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

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

(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 ☒ No ☐

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 ☒ No ☐

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):

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

As of May 7, 2015, 30,675,431 common units representing limited partnership interests were outstanding.

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.

	March 31,			December 31,
	2015			2014
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	10,673		$	15,912
Trade and other receivables		3,430			4,761
Net profits interests receivable - related party		3,843			5,792
Prepaid expenses		58			19
Total current assets		18,004			26,484

Property and leasehold improvements - at cost:
Oil and natural gas properties (full cost method)		340,636			340,703
Accumulated full cost depletion		(272,143	)		(269,690	)
Total		68,493			71,013

Leasehold improvements		512			512
Accumulated amortization		(512	)		(500	)
Total		-			12

Total assets	$	86,497		$	97,509

LIABILITIES AND PARTNERSHIP CAPITAL

Current liabilities:
Accounts payable and other current liabilities	$	1,298		$	975
Current portion of deferred rent incentive		-			10
Total liabilities		1,298			985

Commitments and contingencies (Note 2)

Partnership capital:
General partner		2,390			2,692
Unitholders		82,809			93,832
Total partnership capital		85,199			96,524

Total liabilities and partnership capital	$	86,497		$	97,509

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

	Three Months Ended
	March 31,
	2015		2014
Operating revenues:
Royalties	$	8,281	$	14,663
Net profits interests		448		2,445
Lease bonus		47		216
Other		28		15

Total operating revenues		8,804		17,339

Costs and expenses:
Operating, including production taxes		1,034		1,439
Depreciation, depletion and amortization		2,465		2,517
General and administrative expenses		1,275		1,136

Total costs and expenses		4,774		5,092

Operating income		4,030		12,247

Other income, net		1		650

Net income	$	4,031	$	12,897

Allocation of net income:
General partner	$	153	$	455

Unitholders	$	3,878	$	12,442

Net income per common unit (basic and diluted)	$	0.13	$	0.41
Weighted average common units outstanding (000's)		30,675		30,675

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

	Three Months Ended
	March 31,
	2015			2014

Net cash provided by operating activities	$	10,050		$	16,290

Cash flows provided by investing activities:
Proceeds from sale of reserves		67			-

Cash flows used in financing activities:
Distributions paid to general partner and unitholders		(15,356	)		(14,934	)

(Decrease)/Increase in cash and cash equivalents		(5,239	)		1,356

Cash and cash equivalents at beginning of period		15,912			15,175

Cash and cash equivalents at end of period	$	10,673		$	16,531

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

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 income 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 income 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, 2014.

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.

Reclassification — Certain amounts in the 2014 condensed consolidated financial statements have been reclassified to conform to the 2015 presentation.

3 Distributions to Holders of Common Units: Unitholder cash distributions per common unit since 2013 have been:

	Per Unit Amount
	2015		2014		2013
First quarter	$	0.306553	$	0.496172	$	0.448209
Second quarter			$	0.490861	$	0.395583
Third quarter			$	0.447805	$	0.455287
Fourth quarter			$	0.485780	$	0.468560

Each of the foregoing distributions were paid on 30,675,431 units. The first quarter 2015 distribution was paid on May 7, 2015. 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 August 15, 2015.

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.

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.

Each of the five NPIs have previously had cumulative revenue that exceeded cumulative costs, such excess constituting net proceeds on which NPI payments were determined. In the event an NPI has a deficit of cumulative revenue versus cumulative costs, the deficit will be borne solely by the operating partnership.

Prior to the Minerals NPI (one of the five NPIs) 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 (“GAAP”). Effective third quarter 2011, our consolidated financial statements reflect activity attributable to the Minerals NPI, and include cash receipts and disbursements and accrued revenues and costs not yet received or paid by the NPI. Our financial statements will continue to reflect such information even if the NPI is in temporary deficit due to capital expenditures. Minerals NPI production volumes and prices are within the consolidated financial statements in accordance with GAAP, although net profits income in the first quarter of 2014 and 2015 from this NPI is zero because capital expenditures have exceeded net operating income.

