Document And Entity Information - USD ($)	12 Months Ended
Document And Entity Information - USD ($)	Dec. 31, 2017	Mar. 08, 2018	Jun. 30, 2017
Document Information [Line Items]
Entity Registrant Name	Dorchester Minerals, L.P.
Entity Central Index Key	0001172358
Trading Symbol	dmlp
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	No
Entity Common Stock, Shares Outstanding (in shares)		32,279,774
Entity Public Float			$ 421,073,423
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY
Amendment Flag	false

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 13,827	$ 8,212
Trade and other receivables	6,198	4,351
Net profits interests receivable—related party	5,330	2,225
Total current assets	25,355	14,788
Property and leasehold improvements—at cost:
Oil and natural gas properties (full cost method)	363,186	340,563
Accumulated full cost depletion	(297,442)	(288,163)
Total	65,744	52,400
Total assets	92,047	67,211
Current liabilities:
Accounts payable and other current liabilities	599	252
Current portion of deferred rent incentive	38	23
Total current liabilities	637	275
Deferred rent incentive less current portion	664
Total liabilities	1,301	275
Commitments and contingencies (Note 4)
Partnership capital:
General partner	1,782	1,809
Unitholders	88,964	65,127
Total partnership capital	90,746	66,936
Total liabilities and partnership capital	92,047	67,211
Leasehold Improvements [Member]
Property and leasehold improvements—at cost:
Leasehold improvements	1,573	625
Accumulated amortization	(625)	(602)
Total	$ 948	$ 23

Consolidated Income Statements - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating revenues:
Lease bonus	$ 2,399	$ 2,721	$ 53
Other	753	262	168
Total operating revenues	57,291	37,557	31,870
Costs and expenses
Production taxes	2,175	1,360	1,336
Operating expenses	2,460	1,733	2,244
Depreciation, depletion and amortization	9,302	8,507	10,068
General and administrative expenses	4,930	4,990	4,967
Total costs and expenses	18,867	16,590	18,615
Net income	38,424	20,967	13,255
Allocation of net income:
General partner	1,341	736	513
Unitholders	$ 37,083	$ 20,231	$ 12,742
Net income per common unit (basic and diluted) (in dollars per share)	$ 1.18	$ 0.66	$ 0.42
Weighted average basic and diluted common units outstanding (000's) (in shares)	31,488	30,675	30,675
Royalty Revenue [Member]
Operating revenues:
Revenues	$ 46,125	$ 29,750	$ 30,654
Net Profits Interests [Member]
Operating revenues:
Revenues	$ 8,014	$ 4,824	$ 995

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash flows from operating activities:
Net income	$ 38,424	$ 20,967	$ 13,255
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	9,302	8,507	10,068
Amortization of deferred rent incentive	(23)	(54)	(46)
Changes in operating assets and liabilities:
Trade and other receivables	(1,727)	(1,693)	2,122
Net profits interests receivable—related party	(3,105)	780	2,787
Accounts payable and other current liabilities	455	(252)	(571)
Deferred rent liabilities	702	23	77
Net cash provided by operating activities	44,028	28,278	27,692
Cash flows (used in) provided by investing activities:
Proceeds from sale of NPI reserves			140
Cash contributed in acquisition of royalty interests	440
Capital expenditures	(1,056)
Total cash flows (used in) provided by investing activities	(616)		140
Cash flows used in financing activities:
Distributions paid to general partner and unitholders	(37,797)	(27,202)	(36,608)
Increase (decrease) in cash and cash equivalents	5,615	1,076	(8,776)
Cash and cash equivalents at beginning of year	8,212	7,136	15,912
Cash and cash equivalents at end of year	13,827	8,212	7,136
Non-cash investing and financing activities:
Fair value of common units issued for acquisition of royalty interests	$ 23,183

