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 June 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 Total        Six Months         Cumulative Total
                               at 12/31/08          Ended 6/30/09          at 6/30/09
Cash received for revenue   $           14,216     $         1,538     $           15,754
Cash paid for operating
costs                                    2,226                 384                  2,610
Cash paid for development
costs                                   11,724               2,076                 13,800
Budgeted capital
expenditures                               905                 948                  1,853
Net                         $             (639 )   $        (1,870 )   $           (2,509 )

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 Six Months Ended June 30, 2009 as compared to Three and Six Months
Ended June 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                  Six Months Ended
                                      June 30,             March 31,             June 30,
 Accrual basis sales volumes:     2009         2008          2009           2009          2008
 Royalty properties gas sales
 (mmcf)                            1,019          872           1,037         2,056        1,864
 Royalty properties oil sales
 (mbbls)                              80           80              74           154          152
 Net profits interests gas
 sales (mmcf)                        903          974             887         1,790        1,961
 Net profits interests oil
 sales (mbbls)                         3            3               3             6            7

 Accrual basis weighted
 average sales price:
 Royalty properties gas sales
 ($/mcf)                        $   3.47     $  10.73     $      4.05     $    3.76     $   9.26
 Royalty properties oil sales
 ($/bbl)                        $  55.90     $ 116.43     $     38.45     $   47.54     $ 106.14
 Net profits interests gas
 sales ($/mcf)                  $   2.95     $  11.90     $      3.32     $    3.13     $   9.96
 Net profits interests oil
 sales ($/bbl)                  $  55.70     $ 116.81     $     28.63     $   42.07     $  98.18

 Accrual basis production
 costs deducted
 under the net profits
 interests ($/mcfe) (1)         $   1.41     $   1.94     $      1.45     $    1.43     $   1.96

(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 second quarter were unchanged at 80 mbbls in 2009 and in 2008. Oil sales volumes attributable to our Royalty Properties during the first six months were also virtually unchanged at 154 mbbls in 2009 compared to 152 mbbls in 2008. Natural gas sales volumes attributable to our Royalty Properties during the second quarter increased 16.9% from 872 mmcf in 2008 to 1,019 mmcf in 2009. Natural gas sales volumes attributable to our Royalty Properties during the first six months increased 10.3% from 1,864 in 2008 to 2,056 mmcf in 2009. The increase in natural gas sales volumes 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 second quarter and first six 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 second quarter and first six months of 2009 decreased from the same periods of 2008. Second quarter sales volumes of 903 mmcf during 2009 were 7.3% less than 974 mmcf during 2008. First six month sales volumes of 1,790 mmcf during 2009 were 8.7% less than 1,961 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 52.0% from $116.43/bbl during the second quarter of 2008 to $55.90/bbl during the second quarter of 2009 and decreased 55.2% from $106.14/bbl during the first six months of 2008 to $47.54/bbl during the same period of 2009. Second quarter weighted average natural gas sales prices from Royalty Properties decreased 67.7% from $10.73/mcf during 2008 to $3.47/mcf during 2009. The six months ended June 30 weighted average Royalty Properties natural gas sales prices decreased 59.4% from $9.26/mcf during 2008 to $3.76/mcf during 2009. Both oil and natural gas price changes resulted from changing market conditions.

Second quarter weighted average oil sales prices from the Net Profits Interests' properties decreased 52.3% from $116.81/bbl in 2008 to $55.70/bbl in 2009. The first six months Net Profits Interests' oil sales prices decreased 57.2% from $98.18/bbl in 2008 to $42.07/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 second quarter of 2009 and first six months of 2009 compared to the same periods of 2008. Second quarter natural gas sales prices of $2.95/mcf in 2009 were 75.2% less than $11.90/mcf in 2008. The six months ended June 30, 2009 natural gas prices decreased 68.6% to $3.13/mcf from $9.96/mcf in the same period of 2008. Natural gas sales price decreases during the three- and six- month periods resulted from changing market conditions along with 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 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.