The last payment attributable to the Minerals NPI was declared as of July 31, 2013, at which time cash on hand equaled outstanding capital commitments (resulting in a zero balance, i.e. neither a deficit nor surplus). Since that time, DMOLP has received production revenue, paid operating and capital expenses and made additional capital commitments, resulting in the temporary deficit described above. Set forth below is a summary calculation of this activity and the calculation of the Minerals NPI deficit as of March 31, 2015:

Our profitability is affected by oil and natural gas market prices. Oil and natural gas prices have fluctuated significantly 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 and economic conditions.

Three Months Ended March 31, 2015 as compared to Three Months Ended March 31, 2014

Normally, our period-to-period changes in net income 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:

Oil sales volumes attributable to our Royalty Properties during the first quarter increased 8.1% from 124 mbbls in 2014 to 134 mbbls in the same period of 2015. The increase in oil sales volumes are a result of robust activity in the Permian Basin and the Bakken Trend and release of suspended payments for prior periods. Natural gas sales volumes attributable to our Royalty Properties during the first quarter increased 13.2% from 823 mmcf in 2014 to 932 mmcf in the same period of 2015. The increase in natural gas sales volumes in the first quarter compared to the same period of 2014 is primarily due the release of suspended payments for prior periods, partially offset by natural reservoir declines.

Oil sales volumes attributable to our NPIs during the first quarter increased 114.6% from 48 mbbls in 2014 to 103 mbbls in the same period of 2015. The increase in oil sales volumes are a result of robust activity in the Bakken Trend. Natural gas sales volumes attributable to our NPIs decreased 11.5% from 843 mmcf in 2014 to 746 mmcf in the same period of 2015. The decrease was primarily due to natural reservoir declines in the Fayetteville Shale and the sale of Kansas working interests during the third quarter of 2014.

The weighted average oil sales prices attributable to our interest in Royalty Properties decreased 48.4% from $83.85/bbl during the first quarter of 2014 to $43.26/bbl during the same period of 2015. Weighted average natural gas sales prices from Royalty Properties decreased 48.3% from $5.15/mcf during the first quarter of 2014 to $2.66/mcf during the same period of 2015. Both oil and natural gas price changes resulted from changing market prices.

First quarter weighted average oil sales prices from the NPIs decreased 52.5% from $87.89/bbl in 2014 to $41.74/bbl during the same period of 2015. First quarter weighted average natural gas sales prices attributable to the NPIs decreased 53.9% from $5.70/mcf in 2014 to $2.63/mcf in the same period of 2015. Both oil and natural gas price changes resulted from changing market prices.

Our first quarter net operating revenues decreased 49.2% from $17,339,000 during 2014 to $8,804,000 during 2015. This decrease is primarily a result of lower prices as discussed above, partially offset by increased oil production.

Costs and expenses of $4,774,000 during the first quarter of 2015 were down 6.3% compared to $5,092,000 during the first quarter of 2014. First quarter 2015 production taxes were lower compared to the first quarter of 2014 due to reduced revenues.

General and administrative expenses of $1,275,000 during the first quarter of 2015 were up 12.2% compared to $1,136,000 during the same period of 2014, primarily due to costs associated with added compensation expense for new hires, and merit and retention bonuses for all employees.

Depletion and amortization costs of $2,465,000 during the first quarter of 2015 were down 2.1% compared to $2,517,000 during the same period of 2014. The minor reduction was due to the effects of upward reserve revisions at 2014 year-end offset by increased oil sales volumes during 2015.

Other income of $650,000 during the first quarter of 2014 was related to settlement of a dispute on leases in North Dakota.

First quarter net income allocable to common units decreased 68.8% from $12,442,000 during 2014 to $3,878,000 during 2015. Increased oil volumes were offset by decreased oil and natural gas sales prices.

Net cash provided by operating activities decreased 38.3% from $16,290,000 during the first quarter of 2014 to $10,050,000 during the first quarter of 2015. The decrease is due to lower oil and natural gas prices partially offset by increased 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.

Cash receipts attributable to our Royalty Properties during the 2015 first quarter totaled approximately $9,100,000. These receipts generally reflect oil sales during December 2014 through February 2015 and natural gas sales during November 2014 through January 2015. The weighted average indicated prices for oil and natural gas sales received during the 2015 first quarter attributable to the Royalty Properties were $49.18/bbl and $3.40/mcf, respectively.