Consolidated Statements of Changes in Partnership Capital - USD ($) $ in Thousands	General Partner [Member]	Limited Partner [Member]	Total
Balance at Dec. 31, 2014	$ 2,692	$ 93,832	$ 96,524
Balance (in shares) at Dec. 31, 2014		30,675,431
Net income	513	$ 12,742	13,255
Distributions	(1,209)	(35,399)	(36,608)
Balance at Dec. 31, 2015	1,996	$ 71,175	73,171
Balance (in shares) at Dec. 31, 2015		30,675,431
Net income	736	$ 20,231	20,967
Distributions	(923)	(26,279)	(27,202)
Balance at Dec. 31, 2016	1,809	$ 65,127	66,936
Balance (in shares) at Dec. 31, 2016		30,675,431
Net income	1,341	$ 37,083	38,424
Distributions	(1,368)	(36,429)	(37,797)
Acquisition of assets for units		$ 23,183	23,183
Acquisition of assets for units (in shares)		1,604,343
Balance at Dec. 31, 2017	$ 1,782	$ 88,964	$ 90,746
Balance (in shares) at Dec. 31, 2017		32,279,774,000

Note 1 - General and Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2017

Notes to Financial Statements

Basis of Presentation and Significant Accounting Policies [Text Block]

General and Summary of Significant Accounting Policies

Nature

Operations

— In these Notes, the term “Partnership,” as well as the terms “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. Our Partnership is a Dallas, Texas based owner of producing and nonproducing natural gas and crude oil royalty, net profits, and leasehold interests in

574

counties and

states. We are a publicly traded Delaware limited partnership that was formed in

December 2001,

and commenced operations on

January 31, 2003.

Basis

Presentation —

The consolidated financial statements herein have been prepared in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”).

Basi

c and Diluted Earnings Per Unit

—

Per-unit information is calculated by dividing the net income applicable to holders of our Partnership’s common units by the weighted average number of units outstanding. The Partnership has

potentially dilutive securities and, consequently, basic and dilutive net income per unit do

not

differ.

Principles of Consolidation

—

The consolidated financial statements include the accounts of Dorchester Minerals, L.P., 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.

Estimates

—

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 consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. For example, estimates of uncollected revenues and unpaid expenses from royalties and net profits interests in properties operated by non-affiliated entities are particularly subjective due to our inability to gain timely information. Therefore, actual results could differ from those estimates.

The discounted present value of our proved

oil and natural gas reserves is a major component of the ceiling test calculation and requires many subjective judgments. Estimates of reserves are forecasts based on engineering and geological analyses. Different reserve engineers could reach different conclusions as to estimated quantities of oil and natural gas reserves based on the same information. The passage of time provides more qualitative and quantitative information regarding reserve estimates, and revisions are made to prior estimates based on updated information. However, there can be

assurance that more 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. See the discussion under

Oil and Natural Gas Properties

General Partner

—

Our

general partner is Dorchester Minerals Management LP, referred to in these Notes as “our general partner.” Our general partner owns all of the partnership interests in Dorchester Minerals Operating LP, the operating partnership. See Note

—

Related Party Transactions. The general partner is allocated

and

of our Royalty Properties’ net revenues and Net Profits Interest (or “NPI”) net proceeds actually received by the operating partnership, respectively.

Cash and Cash Equivalents

—

Our

principal banking relationships are with major financial institutions. Cash balances in these accounts

may,

at times, exceed federally insured limits. We have

not

experienced any losses in such cash accounts and do

not

believe we are exposed to any significant risk on cash and cash equivalents. Short term investments with an original maturity of

three

months or less are considered to be cash equivalents and are carried at cost, which approximates fair value.

Concentration of Credit Risks

—

Our

Partnership, as a royalty and NPI owner, has

control over the volumes or method of sale of oil and natural gas produced and sold from the Royalty Properties and NPIs. It is believed that the loss of any single customer would

not

have a material adverse effect on the consolidated results of our operations.

Fair Value of Financial Instruments

—

The carrying amount of cash and cash equivalents, trade and other receivables and accounts 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 year-end or that will be realized in the future.

Receivables

—

Our

Partnership’s trade and other receivables and net profits interests receivable consist primarily of Royalty Properties payments receivable and NPI payments receivable, respectively. Most payments are received

two

four

months after production date.

allowance for doubtful accounts is deemed necessary based upon our lack of historical write offs and review of current receivables.

