit status, we will receive the Net Profits Interest payments attributable to these properties. Our consolidated financial statements do not reflect activity attributable to properties subject to Net Profits Interests that are in a deficit status. Consequently, Net Profits Interest payments and production sales volumes and prices set forth in other portions of this quarterly report do not reflect amounts attributable to the Minerals NPI, which includes all of the operating partnership's Fayetteville Shale working interest properties in Arkansas.

                                                      Minerals NPI Results
                                                         (in Thousands)
                                   Cumulative Total       Three Months        Cumulative Total
                                     at 12/31/08          Ended 3/31/09          at 3/31/09
Cash received for revenue         $           14,216     $           777     $           14,993
Cash paid for operating costs                  2,226                 184                  2,410
Cash paid for development costs               11,724                 782                 12,506
Budgeted capital expenditures                    905                  26                    931
Net                               $             (639 )   $          (215 )   $             (854 )
Cumulative NPI deficit            $             (639 )   $          (854 )   $             (854 )

The development costs pertain to more properties than the properties producing revenue due to timing differences between operating partnership expenditures and oil and natural gas production and payments to the operating partnership. The amounts reflect budgeted capital expenditures of $931,000 at March 31, 2009. The amounts also reflect the operating partnership's ownership of the subject properties. Net Profits Interest payments to us, if any, will equal 96.97% of the cumulative net profits actually received by the operating partnership attributable to subject properties. The above financial information attributable to the Minerals NPI may not be indicative of future results of the Minerals NPI and may not indicate when the deficit status may end and when Net Profits Interest payments may begin from the Minerals NPI.

Commodity Price Risks

Our profitability is affected by volatility in prevailing oil and natural gas prices. Oil and natural gas prices have been subject to significant volatility in recent years in response to changes in the supply and demand for oil and natural gas in the market along with domestic and international political economic conditions.

Results of Operations

Three Months Ended March 31, 2009 as compared to Three Months Ended March 31,
2008

Normally, our period-to-period changes in net earnings and cash flows from
operating activities are principally determined by changes in oil and natural
gas sales volumes and prices. Our portion of oil and natural gas sales and
weighted average prices were:

                                                        Three Months Ended
                                                               March 31,
       Accrual basis sales volumes:                      2009            2008
       Royalty properties gas sales (mmcf)                 1,037          992
       Royalty properties oil sales (mbbls)                   74           72
       Net profits interests gas sales (mmcf)                887          987
       Net profits interests oil sales (mbbls)                 3            4

       Accrual basis weighted average sales price:
       Royalty properties gas sales ($/mcf)           $     4.05      $  7.96
       Royalty properties oil sales ($/bbl)           $    38.45      $ 94.88
       Net profits interests gas sales ($/mcf)        $     3.32      $  8.04
       Net profits interests oil sales ($/bbl)        $    28.63      $ 80.10

       Accrual basis production costs deducted
       under the net profits interests ($/mcfe) (1)   $     1.45      $  1.99

(1) Provided to assist in determination of revenues; applies only to Net Profits Interest sales volumes and prices.

Oil sales volumes attributable to our Royalty Properties during the first quarter were essentially unchanged from the first quarter of 2008. Natural gas sales volumes attributable to our Royalty Properties during the first quarter increased 4.5% from 992 mmcf in 2008 to 1,037 mmcf in 2009. The increase in natural gas sales volume was primarily attributable to results from new drilling activity in the second half of 2008.

Oil sales volumes attributable to our Net Profits Interests during the first quarter of 2009 were virtually unchanged when compared to the same period of 2008. Natural gas sales volumes attributable to our Net Profits Interests during the first quarter of 2009 decreased from the same period of 2008. First quarter sales of 887 mmcf during 2009 were 10.1% less than 987 mmcf during 2008. Natural gas sales volume decreases were primarily a result of severe cold weather freezing gas production facilities and natural reservoir decline in the Guymon-Hugoton field in Oklahoma. Production sales volumes and prices from the Minerals NPI are excluded from the above table. See "Overview" above.

The weighted average oil sales price attributable to our interest in Royalty Properties decreased 59.5% from $94.88/bbl during the first quarter of 2008 to $38.45/bbl during the first quarter of 2009. The first quarter weighted average natural gas sales price from Royalty Properties decreased 49.1% from $7.96/mcf during 2008 to $4.05/mcf during 2009. Both oil and natural gas price changes resulted from changing market conditions.

