UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC.  20549

FORM 10-Q

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2012

or

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from __________ to __________

Commission file number 000-50175

DORCHESTER MINERALS, L.P.

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization) 81-0551518 (I.R.S. Employer Identification No.)

3838 Oak Lawn Avenue, Suite 300, Dallas, Texas  75219

(Address of principal executive offices)  (Zip Code)

Registrant's telephone number, including area code:  (214) 559-0300

None

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "large accelerated filer”, “accelerated filer” and “smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer x	Accelerated filer ¨	Non-accelerated filer o	Smaller reporting companyo
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act.): Yes o No x

As of August 8, 2012, 30,675,431 common units representing limited partnership interests were outstanding.

TABLE OF CONTENTS

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS			1
PART I– FINANCIAL INFORMATION			1
	ITEM 1.	FINANCIAL STATEMENTS	1
		CONDENSED CONSOLIDATED BALANCE SHEETS AS OF JUNE 30, 2012 (UNAUDITED) AND DECEMBER 31, 2011	2
		CONDENSED CONSOLIDATED INCOME STATEMENTS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2012 AND 2011 (UNAUDITED)	3
		CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2012 AND 2011 (UNAUDITED)	4
		NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	5
	ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	6
	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	12
	ITEM 4	CONTROLS AND PROCEDURES	12
PART II–OTHER INFORMATION			13
	ITEM 1.	LEGAL PROCEEDINGS	13
	ITEM 6.	EXHIBITS	13
SIGNATURES			14
INDEX TO EXHIBITS
CERTIFICATIONS

DORCHESTER MINERALS, L.P.

(A Delaware Limited Partnership)

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

Statements included in this report that are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions or forecasts related thereto), are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “will,” “expect,” “anticipate,” “estimate,” “continue” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information. In this report, the term “Partnership,” as well as the terms “DMLP,” “us,” “our,” “we,” and “its” are sometimes used as abbreviated references to Dorchester Minerals, L.P. itself or Dorchester Minerals, L.P. and its related entities.

These forward-looking statements are based upon management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and, therefore, involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements for a number of important reasons. Examples of such reasons include, but are not limited to, changes in the price or demand for oil and natural gas, changes in the operations on or development of our properties, changes in economic and industry conditions and changes in regulatory requirements (including changes in environmental requirements) and our financial position, business strategy and other plans and objectives for future operations. These and other factors are set forth in our filings with the Securities and Exchange Commission.

You should read these statements carefully because they discuss our expectations about our future performance, contain projections of our future operating results or our future financial condition, or state other “forward-looking” information. Before you invest, you should be aware that the occurrence of any of the events described in this report could substantially harm our business, results of operations and financial condition and that upon the occurrence of any of these events, the trading price of our common units could decline, and you could lose all or part of your investment.

1

PART I – FINANCIAL INFORMATION

ITEM 1.     FINANCIAL STATEMENTS

DORCHESTER MINERALS, L.P.

(A Delaware Limited Partnership)

CONDENSED CONSOLIDATED BALANCE SHEETS

(In Thousands)

	June 30, 2012			December 31, 2011
ASSETS	(unaudited)
Current assets:
Cash and cash equivalents	$	15,350		$	14,238
Trade and other receivables		5,016			6,602
Net profits interests receivable - related party		1,862			7,616
Prepaid expenses		25			-
Total current assets		22,253			28,456
Other non-current assets		19			19
Total		19			19
Property and leasehold improvements - at cost:
Oil and natural gas properties (full cost method)		344,196			344,196
Accumulated full cost depletion		(238,830	)		(230,060	)
Total		105,366			114,136
Leasehold improvements		512			512
Accumulated amortization		(378	)		(354	)
Total		134			158
Total assets	$	127,772		$	142,769
LIABILITIES AND PARTNERSHIP CAPITAL
Current liabilities:
Accounts payable and other current liabilities	$	955		$	529
Current portion of deferred rent incentive		39			39
Total current liabilities		994			568
Deferred rent incentive less current portion		70			90
Total liabilities		1,064			658
Commitments and contingencies (Note 2)
Partnership capital:
General partner		3,868			4,242
Unitholders		122,840			137,869
Total partnership capital		126,708			142,111
Total liabilities and partnership capital	$	127,772		$	142,769

The accompanying condensed notes are an integral part of these condensed consolidated financial statements.

