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 574 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 September 30, 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.

The following table sets forth receipts and disbursements attributable to the Minerals NPI:

                                                    Minerals NPI Results
                                                       (in Thousands)
                                        Cumulative                            Cumulative
                                          Total            Nine Months          Total
                                       at 12/31/08        Ended 9/30/09       at 9/30/09
    Cash received for revenue         $     14,216       $       2,518     $     16,734
    Cash paid for operating costs            2,226                 610            2,836
    Cash paid for development costs         11,724               3,377           15,101
    Budgeted capital expenditures              905                 481            1,386
    Net                               $       (639 )     $      (1,950 )   $     (2,589 )

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 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 and Nine Months Ended September 30, 2009 as compared to Three and Nine
Months Ended September 30, 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                  Nine Months Ended
                                    September 30,           June 30,           September 30,
Accrual basis sales volumes:     2009          2008           2009           2009          2008
Royalty properties gas sales
(mmcf)                             1,148         1,000          1,019          3,204         2,864
Royalty properties oil sales
(mbbls)                               71            77             80            225           229
Net profits interests gas
sales (mmcf)                         915           961            903          2,705         2,922
Net profits interests oil
sales (mbbls)                          3             2              3              9             9

Accrual basis weighted
average sales price:
Royalty properties gas sales
($/mcf)                        $    3.39     $    9.41     $     3.47     $     3.63     $    9.31
Royalty properties oil sales
($/bbl)                        $   63.94     $  115.62     $    55.90     $    52.74     $  109.33
Net profits interests gas
sales ($/mcf)                  $    3.04     $    7.76     $     2.95     $     3.10     $    9.23
Net profits interests oil
sales ($/bbl)                  $   58.76           N/A     $    55.70     $    47.27     $  118.47

Accrual basis production
costs deducted
Under the net profits
interests ($/mcfe) (1)         $    1.45     $    1.90     $     1.41     $     1.44     $    1.94

(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 third quarter were down 7.8% from 77 mbbls during the third quarter of 2008 to 71 mbbls in the same period of 2009 due to normal production volume variations. Oil sales volumes attributable to our Royalty Properties during the first nine months were down slightly at 225 mbbls in 2009 compared to 229 mbbls in 2008. Natural gas sales volumes attributable to our Royalty Properties during the third quarter increased 14.8% from 1,000 mmcf in 2008 to 1,148 mmcf in 2009. Natural gas sales volumes attributable to our Royalty Properties during the first nine months increased 11.9% from 2,864 in 2008 to 3,204 mmcf in 2009. The increase in natural gas sales volumes was primarily attributable to the acquisition of properties in the Barnett Shale during the second quarter of 2009.

Oil sales volumes attributable to our Net Profits Interests during the third quarter and first nine months of 2009 were virtually unchanged when compared to the same periods of 2008. Natural gas sales volumes attributable to our Net Profits Interests during the third quarter and first nine months of 2009 decreased from the same periods of 2008. Third quarter sales volumes of 915 mmcf during 2009 were 4.8% less than 961 mmcf during 2008. First nine month sales volumes of 2,705 mmcf during 2009 were 7.4% less than 2,922 mmcf during 2008. Both natural gas sales volume decreases were a result of natural reservoir decline. Production sales volumes and prices from the Minerals NPI are excluded from the above table. See "Overview" above.

The weighted average oil sales prices attributable to our interest in Royalty Properties decreased 44.7% from $115.62/bbl during the third quarter of 2008 to $63.94/bbl during the third quarter of 2009 and decreased 51.8% from $109.33/bbl during the first nine months of 2008 to $52.74/bbl during the same period of 2009. Third quarter weighted average natural gas sales prices from Royalty Properties decreased 64.0% from $9.41/mcf during 2008 to $3.39/mcf during 2009. The nine months ended September 30 weighted average Royalty Properties natural gas sales prices decreased 61.0% from $9.31/mcf during 2008 to $3.63/mcf during 2009. Both oil and natural gas price changes resulted from changing market conditions.