Oil and Natural Gas

Propert

ies

—

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 unit-of-production method. These capitalized costs are subject to a ceiling test, 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. Our Partnership did

not

assign any value to unproved properties, including nonproducing royalty, mineral and leasehold interests. The full cost ceiling is evaluated at the end of each quarter and when events indicate possible impairment. There have been

impairments for the years ended

December 31, 2017,

2016,

and

2015.

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

-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.

Our Partnership

’s properties are being depleted on the unit-of-production method using estimates of proved oil and natural gas reserves. Gains and losses are recognized upon the disposition of oil and natural gas properties involving a significant portion (greater than

25%

) of our Partnership’s reserves. Proceeds from other dispositions of oil and natural gas properties are credited to the full cost pool.

Leasehold Improvements

—

Leasehold improvements include

$702,000

received in

2017

as non-cash incentives in our office space lease and is offset in liabilities as deferred rent. Leasehold improvements are amortized over the shorter of their estimated useful lives or the related life of the lease. For leases with renewal periods at the Partnership’s option, we have used the original lease term, excluding renewal option periods to determine useful life. Deferred rent will be amortized to general and administrative expense over the same term as the leasehold improvements.

Asset Retirement Obligations

— Based on the nature of our property ownership, we have

material obligation to record.

Revenue

Recognition

— The

pricing of oil and natural gas sales from the Royalty Properties and NPIs is primarily determined by supply and demand in the marketplace and can fluctuate considerably. As a royalty owner, we have extremely limited involvement and operational control over the volumes and method of sale of oil and natural gas produced and sold from the Royalty Properties and non-operated NPIs.

Revenues from Royalty Properties and

non-operated NPIs are recorded under the cash receipts approach as directly received from the remitters’ statement accompanying the revenue check. Since the revenue checks are generally received

two

four

months after the production month, the Partnership accrues for revenue earned but

not

received by estimating production volumes and product prices.

Income Taxes

—

are treated as a partnership for income tax purposes and, as a result, our income or loss is includable in the tax returns of the individual unitholders. Depletion of oil and natural gas properties is an expense allowable to each individual partner, and the depletion expense as reported on the consolidated financial statements will

not

be indicative of the depletion expense an individual partner or unitholder

may

be able to deduct for income tax purposes.

Texas imposes a

franchise tax (commonly referred to as the Texas margin tax) at a rate of

0.75%

on gross revenues less certain deductions, as specifically set forth in the Texas margin tax statute. The Texas margin tax applies to corporations and limited liability companies, general and limited partnerships (unless otherwise exempt), limited liability partnerships, trusts (unless otherwise exempt), business trusts, business associations, professional associations, joint stock companies, holding companies, joint ventures and certain other business entities having limited liability protection.

Limited partnerships that receive at least

90%

of their gross income from designated passive sources, including royalties from mineral properties and other non-operated mineral interest income, and do

not

receive more than

10%

of their income from operating

an active trade or business, are generally exempt from the Texas margin tax as “passive entities.” We believe our Partnership meets the requirements for being considered a “passive entity” for Texas margin tax purposes and, therefore, it is exempt from the Texas margin tax. If the Partnership is exempt from Texas margin tax as a passive entity, each unitholder that is considered a taxable entity under the Texas margin tax would generally be required to include its portion of Partnership revenues in its own Texas margin tax computation. The Texas Administrative Code provides that such income is sourced according to the principal place of business of the Partnership, which would be the state of Texas.

Note 2 - Acquisition for Units

12 Months Ended

Dec. 31, 2017

Notes to Financial Statements

Acquisition of Producing and Nonproducing Royalty and Mineral Rights [Text Block]

Acquisition for Units

June 28, 2017,

the Partnership entered into a Contribution, Exchange and Purchase Agreement with DSD Royalty, LLC (the “

DSD Agreement”) pursuant to which the Partnership would acquire an undivided

50%

interest in certain mineral and royalty interests (the “Properties”) in exchange for cash (the “Cash Purchase Right”) and the remaining

50%

undivided interest in the Properties in exchange for the Partnership’s common units of limited partnership interests (the “Units”) for aggregate consideration of approximately

$23,183,000.