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DORCHESTER MINERALS, L.P.

(A Delaware Limited Partnership)

CONDENSED CONSOLIDATED INCOME STATEMENTS

(In Thousands except Earnings per Unit)

(Unaudited)

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Operating revenues:
Royalties	$	11,665	$	14,106	$	24,362	$	26,234
Net profits interests		318		2,014		744		4,093
Lease bonus		3,127		253		3,403		330
Other		132		61		166		66
Total operating revenues		15,242		16,434		28,675		30,723
Costs and expenses:
Operating, including production taxes		1,199		1,322		2,231		2,473
Depletion and amortization		4,482		4,581		8,794		8,823
General and administrative expenses		881		761		1,684		1,917
Total costs and expenses		6,562		6,664		12,709		13,213
Operating income		8,680		9,770		15,966		17,510
Other income, net		-		-		12		-
Net earnings	$	8,680	$	9,770	$	15,978	$	17,510
Allocation of net earnings:
General partner	$	341	$	350	$	625	$	619
Unitholders	$	8,339	$	9,420	$	15,353	$	16,891
Net earnings per common unit (basic and diluted)	$	0.27	$	0.31	$	0.50	$	0.55
Weighted average common units outstanding		30,675		30,675		30,675		30,675

The accompanying condensed notes are an integral part of these condensed consolidated financial statements.

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DORCHESTER MINERALS, L.P.

(A Delaware Limited Partnership)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

	Six Months Ended June 30,
	2012			2011
Net cash provided by operating activities	$	32,493		$	27,614
Cash flows used in investing activities:
Adjustment related to acquisition of natural gas properties		-			(4	)
Cash flows used in financing activities:
Distributions paid to general partner and unitholders		(31,381	)		(24,753	)
Increase in cash and cash equivalents		1,112			2,857
Cash and cash equivalents at beginning of period		14,238			11,253
Cash and cash equivalents at end of period	$	15,350		$	14,110

The accompanying condensed notes are an integral part of these condensed consolidated financial statements.

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DORCHESTER MINERALS, L.P.

(A Delaware Limited Partnership)

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 (Unaudited)

1       Basis of Presentation: Dorchester Minerals, L.P. is a publicly traded Delaware limited partnership that was formed in December 2001, and commenced operations on January 31, 2003.  The consolidated financial statements include the accounts of Dorchester Minerals, L.P. and its wholly-owned subsidiaries Dorchester Minerals Oklahoma LP, Dorchester Minerals Oklahoma GP, Inc., Maecenas Minerals LLP, and Dorchester-Maecenas GP LLC.  All significant intercompany balances and transactions have been eliminated in consolidation.

The condensed consolidated financial statements reflect all adjustments (consisting only of normal and recurring adjustments unless indicated otherwise) that are, in the opinion of management, necessary for the fair presentation of our financial position and operating results for the interim period. Interim period results are not necessarily indicative of the results for the calendar year. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information. Per-unit information is calculated by dividing the earnings or loss applicable to holders of our Partnership’s common units by the weighted average number of units outstanding. The Partnership has no potentially dilutive securities and, consequently, basic and dilutive earnings or loss per unit do not differ.  These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Partnership’s annual report on Form 10-K for the year ended December 31, 2011.

Fair Value of Financial Instruments — The carrying amount of cash and cash equivalents, trade receivables and payables approximates fair value because of the short maturity of those instruments. These estimated fair values may not be representative of actual values of the financial instruments that could have been realized as of quarter close or that will be realized in the future.

