Dorchester Minerals LP
Annual Report 2015

Plain-text annual report

DORCHESTER MINERALS, L.P. FORM 10-K (Annual Report) Filed 02/25/16 for the Period Ending 12/31/15 Address Telephone CIK 3838 OAK LAWN AVENUE SUITE 300 DALLAS, TX 75219-4541 2145590300 0001172358 Symbol DMLP SIC Code 1311 - Crude Petroleum and Natural Gas Industry Oil & Gas Operations Sector Fiscal Year Energy 12/31 http://www.edgar-online.com © Copyright 2016, EDGAR Online, Inc. All Rights Reserved. Distribution and use of this document restricted under EDGAR Online, Inc. Terms of Use. UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWASHINGTON, D.C. 20549FORM 10-K☒Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended December 31, 20 15o r☐Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition Period from ________to__________Commission File Number: 000-50175 DORCHESTER MINERALS, L.P.(Exact name of registrant as specified in its charter)Delaware(State or other jurisdiction ofincorporation or organization)81-0551518(I.R.S. Employer Identification No.) 3838 Oak Lawn Avenue, Suite 300 Dallas, Texas 75219(Address of principal executive offices) (Zip Code) (214) 559-0300(Registrant's telephone number, including area code) SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:Title of e ach c lassCommon Units Representing Limited Partnership InterestsName of each e xchange on which r egisteredNASDAQ Global Select Market SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:Title of ClassNone Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ☐ No ☒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 duringthe 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 thepast 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 tobe 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 theregistrant was required to submit and post such files). Yes ☒ No ☐Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and willnot be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K orany amendment to this Form 10-K. ☐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 thedefinitions of "large accelerated filer”, “accelerated filer” and “smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):Large accelerated filer ☒Accelerated filer ☐Non-accelerated filer ☐Smaller reporting company ☐ (Do not check if a smaller reporting company) Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act.): Yes ☐ No ☒The aggregate market value of the common units held by non-affiliates of the registrant (treating all managers, executive officers and 10% unitholders of theregistrant as if they may be affiliates of the registrant) was approximately $597,182,689 as of June 30, 2015, based on $21.39 per unit, the closing price of thecommon units as reported on the NASDAQ Global Select Market on such date.Number of Common Units outstanding as of February 25, 2016: 30,675,431DOCUMENTS INCORPORATED BY REFERENCEPortions of the definitive proxy statement for the registrant's 2016 Annual Meeting of Unitholders to be held on May 18, 2016, are incorporated by reference inPart III of this Form 10-K. Such definitive proxy statement will be filed with the Securities and Exchange Commission not later than 120 days subsequent toDecember 31, 2015.   TABLE OF CONTENTSPART I ITEM 1.BUSINESS1 ITEM 1A.RISK FACTORS4 ITEM 1BUNRESOLVED STAFF COMMENTS16 ITEM 2.PROPERTIES16 ITEM 3.LEGAL PROCEEDINGS20 ITEM 4.MINE SAFETY DISCLOSURES20 PART II ITEM 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OFEQUITY SECURITIES21 ITEM 6.SELECTED FINANCIAL DATA23 ITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS24 ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK29 ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA29 ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE29 ITEM 9A.CONTROLS AND PROCEDURES30 ITEM 9B.OTHER INFORMATION30 PART III ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE30 ITEM 11.EXECUTIVE COMPENSATION30 ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDERMATTERS30 ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE30 ITEM 14.PRINCIPAL ACCOUNTING FEES AND SERVICES30 PART IV ITEM 15.EXHIBITS, FINANCIAL STATEMENT SCHEDULES31 GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS32 SIGNATURES34 INDEX TO CONSOLIDATED FINANCIAL STATEMENTSF-1  PART I. ITEM 1. BUSINESS General Dorchester Minerals, L.P. is a publicly traded Delaware limited partnership that commenced operations on January 31, 2003, upon the combination ofDorchester Hugoton, Ltd., Republic Royalty Company, L.P. and Spinnaker Royalty Company, L.P. Dorchester Hugoton was a publicly traded Texas limitedpartnership, and Republic and Spinnaker were private Texas limited partnerships. Our common units are listed on the NASDAQ Global Select Market. AmericanStock Transfer & Trust Company is our registrar and transfer agent and its address and telephone number is 6201 15th Avenue, Brooklyn, NY 11219, (800) 937-5449. Our executive offices are located at 3838 Oak Lawn Avenue, Suite 300, Dallas, Texas, 75219-4541, and our telephone number is (214) 559-0300. We haveestablished a website at www.dmlp.net that contains the last annual meeting presentation and a link to the NASDAQ website. You may obtain all current filingsfree of charge at our website. We will provide electronic or paper copies of our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports onForm 8-K and amendments to those reports filed or furnished to the Securities and Exchange Commission (“SEC”) free of charge upon written request at ourexecutive offices. In this report, the term "Partnership," as well as the terms "us," "our," "we," and "its" are sometimes used as abbreviated references to DorchesterMinerals, L.P. itself or Dorchester Minerals, L.P. and its related entities. Our general partner is Dorchester