Immediately after execution of the DSD Agreement, the Partnership entered into a Participation Agreement with related parties of the Partnership, including

1307,

LTD., Mr. James E. Raley (a manager on the Board of Managers), Quiscalus Ventures, LLC, Ms. Leslie A. Moriyama (the Partnership’s Chief Financial Officer),

2011

Pete & Kay Allen Family Trust, Vaughn Petroleum (DMLP), LLC, Rokeby Investment L.P., Browning C. Vaughn and MARI GST Non-Exempt Trust, along with parties unrelated to the Partnership, collectively, (the “Participants”) pursuant to which the Partnership assigned the Cash Purchase Right to the Participants in exchange for the Participants’ assumption of the obligation to pay the cash consideration in connection with the consummation of the transactions contemplated by the DSD Agreement. Mr. William Casey McManemin, the Partnership’s Chairman and Chief Executive Officer and a manager on the Board of Managers, is the sole manager of Cabana Management, LLC, the sole general partner of

1307,

Ltd. Mr. Bradley J. Ehrman, the Partnership’s Chief Operating Officer, is the sole member of Quiscalus Ventures, LLC. Mr. H.C. Allen, Jr., a manager on the Board of Managers, is a trustee of the Pete & Kay Allen Family Trust. Mr. Robert C. Vaughn, a manager on the Board of Managers, and his spouse are the only unit holders of Vaughn Petroleum (DMLP), LLC. Mr. Vaughn’s son, Robert C. Vaughn, Jr., is the sole manager of Prevelly Investments, LLC, the general partner of Rokeby Investment, L.P. Browning C. Vaughn is Mr. Vaughn’s daughter. Ms. Martha Rochelle, a manager on the Board of Managers is a trustee of the MARI GST Non-Exempt Trust. On

June 28, 2017,

The Partnership entered into a Contribution and Exchange Agreement with the Participants (the “Participant Contribution Agreements”), pursuant to which each Participant acquired Units in exchange for the assets received by the Participant pursuant to the rights assigned to the Participant in the Participation Agreement. The quantity of Units issued to the Participants was equal to the quantity issued pursuant to the DSD Agreement. The Advisory Committee reviewed the transactions and found them to be fair and reasonable and approved the terms of the Participation Agreement and the Participant Contribution Agreements and the transactions contemplated thereby. The value of common units issued to each related party pursuant to the Participant Contribution Agreement with such related party is set forth opposite such related party's name below, which represents the approximate dollar value of such related person's interest in the transaction:

Name	Value of Common Units Issued
1307, Ltd.	$	2,259,000
MARI GST Non-Exempt Trust	$	961,000
Vaughn Petroleum (DMLP), LLC	$	769,000
James E. Raley	$	288,000
2011 Pete & Kay Allen Family Trust	$	288,000
Leslie A. Moriyama	$	96,000
Rokeby Investments, L.P.	$	96,000
Browning C. Vaughn	$	96,000
Quiscalus Ventures, LLC	$	48,000

In accordance with the transactions contemplated by the DSD Agreement and the Participant Contribution Agreements, the Partnership issued to DSD and the Participants an aggregate of

1,604,343

Common Units pursuant to the Partnership

’s registration statements on Form S-

After the issuance,

6,395,657

Common Units remain available under the Partnership’s registration statements on Form S-

Note 3 - Related Party Transactions

12 Months Ended

Dec. 31, 2017

Notes to Financial Statements

Related Party Transactions

Our general partner owns all of the partnership interests in the operating partnership. It is the employer of all personnel, owns the working interests and other properties underlying our

NPIs, and provides day-to-day operational and administrative services to us and the general partner. In accordance with our partnership agreement, we reimburse the general partner for certain allocable general and administrative costs, including rent, salaries, employee equity and benefit plans that are

not

direct expenses. These types of reimbursements are limited to

of distributions, plus certain costs previously paid. All such costs have been below the annual

limit amount, including the allowable surplus carryforward, for the years ended

December

31,

2017,

2016,

and

2015.