2       Contingencies:  In January 2002, some individuals and an association called Rural Residents for Natural Gas Rights sued Dorchester Hugoton, Ltd., along with several other operators in Texas County, Oklahoma regarding the use of natural gas from the wells in residences. The operating partnership now owns and operates the properties formerly owned by Dorchester Hugoton. These properties contribute a significant portion of the NPI amounts paid to us. On April 9, 2007, plaintiffs, for immaterial costs, dismissed with prejudice all claims against the operating partnership regarding such residential gas use. On October 4, 2004, the plaintiffs filed severed claims against the operating partnership regarding royalty underpayments, which the Texas County District Court subsequently dismissed with a grant of time to replead. On January 27, 2006, one of the original plaintiffs again sued the operating partnership for underpayment of royalty, seeking class action certification. On October 1, 2007, the Texas County District Court granted the operating partnership’s motion for summary judgment finding no royalty underpayments. Subsequently, the District Court denied the plaintiff’s motion for reconsideration, and the plaintiff filed an appeal. On March 31, 2010, the appeal decision reversed and remanded to the Texas County District Court to resolve material issues of fact.  On June 30, 2011, the District Court issued a revised partial summary judgment in favor of the operating partnership.  On April 27, 2012, the parties successfully mediated terms for a settlement in the amount of $500,000 plus immaterial future royalty amounts on fuel gas; which, will be paid to the plaintiffs upon finalization of the agreed settlement and ultimate approval by the District Court.  A $500,000 reserve was recorded in Net Profits Revenues on the financial statements in the first quarter of 2012.

The Partnership and the operating partnership are involved in other legal and/or administrative proceedings arising in the ordinary course of their businesses, none of which have predictable outcomes and none of which are believed to have any significant effect on consolidated financial position, cash flows, or operating results.

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3       Distributions to Holders of Common Units:Unitholder cash distributions per common unit since 2008 have been:

	Per Unit Amount
	2012		2011		2010		2009		2008
First quarter	$	0.541883	$	0.426745	$	0.449222	$	0.401205	$	0.572300
Second quarter	$	0.456351	$	0.417027	$	0.412207	$	0.271354	$	0.769206
Third quarter			$	0.455546	$	0.471081	$	0.286968	$	0.948472
Fourth quarter			$	0.448553	$	0.354074	$	0.321540	$	0.542081

Distributions from first quarter of 2010 through the present were paid on 30,675,431 units; distributions from the second quarter of 2009 through the fourth quarter of 2009 were paid on 29,840,431 units; previous distributions above were paid on 28,240,431 units.  The second quarter 2012 distribution was paid on August 2, 2012.  Fourth quarter distributions shown above are paid in the first calendar quarter of the following year.  Our partnership agreement requires the next cash distribution to be paid by November 15, 2012.

ITEM 2.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion contains forward-looking statements.  For a description of limitations inherent in forward-looking statements, see page 1 of this Form 10-Q.

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.

We own net profits overriding royalty interests (referred to as the Net Profits Interests, or “NPIs”) in various properties owned by Dorchester Minerals Operating LP, a Delaware limited partnership owned directly and indirectly by our general partner. We refer to Dorchester Minerals Operating LP as the “operating partnership” or “DMOLP.” We receive monthly payments equaling 96.97% of the net profits actually realized by the operating partnership from these properties in the preceding month. In the event costs exceed revenues on a cash basis in a given month for properties subject to a Net Profits Interest, no payment is made and any deficit is accumulated and carried over and reflected in the following month's calculation of net profit.

