dmlp20160630

[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 August 4, 2016, 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.

	June 30,			December 31,
	2016			2015

ASSETS
Current assets:
Cash and cash equivalents	$	9,522		$	7,136
Trade and other receivables		2,848			2,639
Net profits interests receivable - related party		1,882			3,005
Total current assets		14,252			12,780

Other non-current assets		47			19

Property and leasehold improvements - at cost:
Oil and natural gas properties (full cost method)		340,563			340,563
Accumulated full cost depletion		(284,174	)		(279,710	)
Total		56,389			60,853

Leasehold improvements		625			625
Accumulated amortization		(575	)		(548	)
Total		50			77

Total assets	$	70,738		$	73,729

LIABILITIES AND PARTNERSHIP CAPITAL

Current liabilities:
Accounts payable and other current liabilities	$	1,102		$	481
Current portion of deferred rent incentive		50			54
Total current liabilities		1,152			535
Deferred rent incentive less current portion		-			23
Total liabilities		1,152			558

Commitments and contingencies (Note 2)

Partnership capital:
General partner		1,852			1,996
Unitholders		67,734			71,175
Total partnership capital		69,586			73,171
Total liabilities and partnership capital	$	70,738		$	73,729

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2016		2015		2016		2015
Operating revenues:
Royalties	$	6,766	$	8,048	$	12,550	$	16,329
Net profits interests		1,708		217		1,731		665
Lease bonus		1,455		3		1,644		50
Other		80		14		210		43

Total operating revenues		10,009		8,282		16,135		17,087

Costs and expenses:
Operating, including production taxes		771		977		1,278		2,011
Depreciation, depletion and amortization		2,255		2,341		4,491		4,806
General and administrative expenses		1,032		1,148		2,917		2,423

Total costs and expenses		4,058		4,466		8,686		9,240

Net income	$	5,951	$	3,816	$	7,449	$	7,847

Allocation of net income:
General partner	$	201	$	149	$	261	$	302

Unitholders	$	5,750	$	3,667	$	7,188	$	7,545

Net income per common unit (basic and diluted)	$	0.19	$	0.12	$	0.24	$	0.25
Weighted average common units outstanding (000's)		30,675		30,675		30,675		30,675

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

	Six Months Ended
	June 30,
	2016			2015

Net cash provided by operating activities	$	13,420		$	16,073

Cash flows provided by investing activities:
Proceeds from sale of reserves		-			118

Cash flows used in financing activities:
Distributions paid to general partner and unitholders		(11,034	)		(25,075	)

Increase (decrease) in cash and cash equivalents		2,386			(8,884	)

Cash and cash equivalents at beginning of period		7,136			15,912

Cash and cash equivalents at end of period	$	9,522		$	7,028

The accompanying 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 condensed 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 statement 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, 2015.

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.

3 Distributions to Holders of Common Units: Unitholder cash distributions per common unit since 2014 have been:

	Per Unit Amount
	2016		2015		2014
First quarter	$	0.147417	$	0.306553	$	0.496172
Second quarter	$	0.257977	$	0.167430	$	0.490861
Third quarter			$	0.194234	$	0.447805
Fourth quarter			$	0.199076	$	0.485780

Each of the foregoing distributions were paid on 30,675,431 units. The second quarter 2016 distribution will be paid on August 11, 2016. Fourth quarter distributions shown above are paid in the first calendar quarter of the following year. Our partnership agreement requires the third quarter cash distribution to be paid by November 14, 2016.

4 New Accounting Pronouncements: In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (ASU 2014-09), which supersedes nearly all existing revenue recognition guidance under U.S. GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing U.S. GAAP.

The standard is effective for annual periods beginning after December 15, 2017, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). We are currently evaluating the impact of our pending adoption of ASU 2014-09 on our consolidated financial statements and have not yet determined the method by which we will adopt the standard in 2018.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. ASU 2016-02 is effective for public companies for annual periods beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. Companies must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. Lessees and lessors may not apply a full retrospective transition approach. The Partnership is currently evaluating ASU 2016-02 to determine the potential impact to its consolidated financial statements and related disclosures.

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 that costs, including budgeted capital expenditures, 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 initially achieving a cumulative payout status in the third quarter of 2011, the Minerals NPI’s activity 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 reflected within the consolidated financial statements in accordance with GAAP. Accrued net profits income in the second quarter and six month period of 2015 from this NPI are zero because accrued cumulative capital costs have exceeded accrued cumulative operating income. In 2016, the accrued net profits income from the Minerals NPI for the second quarter and six months ended is included in the financial statements.

Prior to the third quarter of 2015, 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 on a GAAP basis described above. The Minerals NPI achieved a surplus for June 2016 of $400,000 on a cash basis. The payment attributable to the surplus will be reflected in the third quarter distribution.

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 and Six Months Ended June 30, 2016 as compared to Three and Six Months Ended June 30, 2015

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:

Both oil and natural gas sales price changes reflected in the table above resulted from changing market conditions.

Oil sales volumes attributable to our Royalty Properties during the second quarter increased 18% from 124 mbbls in 2015 to 146 mbbls in the same period of 2016. Oil sales volumes attributable to the first six months of 2015 increased 12% from 258 mbbls to 288 mbbls in the same period of 2016. The increase in volumes during the second quarter and first six months of 2016 compared to the same periods of 2015 is mainly a result of increased Permian Basin production partially offset by natural reservoir declines. Natural gas sales volumes attributable to our Royalty Properties during the second quarter increased 5% from 792 mmcf in 2015 to 832 mmcf in 2016 mainly due to increased Permian Basin production. Natural gas sales volumes during the first six months decreased 2% from 1,724 mmcf in 2015 to 1,686 mmcf in 2016. The decrease in natural gas sales volumes for the first six months of 2016 compared to the same period of 2015 is primarily due to lower volumes from suspense release in the first quarter of 2016 compared to 2015.