Cash receipts attributable to our NPIs during the 2015 first quarter totaled approximately $2,500,000. These receipts generally reflect oil and natural gas sales from the properties underlying the NPIs during November 2014 through January 2015. The weighted average indicated prices for oil and natural gas sales received during the 2015 first quarter attributable to our NPIs were $57.10/bbl and $7.03/mcf, respectively. The natural gas weighted average indicated price for the quarter was increased by $3.60/mcf due to the receipt of a natural gas liquids payment of $1,800,000 for 2014 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 based on calendar year data. 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.

Horizontal Bakken, Williston Basin – We own varying undivided perpetual mineral interests in approximately 70,000/9,000 gross/net acres located in Burke, Divide, Dunn, McKenzie, Mountrail and Williams Counties, North Dakota. Permits for 669 wells had been issued on these lands as of March 31, 2015. In total, 601 wells were spud, of which 506 were completed as producers including wells for which we may not yet have received division orders or first payment. In some instances we elected to become a non-consenting mineral owner—who, according to North Dakota law, is not obligated to pay well costs, receives a royalty equal to the weighted average of all leases in the unit or 16% (at the operator’s option) from the date of first production, and backs-in for its full working interest after the operator has recovered 150% of drilling and completion costs from the net cash flow. The back-in working interest, if any, is owned by the operating partnership 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 March 31, 2015, 43 of these wells had achieved 150% payout.

We have and will continue to utilize a range of transaction structures for our unleased mineral interests including leasing to third parties, working interest participation through the operating partnership, electing non-consent under North Dakota law, or a combination thereof.

Our primary sources of capital are our cash flows 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 recent 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).

Depending upon gas prices, 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 Oklahoma. 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.

Cash and cash equivalents totaled $10,673,000 at March 31, 2015 and $15,912,000 at December 31, 2014.

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.

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 income. In addition to the impact on the 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.

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.

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 unpredictable for several years. We do not anticipate entering into financial hedging activities intended to reduce our exposure to oil and natural gas price fluctuations.

We 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.

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.

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 March 31, 2015 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

The Partnership and the operating partnership are involved in 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.

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.

Large accelerated filer ☒	Accelerated filer ☐	Non-accelerated filer ☐	Smaller reporting company ☐
		(Do not check if a smaller reporting company)

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS			1

PART I – FINANCIAL INFORMATION			1

	ITEM 1.	FINANCIAL STATEMENTS	1

		CONDENSED CONSOLIDATED BALANCE SHEETS AS OF MARCH 31, 2015 (UNAUDITED) AND DECEMBER 31, 2014	2

		CONDENSED CONSOLIDATED INCOME STATEMENTS FOR THE THREE MONTHS ENDED MARCH 31, 2015 AND 2014 (UNAUDITED)	3

		CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE THREE MONTHS ENDED MARCH 31, 2015 AND 2014 (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	11

	ITEM 4	CONTROLS AND PROCEDURES	11

PART II – OTHER INFORMATION			12

	ITEM 1.	LEGAL PROCEEDINGS	12

	ITEM 6.	EXHIBITS	12

SIGNATURES			13

INDEX TO EXHIBITS

CERTIFICATIONS

Reconciliation of Cash Activity and Capital Commitments for the Period from August 1, 2013 through March 31, 2015
Cash on hand @ 07/31/2013	$	5,000,000
Cumulative revenue during period		33,700,000
Cumulative expense during period		(8,300,000	)
Cumulative operating income during period		25,400,000
Cumulative CAPEX spent during period		(26,100,000	)
(Decrease) increase in cash		(700,000	)
Cash on hand @ 03/31/2015	$	4,300,000

Capital commitments @ 07/31/2013	$	(5,000,000	)
Change in commitments during period		(5,700,000	)
Capital commitments @ 03/31/2015		(10,700,000	)

Cumulative deficit @ 03/31/2015	$	(6,400,000	)

	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: May 7, 2015		Chief Executive Officer

	By:	/s/ H.C. Allen, Jr.
		H.C. Allen, Jr.
Date: May 7, 2015		Chief Financial Officer

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