We own six NPIs. The Minerals NPI (one of the six) owns certain cost bearing interests that were either in existence at the time of our formation, or created subsequent to our formation but associated with nonproducing mineral, royalty and leasehold interest properties acquired upon our formation. The Minerals NPI achieved a cumulative net profit status on September 30, 2011 as a result of its cumulative net revenue exceeding cumulative operating and actual and budgeted capital expenditures and development costs. Subsequent Minerals NPI amounts and payments distributed to us are:

			Distribution
NPI Period Ended	NPI		Amount		Period
Nov. 30, 2011	$	1,347,000	$	1,306,000	4th Qtr. 2011
Feb. 29, 2012	$	709,000	$	688,000	1st Qtr. 2012
May 31, 2012	$	354,000	$	343,000	2nd Qtr. 2012

 Our consolidated financial statements reflect activity attributable to the Minerals NPI and include a portion of 2012 cash receipts and disbursements and accrued revenues and costs not yet received or paid. Prior to the Minerals NPI achieving a cumulative payout status, activity attributable to the Minerals NPI was not reflected in our consolidated financial statements in accordance with generally accepted accounting principles. Effective third quarter 2011, consolidated financial statements reflect activity attributable to the Minerals NPI, and will continue to do so regardless of its net profit status on a cumulative or reporting period basis. As of June 30, 2012, each of the six NPIs has had cumulative revenue that exceeds cumulative costs, such excess constituting net proceeds on which NPI payments were determined. If and when an NPI has a deficit of cumulative revenue versus cumulative costs, the deficit will be borne solely by the operating partnership.

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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, 2012 as compared to Three and Six Months Ended June 30, 2011

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:	2012		2011		2012		2012		2011
Royalty properties gas sales (mmcf)		1,718		1,558		1,597		3,315		2,900
Royalty properties oil sales (mbbls)		92		81		87		179		159
NPI gas sales (mmcf)		1,068		778		1,118		2,186		1,563
NPI oil sales (mbbls)		16		2		15		31		4
Accrual basis weighted average sales price:
Royalty properties gas sales ($/mcf)	$	2.10	$	3.95	$	2.51	$	2.30	$	3.95
Royalty properties oil sales ($/bbl)	$	87.69	$	98.44	$	99.49	$	93.44	$	93.07
NPI gas sales ($/mcf)	$	2.16	$	4.33	$	2.35	$	2.26	$	4.25
NPI oil sales ($/bbl)	$	80.88	$	97.02	$	97.57	$	88.72	$	91.35
Accrual basis production and capital costs deducted under the NPIs ($/mcfe) (1)	$	2.91	$	2.11	$	3.01	$	2.96	$	1.98

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

Oil sales volumes attributable to our Royalty Properties during the second quarter were up 13.6% from 81 mbbls during the second quarter of 2011 to 92 mbbls in the same period of 2012. Oil sales volumes attributable to our Royalty Properties during the first six months were up 12.6% from 159 mbbls in 2011 to 179 mbbls in 2012.  Natural gas sales volumes attributable to our Royalty Properties during the second quarter increased 10.3% from 1,558 mmcf in 2011 to 1,718 mmcf in 2012. Natural gas sales volumes attributable to our Royalty Properties during the first six months increased 14.3% from 2,900 mmcf in 2011 to 3,315 mmcf in 2012. The increase in oil and natural gas sales volumes was primarily attributable to activity in the Barnett Shale, and continued development activities on the Royalty Properties.

Sales volumes and prices attributable to the Minerals NPI during periods prior to the third quarter of 2011 are excluded from the above table because DMLP did not receive any payments from such NPI sales volumes during those prior periods.  Oil sales volumes attributable to our NPIs during the second quarter of 2012 were 16 mbbls, an increase of 700% from 2 mbbls during the same period of 2011.  Oil sales volumes attributable to our NPIs during the first six months increased 675% from 4 mbbls in 2011 to 31 mbbls in 2012.  Natural gas sales volumes attributable to our NPIs during the second quarter of 2012 also increased from the same periods of 2011.  Second quarter gas sales volumes of 1,068 mmcf during 2012 were 37.3% greater than 778 mmcf during 2011.  Similarly, natural gas volumes attributable to our NPI’s during the first six months increased 39.9% from 1,563 mmcf in 2011 to 2,186 in the same period of 2012. These increases are principally due to including the Minerals NPI.Minerals NPI oil sales volumes of 13 mbbls and 25 mbbls for the second quarter and first six months of 2012, respectively, and gas sales volumes of 333 mmcf and 691 mmcf for the same periods, respectively, are included in the Net Profits Interest volumes above.  See “Overview” above.