Costs and expenses decreased 12.3% from $5,853,000 during the second quarter of 2008 to $5,134,000 during the second quarter of 2009, while six months ended June 30 costs and expenses decreased 13.8% from $11,845,000 during 2008 to $10,208,000 during 2009. Such decreases primarily resulted from decreased production tax on lower operating revenues and reduced depletion and amortization.

Depletion and amortization decreased 4.8% during the second quarter ended June 30, 2009 and 8.9% during the six months ended June 30, 2009 when compared to the same periods of 2008. The decreases from $3,648,000 and $7,438,000 during the second quarter and six months ended June 30, 2008, respectively, to $3,473,000 and $6,773,000 during the same periods of 2009 respectively, 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.

Second quarter net earnings allocable to common units decreased 79.7% from $22,504,000 during 2008 to $4,559,000 during 2009. First six months common unit net earnings decreased 78.1% from $37,451,000 during 2008 to $8,213,000 during 2009. Both decreases are primarily the result of decreased oil and natural gas sales prices.

Net cash provided by operating activities decreased 65.7% from $22,683,000 during the second quarter of 2008 to $7,776,000 during the second quarter of 2009 and decreased 51.1% from $39,886,000 for the first six months during 2008 to $19,511,000 during the same period of 2009. Decreases in both periods are primarily due to decreased oil and natural gas sales prices. Abnormal natural gas liquid payments were also received in first quarter 2009 and second quarter 2008. See discussion above on net operating revenues for more details.

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 second quarter totaled $7,009,000. These receipts generally reflect oil sales during March through May 2009 and natural gas sales during February through April 2009. The weighted average indicated prices for oil and natural gas sales during the 2009 second quarter attributable to the Royalty Properties were $46.58/bbl and $3.75/mcf, respectively.

Cash receipts attributable to our Net Profits Interests during the 2009 second quarter totaled $1,532,000. These receipts reflect oil and natural gas sales from the properties underlying the Net Profits Interests generally during February through April 2009. The weighted average indicated prices received during the 2009 second quarter for oil and natural gas sales were $37.91/bbl and $2.94/mcf, respectively.

We received cash payments in the amount of $249,000 from various sources during the second quarter of 2009 including lease bonuses attributable to ten 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 $200/acre.

Our second quarter cash distribution included $1,067,000 of second quarter cash receipts from the acquired Barnett Shale properties. This cash payment contained non-recurring items and, therefore, may not be reflective of future cash generated by the acquired properties. See Note 3 to the consolidated financial statements and Barnett Shale discussion below.

We received division orders for, or otherwise identified, 106 new wells completed on our Royalty Properties and Net Profits Interests located in 46 counties and parishes in 11 states during the second quarter of 2009. The operating partnership elected to participate in 20 wells to be drilled on our Net Profits Interests located in seven 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 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
OK    Ellis   Crusader Energy   Raiders 5-27H      --     3.750% 9.063%        1,142       176
                                Guerra USA GU
TX    Starr   El Paso E&P Co.   "D" #17          8.194%     --     --          6,800        --
                                Guerra USA GU
TX    Starr   El Paso E&P Co.   "D" #18          8.194%     --     --            366         5
                                Garza
TX    Starr   Ram Operating Co. Hitchcock #18    2.653%     --     --          2,491        --
                                Burrell A W

(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 fifty-seven wells have been permitted on the lands as of June 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 second 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.