Minerals Management LP, which is managed by its general partner, Dorchester Minerals Management GP LLC. As a result,the Board of Managers of Dorchester Minerals Management GP LLC exercises effective control of our Partnership. In this report, the term "general partner" is usedas an abbreviated reference to Dorchester Minerals Management LP. Our general partner also controls and owns, directly and indirectly, all of the partnershipinterests in Dorchester Minerals Operating LP and its general partner. Dorchester Minerals Operating LP owns working interests and other properties underlyingour Net Profits Interests (or “NPIs”), provides day-to-day operational and administrative services to us and our general partner, and is the employer of all theemployees who perform such services. In this report, the term "operating partnership" is used as an abbreviated reference to Dorchester Minerals Operating LP. Our general partner and the operating partnership are Delaware limited partnerships, and the general partners of their general partners are Delaware limitedliability companies. These entities and our Partnership were initially formed in December 2001 in connection with the combination. Our wholly owned subsidiary,Dorchester Minerals Oklahoma LP and its general partner are Oklahoma entities that acquired our wholly owned acquisition subsidiary and its general partner bymerger on December 31, 2009. On March 31, 2010, we formed a new subsidiary, and it acquired all of the outstanding partnership interests in Maecenas MineralsLLP, a Texas limited liability partnership. Our business may be described as the acquisition, ownership and administration of Royalty Properties and NPIs. The Royalty Properties consist of producingand nonproducing mineral, royalty, overriding royalty, net profits, and leasehold interests located in 574 counties and parishes in 25 states (“Royalty Properties”).The NPIs represent net profits overriding royalty interests in various properties owned by the operating partnership. Our partnership agreement requires that we distribute quarterly an amount equal to all funds that we receive from the Royalty Properties and the NPIs lesscertain expenses and reasonable reserves. Our partnership agreement allows us to grow by acquiring additional oil and natural gas properties, subject to the limitations described below. The approval ofthe holders of a majority of our outstanding common units is required for our general partner to cause us to acquire or obtain any oil and natural gas propertyinterest, unless the acquisition is complementary to our business and is made either: ●in exchange for our limited partner interests, including common units, not exceeding 20% of the common units outstanding after issuance; or ●in exchange for cash, if the aggregate cost of any acquisitions made for cash during the twelve-month period ending on the first to occur of the executionof a definitive agreement for the acquisition or its consummation is no more than 10% of our aggregate cash distributions for the four most recent fiscalquarters. Unless otherwise approved by the holders of a majority of our common units, in the event that we acquire properties for a combination of cash and limitedpartner interests, including common units, (i) the cash component of the acquisition consideration must be equal to or less than 5% of the aggregate cashdistributions made by our Partnership for the four most recent quarters and (ii) the amount of limited partnership interests, including common units, to be issued insuch acquisition, after giving effect to such issuance, shall not exceed 10% of the common units outstanding. 1 Credit Facilities and Financing Plans We do not have a credit facility in place, nor do we anticipate doing so. We do not anticipate incurring any debt, other than trade debt incurred in the ordinarycourse of our business. Our partnership agreement prohibits us from incurring indebtedness, other than trade payables, (i) in excess of $50,000 in the aggregate atany given time; or (ii) which would constitute "acquisition indebtedness" (as defined in Section 514 of the Internal Revenue Code of 1986, as amended), in order toavoid unrelated business taxable income for federal income tax purposes. We may finance any growth of our business through acquisitions of oil and natural gasproperties by issuing additional limited partnership interests or with cash, subject to the limits described above and in our partnership agreement. Under our partnership agreement, we may also finance our growth through the issuance of additional partnership securities, including options, rights, warrantsand appreciation rights with respect to partnership securities from time to time in exchange for the consideration and on the terms and conditions established by ourgeneral partner in its sole discretion. However, we may not issue limited partnership interests that would represent over 20% of the outstanding limited partnershipinterests immediately after giving effect to such issuance or that would have greater rights or powers than our common units without the approval of the holders ofa majority of our outstanding common units. Except in connection with qualifying acquisitions, we do not currently anticipate issuing additional partnershipsecurities. We have effective registration statements on Form S-4 registering an aggregate of 8,000,000 common units that may be offered and issued by thePartnership from time to time in connection with asset acquisitions or other business combination transactions. At present, all units remain available. Regulation Many aspects of the production, pricing and marketing of crude oil and natural gas are regulated by federal and state agencies. Legislation affecting the oil andnatural