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The weighted average oil sales prices attributable to our interest in Royalty Properties decreased 10.9% from $98.44/bbl during the second quarter of 2011 to $87.69/bbl during the second quarter of 2012 and were about the same at $93.07/bbl during the first six months of 2011 compared to $93.44/bbl during the same period of 2012.  Second quarter weighted average natural gas sales prices from Royalty Properties decreased 46.8% from $3.95/mcf during 2011 to $2.10/mcf during 2012 and decreased 41.8% from $3.95/mcf during the first six months of 2011 to $2.30/mcf during the same period of 2012.  Both oil and natural gas price changes resulted from changing market conditions.

Second quarter weighted average oil sales prices from the NPIs decreased 16.6% from $97.02/bbl in 2011 to $80.88/bbl in 2012 and decreased 2.9% from $91.35/bbl during the first six months of 2011 to $88.72/bbl during the same period of 2012. Second quarter weighted average natural gas sales prices attributable to the NPIs decreased 50.1% from $4.33/mcf during 2011 to $2.16/mcf in 2012 and decreased 46.8% from $4.25/mcf during the first six months of 2011 to $2.26/mcf during the same period of 2012. Price changes during the three- and six-month periods resulted from changing market conditions.

Our second quarter total operating revenues decreased 7.3% from $16,434,000 during 2011 to $15,242,000 during 2012, and our first six months net operating revenues decreased 6.7% from $30,723,000 during 2011 to $28,675,000 during 2012 as a result of continued capital expenditures in the Minerals NPI, a first quarter 2012 Hugoton NPI litigation settlement reserve of $500,000, and decreased oil and gas prices.  These amounts were partially offset by increased oil and gas sales volumes as discussed above.

Costs and expenses of $6,562,000 and $12,709,000 during the second quarter and six months of 2012, respectively, were down 1.5% and 3.8%, compared to $6,664,000 and $13,213,000 during the same periods of 2011.  Increased general and administrative costs during the quarter were offset by reduced production tax on reduced operating revenues.

Depletion and amortization costs were $4,482,000 and $8,794,000 during the second quarter and first six months of 2012 compared to $4,581,000 and $8,823,000 during the same periods of 2011.  Increased sales volumes during 2012 were offset by the effects of upward reserve revisions at 2011 year-end along with the inclusion of Minerals NPI reserves.

Second quarter net earnings allocable to common units was down 11.5% from $9,420,000 during 2011 to $8,339,000 during 2012. First six months common unit net earnings decreased 9.1% from $16,891,000 during 2011 to $15,353,000 during 2012 due to decreased natural gas sales prices and the litigation reserve as discussed above, which was partially offset by oil and natural gas sales volumes and lease bonus income.

Net cash provided by operating activities increased 9.2% from $13,684,000 during the second quarter of 2011 to $14,946,000 during the second quarter of 2012 and increased 17.7% from $27,614,000 during the first six months of 2011 to $32,493,000 during the same period of 2012.   These increases are due to increased lease bonus income along with increased oil and natural gas sales volumes.

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.

8

Cash receipts attributable to our Royalty Properties during the 2012 second quarter totaled approximately $11,400,000. These receipts generally reflect oil sales during March through May 2012 and natural gas sales during February through April 2012.  The weighted average indicated prices for oil and natural gas sales during the 2012 second quarter attributable to the Royalty Properties were $96.57/bbl and $2.30/mcf, respectively.

Cash receipts attributable to our NPIs during the 2012 second quarter totaled approximately $1,100,000 and include Net Profits Interest payments from the Minerals NPI of approximately $343,000. These receipts reflect oil and natural gas sales from the properties underlying the NPIs generally during February through April 2012.  The weighted average indicated prices received during the 2012 second quarter for oil and natural gas sales were $93.33/bbl and $2.29/mcf, respectively.