Third quarter weighted average oil sales prices from the Net Profits Interests properties decreased significantly from 2008 to $58.76/bbl in 2009. The third quarter of 2008 included a purchaser correction that significantly distorted the price due to small volumes; thus, we have not shown an average price in order to avoid confusion. The first nine months Net Profits Interests' oil sales prices decreased 60.1% from $118.47/bbl in 2008 to $47.27/bbl in 2009. Changing market conditions resulted in decreased oil prices. Weighted average natural gas sales prices attributable to the Net Profits Interests decreased during the third quarter of 2009 and first nine months of 2009 compared to the same periods of 2008. Third quarter natural gas sales prices of $3.04/mcf in 2009 were 60.8% less than $7.76/mcf in 2008. The nine months ended September 30, 2009 natural gas prices decreased 66.4% to $3.10/mcf from $9.23/mcf in the same period of 2008. Natural gas sales price decreases during the three- and nine- month periods resulted from changing market conditions and, to a lesser degree, a natural gas liquids payment received in 2008 that related to prior year production. 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

Our third quarter net operating revenues decreased 56.3% from $24,487,000 during 2008 to $10,706,000 during 2009. Net operating revenues for the first nine months of 2009 decreased 60.9% from $74,747,000 during 2008 to $29,214,000 during 2009. Both the quarterly and nine-month decrease resulted from decreased gas and oil sales prices combined with a 2007 natural gas liquid payment received during the second quarter 2008.

Costs and expenses increased 5.0% from $6,010,000 during the third quarter of 2008 to $6,312,000 during the third quarter of 2009, while nine months ended September 30 costs and expenses decreased 7.5% from $17,855,000 during 2008 to $16,520,000 during 2009. The third quarter increase primarily resulted from increased depletion related to the Barnett Shale acquisition at the end of the second quarter partially offset by decreased production tax on lower operating revenues. The decrease in the nine-month period primarily resulted from decreased production tax.

Depletion and amortization increased 19.8% during the third quarter ended September 30, 2009 and 0.7% during the nine months ended September 30, 2009 when compared to the same periods of 2008. The increases from $3,775,000 and $11,213,000 during the third quarter and nine months ended September 30, 2008, respectively, to $4,524,000 and $11,297,000 during the same periods of 2009 respectively, resulted primarily from a higher depletable base due to the June 30, 2009 acquisition of properties in the Barnett Shale.

Third quarter net earnings allocable to common units decreased 76.3% from $17,997,000 during 2008 to $4,263,000 during 2009. First nine months common unit net earnings decreased 77.5% from $55,448,000 during 2008 to $12,476,000 during 2009. Both decreases are primarily the result of decreased oil and natural gas sales prices.

Net cash provided by operating activities decreased 67.3% from $28,082,000 during the third quarter of 2008 to $9,181,000 during the third quarter of 2009 and decreased 57.8% from $67,968,000 for the first nine months during 2008 to $28,692,000 during the same period of 2009. Decreases in both periods are primarily due to decreased oil and natural gas sales prices.

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 third quarter totaled approximately $7,800,000. These receipts generally reflect oil sales during June through August 2009 and natural gas sales during May through July 2009. The weighted average indicated prices for oil and natural gas sales during the 2009 third quarter attributable to the Royalty Properties were $62.52/bbl and $3.46/mcf, respectively.

Cash receipts attributable to our Net Profits Interests during the 2009 third quarter totaled approximately $1,600,000. These receipts reflect oil and natural gas sales from the properties underlying the Net Profits Interests generally during May through July 2009. The weighted average indicated prices received during the 2009 third quarter for oil and natural gas sales were $55.30/bbl and $3.07/mcf, respectively.

We received cash payments of approximately $560,000 from various sources during the third quarter of 2009 including lease bonuses attributable to 25 consummated leases and pooling elections located in five counties and parishes in three states. The consummated leases reflected royalty terms ranging up to 25% and lease bonuses ranging up to $1,200/acre.

We received division orders for, or otherwise identified, 71 new wells completed on our Royalty Properties and Net Profits Interests located in 38 counties and parishes in seven states during the third quarter of 2009. The operating partnership elected to participate in ten wells to be drilled on our Net Profits Interests located in three counties in Arkansas. 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 tables below.

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
              Marathon Oil
 ND   Dunn    Co.          Borth 41-14 H   0.916%    --     --         207      451
              Marathon Oil Gehrer 21-14
 ND   Dunn    Co.          H               0.916%    --     --       1,640      396
              Cimarex
 OK   Garvin  Energy Co.   Cole 1-5        1.363%    --     --         292      484
              Cimarex      Howard D 4-17
 OK   Garvin  Energy Co.   ENT             1.563%    --     --         215      181
              Dewbre       E.E. Guerra