The first quarter weighted average oil sales price from the Net Profits Interests properties decreased 64.3% from $80.10/bbl in 2008 to $28.63/bbl in 2009. The first quarter weighted average natural gas sales price from the Net Profits Interests properties of $3.32/mcf in 2009 was 58.7% lower than $8.04/mcf during the same period of 2008. Changing market conditions resulted in decreased oil and natural gas sales prices.

Our first quarter net operating revenues decreased 58.5% from $21,272,000 during 2008 to $8,824,000 during 2009. The quarterly decrease primarily resulted from decreases in oil and natural gas sales prices.

Costs and expenses decreased 15.3% from $5,992,000 during the first quarter of 2008 to $5,074,000 during the first quarter of 2009. The decrease resulted from decreased production tax on lower operating revenues and reduced depletion and amortization.

Depletion and amortization decreased 12.9% during the first quarter of 2009 when compared to the same period of 2008. The decrease from $3,790,000 in 2008 to $3,300,000 in 2009 resulted from a lower depletable base due to effects of previous depletion and upward revisions in oil and natural gas reserve estimates at 2008 year end.

First quarter net earnings allocable to common units decreased 75.6% from $14,947,000 during 2008 to $3,654,000 during 2009. The 2009 decrease from the first quarter 2008 net earnings is primarily the result of decreased oil and natural gas sales prices.

Net cash provided by operating activities decreased 31.8% from $17,203,000 during the first quarter of 2008 to $11,735,000 during the first quarter of 2009 primarily due to decreased oil and natural gas sales prices partially offset by a $2.1 million natural gas liquid payment attributable to 2008. The natural gas liquids payment is based on an Oklahoma Guymon-Hugoton field 1994 gas delivery agreement that is in effect through 2015. Under the terms of the agreement, when the market price of natural gas liquids increases sufficiently disproportionately to natural gas market prices, the operating partnership receives a portion of that increase in an annual payment. In the event the evaluation at the end of the annual contract period shows the payment to be determinable and collectable, the revenue is accrued. Only immaterial amounts were received prior to 2007.

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

Cash receipts attributable to our Royalty Properties during the 2009 first quarter totaled approximately $8.1 million. These receipts generally reflect oil sales during December 2008 through February 2009 and natural gas sales during November 2008 through January 2009. The weighted average indicated price for oil and natural gas sales during the 2009 first quarter attributable to the Royalty Properties was $38.49/bbl and $5.33/mcf, respectively.

Cash receipts attributable to our Net Profits Interests during the 2009 first quarter totaled approximately $5.1 million. These receipts reflect oil and natural gas sales from the properties underlying the Net Profits Interests generally during November 2008 through January 2009 and approximately $2.1 million attributable to calendar year 2008 natural gas liquids. The weighted average indicated price received during the 2009 first quarter for oil and natural gas sales was $36.38/bbl and $6.89/mcf, respectively. The natural gas weighted average indicated price for the quarter was increased by $2.41/mcf due to the natural gas liquids payment.

We received division orders for, or otherwise identified, 141 new wells completed on our Royalty Properties and Net Profits Interests located in 54 counties and parishes in nine states during the first quarter of 2009. The operating partnership elected to participate in 17 wells to be drilled on our Net Profits Interests located in six counties in two states. Selected new wells and the royalty interests owned by us and the working and net revenue interests owned by the operating partnership are summarized in the following table.

This table does not include wells drilled in the Fayetteville Shale trend as they are detailed in a subsequent discussion and table.

      County                                   DMLP       DMOLP        Test Rates per day
State /Parish     Operator   Well Name        NRI(2)   WI(1) NRI(2)    Gas, mcf  Oil, bbls
                             HA RA SUA;
                  Comstock   Robert Crews
LA    De Soto     Oil &Gas   #3Alt            2.734%    --     --          2,350    --
                  Comstock   Lena Crews #5

LA    De Soto     Oil &Gas   Alt              2.734%    --     --          1,700    --
                  Burlington Troy Miller
OK    Roger Mills Resources  #17-11           1.670%    --     --          2,803     5
                  Chesapeake Barton Gas
TX    Hidalgo     Operating  Unit #1          3.125%    --     --          4,920    --
                  Devon      Effie Hayes
TX    Wheeler     Energy     #18-5H           3.125%    --     --          4,377    --

(1) WI means the working interest owned by the operating partnership and subject to a Net Profits Interest.