Cash receipts attributable to lease bonus and other income during the second quarter of 2012 totaled approximately $3.2 million including proceeds from two notable leasing transactions.  The Partnership leased 506 net acres in the Lycoming County, Pennsylvania portion of the Marcellus Shale trend in multiple transactions for amounts ranging from $3,000 to $4,000 per acre and 20% royalty escalating to 25% in certain circumstances.  In addition, the Partnership leased 160 net acres in the Wheeler County, Texas portion of the Granite Wash trend for $7,000 per acre and 25% royalty.  Total lease bonus from these two transactions was approximately $2.8 million.  In total during the second quarter of 2012, there were 13 consummated leases and pooling elections located in 11 counties and parishes in four states.

We received division orders for, or otherwise identified, 104 new wells completed on our Royalty Properties and NPIs located in 33 counties and parishes in six states during the second quarter of 2012. The operating partnership elected to participate during the second quarter of 2012 in 10 wells to be drilled on our NPI properties located in four counties in three states.

Set forth below are summaries of recent activity on selected Royalty and NPI properties:

APPALACHIAN BASIN — We own varying undivided perpetual mineral interests in approximately 31,000/24,000 gross/net acres in 19 counties in southern New York and northern Pennsylvania. Approximately 75% of those net acres are located in eastern Allegany and western Steuben Counties, New York—an area that some industry press reports suggest may be prospective for gas production from unconventional reservoirs, including the Marcellus Shale. The New York State Department of Environmental Conservation has completed its regulatory review of high-volume hydraulic fracturing practices; however, development of these natural gas resources will be limited until remaining regulatory issues are resolved. We continue to monitor industry activity and encourage dialogue with industry participants to determine the proper course of action regarding our interests in this area.

FAYETTEVILLE SHALE, 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. Three hundred eighty one wells were permitted on the lands as of June 30, 2012, 224 of which the operating partnership owns an interest. In total, 359 wells were spud and 340 were completed as producers.  Leases covering approximately 10,722/5,310 gross/net acres expired in June, 2011 leaving approximately 8,933/4,448 gross/net acres held by production.  Industry participants were solicited during January 2012 to submit comprehensive proposals to lease all of the expired lands.  We rejected all of such proposals, and are responding to subsequent lease offers and well proposals on an individual basis.

9

Set forth below is a summary of Fayetteville Shale activity through June 30, 2012 for wells in which we have a royalty or Net Profits Interest. This includes wells subject to the Minerals NPI and wells for which we may not yet have received division orders or first payment.

	2004  through 2008	2009	2010	Q1 2011	Q2 2011	Q3 2011	Q4 2011	Q1 2012	Q2 2012	Total to Date
New Well Permits(1)	113	68	110	23	17	17	12	10	11	381
Wells Spud	103	70	88	21	28	26	9	8	6	359
Wells Completed(2)	81	49	88	29	18	17	33	19	6	340
Royalty Wells in Pay Status (3)	36	55	70	22	19	16	10	22	29	279

(1) Excludes permits that expire undrilled.

(2) Completion date is defined as the day the well commences production.

(3) 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 $581,000 in the second quarter of 2012 from 279 wells.  Net cash receipts for the Minerals NPI Properties attributable to interests in these lands totaled approximately $351,000 in the second quarter of 2012 from 174 wells.

HORIZONTAL BAKKEN, WILLISTON BASIN – We own varying undivided perpetual mineral interests totaling 70,390/8,905 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 Whiting Oil & Gas. Two hundred thirty five wells were permitted on these lands as of June 30, 2012, with 167 completed as producers. In most cases we elected to become a non-consenting mineral owner—who is not obligated to pay well costs. According to North Dakota law, non-consenting mineral 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 operating partnership will then own the working interest; subject to the Minerals NPI burden. Non-consenting mineral owners are not entitled to well data other than public information available from the North Dakota Industrial Commission. As of June 30, 2012, 16 of these wells had achieved 150% payout.