                                                DMLP          DMOLP        Gas Test Rates
County    Operator    Well Name                NRI(2)     WI(1)  NRI(2)     mcf per day
Cleburne  SEECO       Mulliniks 9-12 #6-35H2   1.401%    1.992%  1.494%         4,323
                      Collinsworth 7-16
Conway    Chesapeake  #1-10H3                  2.312%    4.553%  3.414%          --
                      Charles Reeves 9-15
Conway    SEECO       #3-10H3                  2.849%    4.559%  3.419%         3,976
                      Charles Reeves 9-15
Conway    SEECO       #4-10H3                  2.974%    4.758%  3.569%         1,895
                      Charles Reeves 9-15
Conway    SEECO       #5-10H3                  2.974%    4.375%  3.569%         3,884
Conway    SEECO       Polk 9-15 #4-30H         5.930%    5.561%  4.220%          --
Faulkner  Chesapeake  Hooten 8-12 #1-17H       0.752%    0.000%  0.000%          --
Van Buren Petrohawk   Green Bay 11-14 #1-20H   0.703%    0.000%  0.000%          --
Van Buren Petrohawk   Thacker 9-12 #2-21H      2.343%    4.375%  3.281%         1,538
                      Howard Family Trust
Van Buren SEECO       10-12 #2-9H16            2.594%    4.576%  3.432%          --
                      Collums-Pennington
Van Buren SEECO       10-12 #1-20H             2.344%    4.375%  3.281%         2,081
                      Collums-Pennington
Van Buren SEECO       10-12 #2-20H             2.344%    4.375%  3.281%         2,229

(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.

                            Total to    Year   Year    Q1     Q2     Q3     Q4     Q1     Q2
                             date (2)   2006   2007   2008   2008   2008   2008   2009   2009
    New Well Permits           157       11     35     16     21     12     21     19     19
    Wells Spud                 132        9     33     12     17     19     13     21      7
    Wells Completed            111        5     23     10     17     12     17     12     14
    Wells in Pay Status (1)     71        0     14      4      7     14      7     14     10

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

(2) Includes activity begun in year 2004.

Net cash receipts for the Royalty Properties attributable to interests in these lands totaled $306,000 in the second quarter from 57 wells. Net cash receipts for the Minerals NPI Properties attributable to interests in these lands totaled $337,000 in the second quarter from 37 wells.

BARNETT SHALE - On May 15, 2009, we executed a definitive agreement to acquire 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 May 15, 2009, 32 wells were drilled from 11 padsites located on or adjacent to the properties, of which 26 wells were completed for production and six were drilled but not yet completed or connected to a pipeline. Permits to drill four additional wells on the properties had been issued by regulatory agencies.

The transaction was consummated on June 30, 2009 and was structured as a non-taxable contribution and exchange. At the closing, in addition to conveying their interests to us, the contributing parties delivered funds in an amount equal to their cash receipts less cash disbursements during period April 1, 2009 through June 30, 2009 and we conveyed an aggregate of 1,600,000 common limited partnership units to the contributing parties. The funds delivered at closing totaled $1,067,000; approximately $520,000 of these funds were attributable to the production during January, February and March 2009. The balance of the funds was attributable to prior production periods and primarily due to one-time release of production revenues previously suspended by the purchaser.

Estimated proved developed reserves of 5,584.6 mmcf were assigned to the acquired properties as of June 30, 2009 based on the report of independent petroleum engineering consultant firm Huddleston & Co., Inc. These reserves include proved developed nonproducing reserves assigned to six wells. No proved undeveloped reserves were assigned to four permitted but undrilled locations or otherwise to the properties.

As of July 31, 2009, one of these six wells had been completed and was producing to sales. In addition, one of the permitted locations had been drilled and was waiting on completion and one other was drilling.

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. Seventy-two wells have been permitted on these lands as of June 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 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.

                             Total to   Year   Year    Q1     Q2     Q3     Q4     Q1     Q2
                             Date(2)    2006   2007   2008   2008   2008   2008   2009   2009
   New Well Permits             72       0      15     8      16     15     12      0     3
   Wells Spud                   58       0      12     2      10     10      9     11     2
   Wells Completed              44       0       7     5       5     10      6      8     1
   WI Wells in Pay Status(1)     3       0       0     0       2      1      0      0     0

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

(2) Includes Activity begun in year 2004.

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 . . .