(2) NRI means the net revenue interest attributable to our royalty interest or to the operating partnership's royalty and working interest, which is subject to a Net Profits Interest.

FAYETTEVILLE SHALE TREND OF NORTHERN ARKANSAS -- We own varying undivided perpetual mineral interests totaling 23,336/11,464 gross/net acres located in Cleburne, Conway, Faulkner, Franklin, Johnson, Pope, Van Buren, and White counties, Arkansas in an area commonly referred to as the "Fayetteville Shale" trend of the Arkoma Basin. One hundred forty wells have been permitted on the lands as of March 31, 2009. Wells that have been proposed to be drilled by the operator but for which permits have not yet been issued by the Arkansas Oil & Gas Commission are not reflected in this number. Available test results for new wells producing in the first quarter, along with ownership interests owned by us and interests owned by the operating partnership subject to the Minerals NPI, are summarized in the following table.

                                                                            Gas Test
                                                    DMLP        DMOLP        Rates
                                                                            mcf per
    County    Operator        Well Name            NRI(2)   WI(1)  NRI(2)     day
                              Kessinger Trust
    Cleburne  SEECO           8-12 #3-2H35         0.307%   0.436% 0.327%     3,007
                              Beverly Crofford
    Conway    David Arrington #1-14H               1.563%   1.322% 0.996%      --
                              Beverly Crofford
    Conway    David Arrington #2-14H               1.563%   1.322% 0.996%      --
                              Bryant 9-15
    Conway    SEECO           #4-32H31             0.635%   1.701% 1.275%     5,499
                              Deltic Timber 9-16
    Conway    SEECO           #4-36H31             1.384%   2.400% 1.800%     4,625
                              Jerome Carr 9-15
    Conway    SEECO           #4-31H               2.188%   3.796% 2.847%     3,911
                              Bradley 11-13
    Van Buren Chesapeake      #2-9H                1.563%   1.250% 0.938%       320
                              Sequoyah 9-12
    Van Buren Petrohawk       #3-15H               1.953%   2.813% 2.109%       569
    Van Buren SEECO           Linn 10-12 #3-8H16   2.621%   3.230% 2.484%     3,930
    Van Buren SEECO           Linn 10-12 #4-8H16   2.621%   3.230% 2.484%     3,407

(1) WI means the working interest owned by the operating partnership and subject to the Minerals NPI.

(2) NRI means the net revenue interest attributable to our royalty interest or to the operating partnership's royalty and working interest, which is subject to the Minerals NPI.

              2004   2005   2006   2007   Q1 2008   Q2 2008   Q3 2008   Q4 2008   Q1 2009   Total
  New Well
  Permits      1      2      11     35      15        21        15        21        19       140
  Wells Spud   0      1      9      33      12        17        22        13         9       116
  Wells
  Completed    0      1      5      23      10        17        12        17        12       97
  Wells in
  Pay Status
  (1)          0      0      0      6        5         8        10         7        12       48

(1) Wells in pay status means wells for which revenue was initially received during the indicated period.

Net cash receipts for the Royalty Properties attributable to interests in these lands totaled $510,000 in the first quarter from 45 wells. Net cash receipts for the Minerals NPI Properties attributable to interests in these lands totaled $376,000 in the first quarter from 36 wells.

APPALACHIAN BASIN - We own varying undivided perpetual mineral interests in approximately 31,000/22,000 gross/net acres in 19 counties in southern New York and northern Pennsylvania. Approximately 75% of these net acres are located in eastern Allegany and western Steuben Counties in New York, an area which some industry press reports suggest may be prospective for gas production from unconventional reservoirs including the Marcellus Shale. We are monitoring industry activity and encouraging dialogue with industry participants to determine the proper course of action regarding our interests.

HORIZONTAL BAKKEN, WILLISTON BASIN - We own varying undivided perpetual mineral interests totaling 70,390/7,602 gross/net acres located in Burke, Divide, Dunn, McKenzie, Mountrail and Williams Counties, North Dakota. Operators active in this area include Continental Resources, EOG Resources, Hess Corporation and Marathon Oil Company. Sixty-eight wells have been permitted on these lands as of March 31, 2009. In all cases we have elected not to lease our lands and not to pay our share of well costs thus becoming a non-consenting mineral owner. According to North Dakota law, non-consenting owners receive the average royalty rate from the date of first production and back-in for their full working interest after the operator has recovered 150% of drilling and completion costs. Once 150% payout occurs, the working interest will be owned by the operating partnership and subject to the Minerals NPI. Non-consenting owners are not entitled to well data other than public information available from the North Dakota Industrial Commission.