Additionally, certain reimbursable direct expenses such as professional and regulatory fees and ad valorem and severance taxes, as well as certain general and administrative costs that are related to regulatory matters, are

not

limited. Significant activity between the Partnership and the operating partnership consists of the following:

	In Thousands
From/To Operating Partnership	201 7		201 6			201 5
Net Profits Interest s Payments Receivable	$	5,330	$	2,225		$	3,005
Net Profits Interests Revenue	$	8,014	$	4,824		$	995
General & Administrative Amounts Payable/(Receivable)	$	9	$	(146	)	$	125
Total General & Administrative Expense	$	2,663	$	2,673		$	3,466

Note 4 - Commitments and Contingencies

12 Months Ended

Dec. 31, 2017

Notes to Financial Statements

Commitments and Contingencies Disclosure [Text Block]

Commitments and Contingencies

Our 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.

Operating Leases

We have entered into an operating lease agreement in the ordinary course of our business activities. The

third

amendment to our office lease was signed on

April 17, 2017,

for a term of

129

months beginning

June 1, 2018.

The lease is for our office space at

3838

Oak Lawn Avenue, Suite

300,

Dallas, Texas, and now expires in

2029.

Under the

third

amendment to the office lease, monthly rental payments will range from

$25,000

$30,000

and the Partnership will receive a tenant improvement allowance of

$702,000.

The Partnership recognizes a deferred rent liability for the rent escalations when the amount of straight-line rent exceeds the lease payments, and reduces the deferred rent liability when the lease payments exceed the straight-line rent expense. For the tenant improvement allowance, the Partnership will record a deferred rent liability and will amortize the deferred rent over the lease term as a reduction to rent expense once in use.

Rental expense related to the lease

, including operating expenses and consumption of electricity, was

$385,000,

$272,000,

and

$231,000

for the years ended

December 31, 2017,

2016

and

2015,

respectively. Minimum rental commitments under the terms of our office lease are as follows:

Years Ended December 31,	Minimum Payments
201 8	$	136,000
2019	$	252,000
2020	$	307,000
2021	$	313,000
2022	$	319,000
Thereafter	$	2,097,000
Total	$	3,424,000

Note 5 - Distribution to Holders of Common Units

12 Months Ended

Dec. 31, 2017

Notes to Financial Statements

Partners' Capital Notes Disclosure [Text Block]

Distribution To Holders Of Common Units

U nitholder cash distributions per common unit have been:	Per Unit Amount
	2017		2016		2015
First Quarter	$	0.306700	$	0.147417	$	0.306553

Second Quarter	$	0.322965	$	0.257977	$	0.167430

Third Quarter	$	0.284650	$	0.252224	$	0.194234

Fourth Quarter	$	0.386915	$	0.241475	$	0.199076

istributions were paid on

30,675,431

units from the

first

quarter of

2015

through the

first

quarter of

2017.

Beginning with the

second

quarter of

2017,

distributions were paid on

32,279,774

units. Fourth quarter distributions are paid in

February

of the following calendar year to unitholders of record in

January

February

of such following year. The partnership agreement requires the next cash distribution to be paid by

May 15, 2018.

Note 6 - New Accounting Pronouncements

12 Months Ended

Dec. 31, 2017

Notes to Financial Statements

Description of New Accounting Pronouncements Not yet Adopted [Text Block]

New Accounting Pronouncements

May 2014,

the

Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU)

No.

2014

09,

Revenue from Contracts with Customers (ASU

2014

), which supersedes nearly all existing revenue recognition guidance under U.S. GAAP.

The guidance requires entities to recognize revenue using the following

five

-step model: identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract, and recognize revenue as the entity satisfies each performance obligation. Adoption of this standard could result in retrospective application, either in the form of recasting all prior periods presented or a cumulative adjustment to equity in the period of adoption. The guidance is effective for annual and interim reporting periods beginning after

December 15, 2017.

January 1, 2018

we adopted using the full retrospective method. The Partnership completed its review of a representative sample of revenue contracts covering its material revenue streams and determined that there will be

impact to its consolidated financial statements, results of operations or liquidity. When comparing the Partnership

’s current revenue recognition to the new applied revenue recognition under Accounting Standards Codification (ASC)

606,

there will be

changes to the amount or timing of revenue being recognized. Therefore

quantitative adjustment will be required to be made to the prior periods presented on the financial statements after the

adoption of ASC

606.