Set forth below is a summary of Horizontal Bakken activity through June 30, 2012 for wells in which we own a royalty or Net Profits Interest. This includes wells subject to the Minerals NPI.

	2004 through 2008	2009	2010	Q1 2011	Q2 2011	Q3 2011	Q4 2011	Q1 2012	Q2 2012	Total to Date
New Well Permits	61	23	59	13	20	17	17	17	8	235
Wells Spud	39	30	44	18	15	20	19	8	13	206
Wells Completed	31	31	37	9	10	15	15	18	1	167
Wells Reaching 150% Payout(1)	3	1	5	0	1	2	1	2	1	16

(1) Wells reaching 150% payout means wells for which the 150% penalty has been recovered during the indicated period.

Liquidity and Capital Resources

Capital Resources

Our primary sources of capital are our cash flow from the NPIs 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.

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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 vary widely and are not predictable as each effort requires specific engineering.  Such activities by the operating partnership could influence the amount we receive from the NPIs as reflected in the accrual-basis production costs $/mcfe in the table under “Results of Operations.”

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 are reflected in the NPI payments we receive from the operating partnership.

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 NPIs.  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 $15,350,000 at June 30, 2012 and $14,238,000 at December 31, 2011.

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. The full cost ceiling is evaluated at the end of each quarter and when events indicate possible impairment.

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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 or crude oil 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 the unweighted arithmetic average of the first day of the month price during the 12-month period ending on the balance sheet date 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 Royalty Properties and NPI 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.

ITEM 3.     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 possible losses.

Market Risk Related to Oil and Natural Gas Prices

Essentially all of our assets and sources of income are from Royalty Properties and NPIs, which generally entitle us to receive a share of the proceeds based on oil and natural gas production from those properties. Consequently, we are subject to market risk from fluctuations in oil and natural gas prices. Pricing for oil and natural gas production has been volatile and unpredictable for several years. We do not anticipate entering into financial hedging activities intended to reduce our exposure to oil and natural gas price fluctuations.

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. Therefore, we do not expect interest rate risk to be material to us. We do not anticipate engaging in transactions in foreign currencies that could expose us to foreign currency related market risk.

ITEM 4.    CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, our principal executive officer and principal financial officer carried out an evaluation of the effectiveness of our disclosure controls and procedures. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective.

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Changes in Internal Controls

There were no changes in our internal controls (as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934) during the quarter ended June 30, 2012 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II – OTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS

In January 2002, some individuals and an association called Rural Residents for Natural Gas Rights sued Dorchester Hugoton, Ltd., along with several other operators in Texas County, Oklahoma regarding the use of natural gas from the wells in residences. The operating partnership now owns and operates the properties formerly owned by Dorchester Hugoton. These properties contribute a significant portion of the NPI amounts paid to us. On April 9, 2007, plaintiffs, for immaterial costs, dismissed with prejudice all claims against the operating partnership regarding such residential gas use. On October 4, 2004, the plaintiffs filed severed claims against the operating partnership regarding royalty underpayments, which the Texas County District Court subsequently dismissed with a grant of time to replead. On January 27, 2006, one of the original plaintiffs again sued the operating partnership for underpayment of royalty, seeking class action certification. On October 1, 2007, the Texas County District Court granted the operating partnership’s motion for summary judgment finding no royalty underpayments. Subsequently, the District Court denied the plaintiff’s motion for reconsideration, and the plaintiff filed an appeal. On March 31, 2010, the appeal decision reversed and remanded to the Texas County District Court to resolve material issues of fact.  On June 30, 2011, the District Court issued a revised partial summary judgment in favor of the operating partnership.  On April 27, 2012, the parties successfully mediated terms for a settlement in the amount of $500,000 plus immaterial future royalty amounts on fuel gas; which, will be paid to the plaintiffs upon finalization of the agreed settlement and ultimate approval by the District Court.  A $500,000 reserve was recorded in Net Profits Revenues on the financial statements in the first quarter of 2012.