Set forth below is a summary of all permitting, drilling and completion activity through March 31, 2009 for wells in which we have a royalty or Net Profits Interest.

                                                 Q1      Q2      Q3      Q4      Q1
                   2004   2005   2006    2007    2008    2008    2008    2008    2009   Total
      New Well
      Permits       2      1      0      15       8      15      15      12       0      68
      Wells Spud    1      1      0      11       2       9      10       9       8      51
      Wells
      Completed     1      1      0       7       5       4      11       6       1      36
      WI Wells in
      Pay
      Status(1)     0      0      0       0       0       2       1       0       0       3

(1) Wells in pay status means wells for which revenue was initially received during the indicated period.

Liquidity and Capital Resources

Capital Resources

Our primary sources of capital are our cash flow from the Net Profits Interests and the Royalty Properties. Our only cash requirements are the distributions to our unitholders, the payment of oil and natural gas production and property taxes not otherwise deducted from gross production revenues and general and administrative expenses incurred on our behalf and allocated in accordance with our partnership agreement. Since the distributions to our unitholders are, by definition, determined after the payment of all expenses actually paid by us, the only cash requirements that may create liquidity concerns for us are the payments of expenses. Since most of these expenses vary directly with oil and natural gas sales prices and volumes, we anticipate that sufficient funds will be available at all times for payment of these expenses. See Note 3 of the Notes to the Condensed Consolidated Financial Statements for the amounts and dates of cash distributions to unitholders.

We are not directly liable for the payment of any exploration, development or production costs. We do not have any transactions, arrangements or other relationships that could materially affect our liquidity or the availability of capital resources. We have not guaranteed the debt of any other party, nor do we have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt.

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

Expenses and Capital Expenditures

The operating partnership plans to continue its efforts to increase production in Oklahoma with techniques that may include fracture treating, deepening, recompleting, and drilling. Costs of such techniques vary widely and are not predictable as each effort requires specific engineering. The operating partnership owns and operates the wells, pipelines and natural gas compression and dehydration facilities located in Kansas and Oklahoma. The operating partnership anticipates gradual increases in expenses as repairs to these facilities become more frequent and anticipates gradual increases in field operating expenses as reservoir pressure declines. The operating partnership does not anticipate incurring significant expense to replace these facilities at this time. These capital and operating costs influence the Net Profits Interests payments we receive from the operating partnership and are included in the accrual basis production costs $/mcfe in the table under "Results of Operations."

In 1998, Oklahoma regulations removed production quantity restrictions in the Guymon-Hugoton field and did not address efforts by third parties to persuade Oklahoma to permit infill drilling in the Guymon-Hugoton field. Infill drilling could require considerable capital expenditures. The outcome and the cost of such activities are unpredictable and could influence the amount we receive from the Net Profits Interests. The operating partnership believes it now has sufficient field compression and permits for vacuum operation for the foreseeable future.

Liquidity and Working Capital

Cash and cash equivalents totaled $12,039,000 at March 31, 2009 and $16,211,000 at December 31, 2008.

Critical Accounting Policies

We utilize the full cost method of accounting for costs related to our oil and natural gas properties. Under this method, all such costs are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the units-of-production method. These capitalized costs are subject to a ceiling test, however, which limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves discounted at 10% plus the lower of cost or market value of unproved properties. Oil and natural gas properties are evaluated using the full cost ceiling test at the end of each quarter and when events indicate possible impairment.

The discounted present value of our 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 natural gas reserves based on the same information. Our reserve estimates are prepared by independent consultants. The passage of time provides more qualitative information regarding reserve estimates, and revisions are made to prior estimates based on updated information. However, there can be no assurance that significant revisions will not be necessary in the future. Significant downward revisions could result in an impairment representing a non-cash charge to earnings. In addition to the impact on calculation of the ceiling test, estimates of proved reserves are also a major component of the calculation of depletion.

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

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. For example, estimates of uncollected revenues and unpaid expenses from royalties and net profits interests in properties operated by non-affiliated entities are particularly subjective due to our inability to gain accurate and timely information. Therefore, actual results could differ from those estimates.