Oil sales volumes attributable to our NPIs during the second quarter and first six months of 2015 were 70 mbbls and 173 mbbls, respectively, resulting in increases of 91% and 29% to 134 mbbls and 223 mbbls during the same periods of 2016. The increase in oil sales volumes are due to increased production in the Permian Basin in the second quarter and additional liquid volumes realized under the 2016 processing and purchase agreement on our Hugoton properties. Natural gas sales volumes attributable to our NPIs during the second quarter decreased 33% from 853 mmcf in 2015 to 569 mmcf in 2016 due to a decreased number of suspense releases in the second quarter of 2016 and the effect of the 2016 processing and purchase agreement for our Hugoton properties. During the first six months of 2016, NPI natural gas sales volumes decreased 13% from 1,599 mmcf in 2015 to 1,397 mmcf in 2016 due to natural declines.

Our second quarter net operating revenues increased 21% from $8,282,000 during 2015 to $10,009,000 during the same period of 2016. Current quarter decreases in oil and natural gas sales prices were more than offset by net profits interest and lease bonus income. Our first six months net operating revenues decreased 6% from $17,087,000 during 2015 to $16,135,000 during 2016. These changes are primarily a result of decreases in both oil and natural gas sales prices partially offset by an increase in lease bonus income in the first six months of 2016.

Second quarter and first six months operating costs and expenses decreased 21% and 36% from $977,000 and $2,011,000 during 2015 to $771,000 and $1,278,000 during 2016, respectively. The decreases are primarily a result of lower production taxes and lower ad valorem taxes due to lower oil and natural gas sales prices.

General and administrative expenses of $1,148,000 during the second quarter of 2015 decreased 10% to $1,032,000 during the same period of 2016. The decrease was mainly attributed to lower third party recruiting fees in 2016. General and administrative expenses of $2,423,000 during the first six months increased 20% compared to $2,917,000 during the same period of 2016. The expense increases are primarily due to outsourcing and enhancement of information technology services and higher legal costs associated with royalty litigation.

Depletion and amortization costs of $2,341,000 during the second quarter of 2015 decreased 4% to $2,255,000 during the same period of 2016. Depletion and amortization costs of $4,806,000 during the first six months of 2015 decreased 7% compared to $4,491,000 during the same period of 2016. We adjust our depletion each quarter for significant changes in our estimates of oil and natural gas reserves.

Second quarter net income allocable to common units increased 57% from $3,667,000 during 2015 to $5,750,000 during 2016 mainly due to higher net profits interest and lease bonus income partially offset by lower oil and natural gas sales prices. Our first six months net income allocable to common units decreased by 5% from $7,545,000 compared to $7,188,000 during the same period of 2016. The decrease is due to lower oil and natural gas sales prices, partially offset by higher net profits interest and lease bonus income and increased oil volumes.

Net cash provided by operating activities decreased 17% from $16,073,000 during the first six months of 2015 to $13,420,000 during the same period of 2016. The decrease is mainly due to lower oil and natural gas sales prices.

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

Cash receipts attributable to our Royalty Properties during the 2016 second quarter totaled approximately $5,800,000. These receipts generally reflect oil sales during March 2016 through May 2016 and natural gas sales during February 2016 through April 2016. The weighted average indicated prices for oil and natural gas sales received during the 2016 second quarter attributable to the Royalty Properties were $32.95/bbl and $1.63/mcf, respectively.

Cash receipts attributable to our NPIs during the 2016 second quarter totaled approximately $2,300,000. These receipts generally reflect oil and natural gas sales from the properties underlying the NPIs during February 2016 through April 2016. The weighted average indicated prices for oil and natural gas sales received during the 2016 second quarter attributable to our NPIs were $35.22/bbl and $1.97/mcf, respectively.

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 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).

The operating partnership plans to continuously assess the opportunity to increase production based on prevailing market conditions 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.

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 $9,522,000 at June 30, 2016 and $7,136,000 at December 31, 2015.

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. There was no impairment for the quarter and six months ended June 30, 2015 and 2016. 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 June 30, 2016 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 JUNE 30, 2016 AND DECEMBER 31, 2015 (UNAUDITED)	2

		CONDENSED CONSOLIDATED INCOME STATEMENTS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2016 AND 2015 (UNAUDITED)	3

		CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2016 AND 2015 (UNAUDITED)	4

		NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	5

	ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	7

	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	11

	ITEM 4.	CONTROLS AND PROCEDURES	12

PART II – OTHER INFORMATION			12

	ITEM 1.	LEGAL PROCEEDINGS	12

	ITEM 6.	EXHIBITS	12

SIGNATURES			13

INDEX TO EXHIBITS			14

CERTIFICATIONS			15

	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 4, 2016		Chief Executive Officer


	By:	/s/ Leslie Moriyama
		Leslie Moriyama
Date: August 4, 2016		Chief Financial Officer

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Accrual basis sales volumes:	2016		2015		2016		2015
Royalty properties gas sales (mmcf)		832		792		1,686		1,724

Royalty properties oil sales (mbbls)		146		124		288		258

NPI gas sales (mmcf)		569		853		1,397		1,599

NPI oil sales (mbbls)		134		70		223		173

Accrual basis weighted average sales price:

Royalty properties gas sales ($/mcf)	$	1.63	$	2.31	$	1.72	$	2.50

Royalty properties oil sales ($/bbl)	$	37.15	$	50.07	$	33.57	$	46.54

NPI gas sales ($/mcf)	$	1.76	$	2.56	$	1.96	$	2.59

NPI oil sales ($/bbl)	$	33.99	$	53.65	$	32.74	$	46.56

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