The Partnership and the operating partnership are involved in other legal and/or administrative proceedings arising in the ordinary course of their businesses, none of which have predictable outcomes and none of which are believed to have any significant effect on consolidated financial position, cash flows, or operating results.

ITEM 6.    EXHIBITS

See the attached Index to Exhibits.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

DORCHESTER MINERALS, L.P.
By:	Dorchester Minerals Management LP
	its General Partner
By:	Dorchester Minerals Management GP LLC
	its General Partner

	By:	/s/ William Casey McManemin
		William Casey McManemin
Date: August 8, 2012		Chief Executive Officer

	By:	/s/ H.C. Allen, Jr.
		H.C. Allen, Jr.
Date: August 8, 2012		Chief Financial Officer

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INDEX TO EXHIBITS

Number	Description
3.1	Certificate of Limited Partnership of Dorchester Minerals, L.P. (incorporated by reference to Exhibit 3.1 to Dorchester Minerals’ Registration Statement on Form S-4, Registration Number 333-88282)
3.2	Amended and Restated Agreement of Limited Partnership of Dorchester Minerals, L.P. (incorporated by reference to Exhibit 3.2 to Dorchester Minerals’ Report on Form 10-K filed for the year ended December 31, 2002)
3.3	Certificate of Limited Partnership of Dorchester Minerals Management LP (incorporated by reference to Exhibit 3.4 to Dorchester Minerals’ Registration Statement on Form S-4, Registration Number 333-88282)
3.4	Amended and Restated Limited Partnership Agreement of Dorchester Minerals Management LP (incorporated by reference to Exhibit 3.4 to Dorchester Minerals’ Report on Form 10-K for the year ended December 31, 2002)
3.5	Certificate of Formation of Dorchester Minerals Management GP LLC (incorporated by reference to Exhibit 3.7 to Dorchester Minerals’ Registration Statement on Form S-4, Registration Number 333-88282)
3.6	Amended and Restated Limited Liability Company Agreement of Dorchester Minerals Management GP LLC (incorporated by reference to Exhibit 3.6 to Dorchester Minerals’ Report on Form 10-K for the year ended December 31, 2002)
3.7	Certificate of Formation of Dorchester Minerals Operating GP LLC (incorporated by reference to Exhibit 3.10 to Dorchester Minerals’ Registration Statement on Form S-4, Registration Number 333-88282)
3.8	Limited Liability Company Agreement of Dorchester Minerals Operating GP LLC (incorporated by reference to Exhibit 3.11 to Dorchester Minerals’ Registration Statement on Form S-4, Registration Number 333-88282)
3.9	Certificate of Limited Partnership of Dorchester Minerals Operating LP (incorporated by reference to Exhibit 3.12 to Dorchester Minerals’ Registration Statement on Form S-4, Registration Number 333-88282)
3.10	Amended and Restated Agreement of Limited Partnership of Dorchester Minerals Operating LP (incorporated by reference to Exhibit 3.10 to Dorchester Minerals’ Report on Form 10-K for the year ended December 31, 2002)
31.1*	Certification of Chief Executive Officer of the Partnership pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934
31.2*	Certification of Chief Financial Officer of the Partnership pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934
32.1**	Certification of Chief Executive Officer of the Partnership pursuant to 18 U.S.C. Sec. 1350
32.2**	Certification of Chief Financial Officer of the Partnership pursuant to 18 U.S.C. Sec. 1350 (contained within Exhibit 32.1 hereto)
101.INS**	XBRL Instance Document
101.SCH**	XBRL Taxonomy Extension Schema Document
101.CAL**	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF**	XBRL Taxonomy Extension Definition Document
101.LAB**	XBRL Taxonomy Extension Label Linkbase Document
101.PRE**	XBRL Taxonomy Extension Presentation Linkbase Document

*  Filed herewith

**Furnished herewith