Upon adoption the Partnership has

not

altered its existing information technology and internal controls outside of the contract review processes in order to identify impacts of future revenue contracts the Partnership

may

enter into. The Partnership does

not

anticipate the disclosure requirements under the Accounting Standards Update to have a material change on presentation of revenue streams as compared to our existing U.S. GAAP.

February 2016,

the FASB issued ASU

2016

02,

which requires lessees to record most leases on the balance sheet. Under the new guidance, lease classification as either a finance lease or an operating lease will determine how lease-related revenue and expense are recognized. The guidance is effective for fiscal years beginning after

December 15, 2018,

including interim periods within those fiscal years. The Partnership currently has lease commitments of approximately

million that we believe

may

be subject to capitalization under ASU

2016

02.

The lease obligations that will be in place upon adaption of ASU

2016

may

be significantly different than current obligations. We are still evaluating the impact of this on our consolidated financial statements.

Significant Accounting Policies (Policies)	12 Months Ended
Significant Accounting Policies (Policies)	Dec. 31, 2017
Accounting Policies [Abstract]
Basis of Accounting, Policy [Policy Text Block]	Basis of Presentation — The consolidated financial statements herein have been prepared in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”).
Earnings Per Share, Policy [Policy Text Block]	Basi c and Diluted Earnings Per Unit — Per-unit information is calculated by dividing the net income 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 net income per unit do not differ.
Consolidation, Policy [Policy Text Block]	Principles of Consolidation — The consolidated financial statements include the accounts of Dorchester Minerals, L.P., 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.
Use of Estimates, Policy [Policy Text Block]	Estimates — 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 consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. For example, estimates of uncollected revenues and unpaid expenses from royalties and net profits interests in properties operated by non-affiliated entities are particularly subjective due to our inability to gain timely information. Therefore, actual results could differ from those estimates. The discounted present value of our proved oil and natural gas reserves is a major component of the ceiling test calculation and requires many subjective judgments. Estimates of reserves are forecasts based on engineering and geological analyses. Different reserve engineers could reach different conclusions as to estimated quantities of oil and natural gas reserves based on the same information. The passage of time provides more qualitative and quantitative information regarding reserve estimates, and revisions are made to prior estimates based on updated information. However, there can be no assurance that more 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. See the discussion under Oil and Natural Gas Properties .
Incentive Distribution Policy, Managing Member or General Partner, Description [Policy Text Block]	General Partner — Our general partner is Dorchester Minerals Management LP, referred to in these Notes as “our general partner.” Our general partner owns all of the partnership interests in Dorchester Minerals Operating LP, the operating partnership. See Note 3 — Related Party Transactions. The general partner is allocated 4% and 1% of our Royalty Properties’ net revenues and Net Profits Interest (or “NPI”) net proceeds actually received by the operating partnership, respectively.
Cash and Cash Equivalents, Policy [Policy Text Block]	Cash and Cash Equivalents — Our principal banking relationships are with major financial institutions. Cash balances in these accounts may, at times, exceed federally insured limits. We have not experienced any losses in such cash accounts and do not believe we are exposed to any significant risk on cash and cash equivalents. Short term investments with an original maturity of three months or less are considered to be cash equivalents and are carried at cost, which approximates fair value.
Concentration Risk, Credit Risk, Policy [Policy Text Block]	Concentration of Credit Risks — Our Partnership, as a royalty and NPI owner, has no control over the volumes or method of sale of oil and natural gas produced and sold from the Royalty Properties and NPIs. It is believed that the loss of any single customer would not have a material adverse effect on the consolidated results of our operations.
Fair Value of Financial Instruments, Policy [Policy Text Block]	Fair Value of Financial Instruments — The carrying amount of cash and cash equivalents, trade and other receivables and accounts 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 year-end or that will be realized in the future.
Trade and Other Accounts Receivable, Policy [Policy Text Block]	Receivables — Our Partnership’s trade and other receivables and net profits interests receivable consist primarily of Royalty Properties payments receivable and NPI payments receivable, respectively. Most payments are received two to four months after production date. No allowance for doubtful accounts is deemed necessary based upon our lack of historical write offs and review of current receivables.