(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 eighty-two wells have been permitted on the lands as of September 30, 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 third 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
                     Collinsworth 7-16
Conway    Chesapeake #1-10H3               2.312%   4.553% 3.414%    4,815
                     Green Bay Packaging
Conway    SEECO      9-15 #3-19H           0.056%   0.000% 0.000%    4,221
                     Green Bay Packaging
Conway    SEECO      9-15 #4-19H           0.056%   0.000% 0.000%    4,242
Conway    SEECO      Polk 9-15 #4-30H      5.930%   5.561% 4.220%    2,434
Faulkner  Chesapeake Glover 8-13 #1-25H    3.222%   7.185% 5.648%    1,433
Faulkner  Chesapeake Glover 8-13 #2-25H    2.990%   4.807% 3.614%    2,439
                     Collister 12-13
Van Buren Chesapeake #2-32H                1.561%   1.274% 0.956%       228
                     Collister 12-13
Van Buren Chesapeake #3-32H                1.561%   1.274% 0.956%       469
                     Green Bay 11-14
Van Buren Petrohawk  #1-20H                0.703%   0.000% 0.000%       723
Van Buren Petrohawk  Trahan 11-14 #1-30H   0.039%   0.000% 0.000%    4,144
                     Handy 10-12
Van Buren SEECO      #3-18H19              0.395%   0.944% 0.708%    4,180
Van Buren SEECO      Handy 10-12 #4-18H    2.971%   6.344% 4.758%    2,876
Van Buren SEECO      Handy 10-12 #5-18H    2.972%   6.347% 4.760%    3,679
Van Buren SEECO      Handy 10-12 #6-18H    2.972%   6.347% 4.760%    3,422
                     Howard Family Trust
Van Buren SEECO      10-12 #2-9H16         2.594%   4.576% 3.432%    5,184

(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.

Set forth below are totals and a summary of permitting, drilling and completion activity through September 30, 2009 for wells in which we have a royalty interest or Net Profits Interest. This includes wells subject to the Minerals NPI, which is currently in a deficit status.

                   Total to        Year       Year
                    date (2)       2006       2007         Q1 2008       Q2 2008       Q3 2008       Q4 2008       Q1 2009       Q2 2009       Q3 2009
New Well
Permits                180           11          35          16            21            12            21            19            20            22
Wells Spud             145            9          33          12            17            20            13            21            15              4
Wells Completed        126            5          23          10            17            12            17            13            14            14
Wells in Pay
Status (1)               85           0          14            4             7           14              7           14            10            14

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

(2) Includes activity since 2004.

Net cash receipts for the Royalty Properties attributable to interests in these lands totaled $306,000 in the third quarter from 72 wells. Net cash receipts for the Minerals NPI Properties attributable to interests in these lands totaled approximately $280,000 in the third quarter from 44 wells.

BARNETT SHALE -- We own producing and nonproducing mineral and royalty interests located in Tarrant County, Texas. The properties consist of varying undivided mineral and overriding royalty interests in six tracts totaling approximately 1,820 acres in what is commonly referred to as the Core Area of the Barnett Shale Trend. All of the mineral interests were leased in 2003 to a predecessor of Chesapeake Energy Corporation, the current operator of and majority working interest owner in the properties. Approximately 577 acres of the subject lands are pooled into six units totaling 1,800 acres, approximately 1,129 acres are developed on a lease basis and the remaining lands are leased but not pooled or drilled upon. As of September 30, 2009, 34 wells were drilled from 11 padsites located on or adjacent to the properties, of which 27 wells were completed for production and seven were drilled but not yet completed or connected to a pipeline. Permits to drill two additional wells on the properties had been issued by regulatory agencies.

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. Seventy-nine wells have been permitted on these lands as of September 30, 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 will be 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 are totals and a summary of permitting, drilling and completion activity through September 30, 2009 for wells in which we have a royalty interest or Net Profits Interest.

                          Total to   Year   Year    Q1     Q2     Q3     Q4     Q1     Q2     Q3
                          Date(2)    2006   2007   2008   2008   2008   2008   2009   2009   2009
New Well Permits             82       0      16     10     17     16     14     0      6      0
Wells Spud                   69       0      12      2     10     11     10     11     4      7
Wells Completed              54       0       7      5      5     11      6     12     5      1
WI Wells in Pay Status(1)     3       0       0      0      2      1      0      0     0      0

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

(2) Includes activity since 2004.

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.

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 4 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 believes it now has sufficient field compression and permits for vacuum operation for the foreseeable future. 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."

Liquidity and Working Capital

Cash and cash equivalents totaled $10,012,000 at September 30, 2009 and . . .