Full Cost or Successful Efforts, Policy [Policy Text Block]	Oil and Natural Gas Propert ies — 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 unit-of-production method. These capitalized costs are subject to a ceiling test, 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. Our Partnership did not assign any value to unproved properties, including nonproducing royalty, mineral and leasehold interests. The full cost ceiling is evaluated at the end of each quarter and when events indicate possible impairment. There have been no impairments for the years ended December 31, 2017, 2016, and 2015. 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. Our Partnership ’s properties are being depleted on the unit-of-production method using estimates of proved oil and natural gas reserves. Gains and losses are recognized upon the disposition of oil and natural gas properties involving a significant portion (greater than 25% ) of our Partnership’s reserves. Proceeds from other dispositions of oil and natural gas properties are credited to the full cost pool.
Property, Plant and Equipment, Policy [Policy Text Block]	Leasehold Improvements — Leasehold improvements include $702,000 received in 2017 as non-cash incentives in our office space lease and is offset in liabilities as deferred rent. Leasehold improvements are amortized over the shorter of their estimated useful lives or the related life of the lease. For leases with renewal periods at the Partnership’s option, we have used the original lease term, excluding renewal option periods to determine useful life. Deferred rent will be amortized to general and administrative expense over the same term as the leasehold improvements.
Asset Retirement Obligation [Policy Text Block]	Asset Retirement Obligations — Based on the nature of our property ownership, we have no material obligation to record.
Revenue Recognition, Policy [Policy Text Block]	Revenue Recognition — The pricing of oil and natural gas sales from the Royalty Properties and NPIs is primarily determined by supply and demand in the marketplace and can fluctuate considerably. As a royalty owner, we have extremely limited involvement and operational control over the volumes and method of sale of oil and natural gas produced and sold from the Royalty Properties and non-operated NPIs. Revenues from Royalty Properties and non-operated NPIs are recorded under the cash receipts approach as directly received from the remitters’ statement accompanying the revenue check. Since the revenue checks are generally received two to four months after the production month, the Partnership accrues for revenue earned but not received by estimating production volumes and product prices.
Income Tax, Policy [Policy Text Block]	Income Taxes — We are treated as a partnership for income tax purposes and, as a result, our income or loss is includable in the tax returns of the individual unitholders. Depletion of oil and natural gas properties is an expense allowable to each individual partner, and the depletion expense as reported on the consolidated financial statements will not be indicative of the depletion expense an individual partner or unitholder may be able to deduct for income tax purposes. Texas imposes a franchise tax (commonly referred to as the Texas margin tax) at a rate of 0.75% on gross revenues less certain deductions, as specifically set forth in the Texas margin tax statute. The Texas margin tax applies to corporations and limited liability companies, general and limited partnerships (unless otherwise exempt), limited liability partnerships, trusts (unless otherwise exempt), business trusts, business associations, professional associations, joint stock companies, holding companies, joint ventures and certain other business entities having limited liability protection. Limited partnerships that receive at least 90% of their gross income from designated passive sources, including royalties from mineral properties and other non-operated mineral interest income, and do not receive more than 10% of their income from operating an active trade or business, are generally exempt from the Texas margin tax as “passive entities.” We believe our Partnership meets the requirements for being considered a “passive entity” for Texas margin tax purposes and, therefore, it is exempt from the Texas margin tax. If the Partnership is exempt from Texas margin tax as a passive entity, each unitholder that is considered a taxable entity under the Texas margin tax would generally be required to include its portion of Partnership revenues in its own Texas margin tax computation. The Texas Administrative Code provides that such income is sourced according to the principal place of business of the Partnership, which would be the state of Texas.

Note 4 - Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2017

Notes Tables

Lessee, Operating Lease, Disclosure [Table Text Block]

Years Ended December 31,	Minimum Payments
201 8	$	136,000
2019	$	252,000
2020	$	307,000
2021	$	313,000
2022	$	319,000
Thereafter	$	2,097,000
Total	$	3,424,000

Note 1 - General and Summary of Significant Accounting Policies (Details Textual) shares in Thousands	12 Months Ended
	Dec. 31, 2017 USD ($) shares	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Number of Countries in which Entity Operates	574
Number of States in which Entity Operates	25
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount \| shares	0
Allowance for Doubtful Accounts Receivable, Current	$ 0	$ 0
Future Net Revenues To Proved Oil And Natural Gas Reserves Discount Percentage	10.00%
Impairment of Oil and Gas Properties	$ 0	$ 0	$ 0
Gain (Loss) Recognition Upon Disposition of Oil and Gas, Minimum Percent of Reserves	25.00%
Incentive from Lessor	$ 702,000
Texas Franchise Tax Rate	0.75%
Royalty Revenue [Member]
Revenue Allocated To General Partner Percentage	4.00%
Net Profits Interests [Member]
Revenue Allocated To General Partner Percentage	1.00%

Note 2 - Acquisition for Units (Details Textual) - Royalty and Mineral Interests [Member]	Jun. 30, 2017 USD ($) shares
Limited Partnership Common Units, Value \| $	$ 23,183,000
Limited Partners' Capital Account, Units Issued	1,604,343
Limited Partners' Capital Account, Units Authorized	6,395,657

Note 2 - Acquisition for Units - Related Parties' Interest in Units (Details) - Participant Contribution Agreement [Member]	Jun. 30, 2017 USD ($)
The 1307, LTD [Member]
Dollar Value of Interest	$ 2,259,000
MARI GST Non-Exempt Trust [Member]
Dollar Value of Interest	961,000
Vaughn Petroleum (DMLP), LLC [Member]
Dollar Value of Interest	769,000
James E. Raley [Member]
Dollar Value of Interest	288,000
The 2011 Pete & Kay Allen Family Trust [Member]
Dollar Value of Interest	288,000
Leslie A. Moriyama [Member]
Dollar Value of Interest	96,000
Rokeby Investments, L.P. [Member]
Dollar Value of Interest	96,000
Browning C. Vaughn [Member]
Dollar Value of Interest	96,000
Quiscalus Ventures, LLC [Member]
Dollar Value of Interest	$ 48,000

Note 3 - Related Party Transactions - Significant Activities Between Partnerships (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Total General & Administrative Expense	$ 2,663	$ 2,673	$ 3,466
Net Profits Interests Payments Receivableor Accrued [Member]
From/To Operating Partnership	5,330	2,225	3,005
Net Profits Interests Revenue [Member]
From/To Operating Partnership	8,014	4,824	995
General And Administrative Amounts Receivable Payable [Member]
From/To Operating Partnership	$ 9	$ (146)	$ 125

Note 4 - Commitments and Contingencies (Details Textual) - USD ($)		12 Months Ended
	Apr. 17, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Tenant Improvement Allowance	$ 702,000
Operating Leases, Rent Expense		$ 385,000	$ 272,000	$ 231,000
Office Lease [Member]
Lessee, Operating Lease, Term of Contract	10 years 270 days
Office Lease [Member] \| Minimum [Member]
Operating Leases, Future Monthly Payments	$ 25,000
Office Lease [Member] \| Maximum [Member]
Operating Leases, Future Monthly Payments	$ 30,000

Note 4 - Commitments and Contingencies - Minimum Rental Commitments of Operating Lease (Details)	Dec. 31, 2017 USD ($)
2018	$ 136,000
2019	252,000
2020	307,000
2021	313,000
2022	319,000
Thereafter	2,097,000
Total	$ 3,424,000

Note 5 - Distribution to Holders of Common Units (Details Textual) - shares	3 Months Ended	27 Months Ended
	Jun. 30, 2017	Mar. 31, 2017
Distribution Made to Limited Partner, Unit Distribution	32,279,774	30,675,431

Note 3 - Related Party Transactions (Details Textual)	12 Months Ended
Note 3 - Related Party Transactions (Details Textual)	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
General and Administrative Reimbursement, Maximum Percentage	5.00%	5.00%	5.00%

Note 5 - Distribution to Holders of Common Units - Unitholder Cash Distributions Per Common Unit (Details) - $ / shares	3 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015
Cash distribution per unit (in dollars per share)	$ 0.386915	$ 0.28465	$ 0.322965	$ 0.3067	$ 0.241475	$ 0.252224	$ 0.257977	$ 0.147417	$ 0.199076	$ 0.194234	$ 0.16743	$ 0.306553