gas industry is under constant review for amendment or expansion, which frequently increases the regulatory burden on affected members of the industry. Exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes: ●permits for the drilling of wells; ●bonding requirements in order to drill or operate wells; ●the location and number of wells; ●the method of drilling and completing wells; ●the surface use and restoration of properties upon which wells are drilled; ●the plugging and abandonment of wells; ●numerous federal and state safety requirements; ●environmental requirements; ●property taxes and severance taxes; and ●specific state and federal income tax provisions. Oil and natural gas operations are also subject to various conservation laws and regulations. These regulations govern the size of drilling and spacing units orproration units and the density of wells that may be drilled and the unitization or pooling of oil and natural gas properties. In addition, state conservation lawsestablish a maximum allowable production from oil and natural gas wells. These state laws also generally prohibit the venting or flaring of natural gas and imposecertain requirements regarding the ratability of production. These regulations can limit the amount of oil and natural gas that the operators of our properties canproduce. The transportation of oil and natural gas after sale by operators of our properties is sometimes subject to regulation by state authorities. The interstatetransportation of oil and natural gas is subject to federal governmental regulation, including regulation of tariffs and various other matters, primarily by the FederalEnergy Regulatory Commission. Customers and Pricing The pricing of oil and natural gas sales is primarily determined by supply and demand in the marketplace and can fluctuate considerably. As a royalty ownerand non-operator, we have extremely limited access to timely information, involvement, and operational control over the volumes of oil and natural gas producedand sold and the terms and conditions on which such volumes are marketed and sold. 2 The operating partnership sells its Oklahoma Hugoton field natural gas production to DCP Midstream, LP; a gas processor and purchaser. Effective January 1,2016, the operating partnership commenced gas deliveries to DCP Midstream, LP under a new processing and purchase agreement with transportation costs lessfavorable than the prior agreement. The new agreement has an initial one year term and is automatically renewed annually unless cancelled by either party. Webelieve that the loss of DCP Midstream, LP or any single customer would not have a material adverse effect on us due to the availability of alternative purchasers inthe area. Competition The energy industry in which we compete is subject to intense competition among many companies, both larger and smaller than we are, many of which havefinancial and other resources greater than we have. Business Opportunities Agreement Pursuant to a business opportunities agreement among us, our general partner, the general partner of our general partner, the owners of the general partner ofour general partner (the “GP Parties”), we have agreed that, except with the consent of our general partner, which it may withhold in its sole discretion, we will notengage in any business not permitted by our partnership agreement, and we will have no interest or expectancy in any business opportunity that does not consistexclusively of the oil and natural gas business within a designated area that includes portions of Texas County, Oklahoma and Stevens County, Kansas . Allopportunities that are outside the designated area or are not oil and natural gas business activities are called renounced opportunities. The parties also have agreed that, as long as the activities of the general partner, the GP Parties and their affiliates or manager designees are conducted inaccordance with specified standards, or are renounced opportunities: ●our general partner, the GP Parties and their affiliates or the manager designees will not be prohibited from engaging in the oil and natural gas business orany other business, even if such activity is in direct or indirect competition with our business activities; ●affiliates of our general partner, the GP Parties and their affiliates and the manager designees will not have to offer us any business opportunity; ●we will have no interest or expectancy in any business opportunity pursued by affiliates of our general partner, the GP Parties or their affiliates and themanager designees; and ●we waive any claim that any business opportunity pursued by our general partner, the GP Parties or their affiliates and the manager designees constitutes acorporate opportunity that should have been presented to us. The standards specified in the business opportunities agreement generally provide that the GP Parties and their affiliates and manager designees must conducttheir business through the use of their own personnel and assets and not with the use of any personnel or assets of us, our general partner or operating partnership.A manager designee or personnel of a company in which any affiliate of our general partner or any GP Party or their affiliates has an interest or in which a managerdesignee is an owner, director, manager, partner or employee (except for our general partner and its general partner and their subsidiaries) is not allowed to usurp abusiness opportunity solely for his or her personal benefit, as opposed to pursuing, for the benefit of the separate party an opportunity in accordance with thespecified standards. In certain circumstances, if a GP Party or any subsidiary thereof, any officer of the general partner of our general partner or any of their subsidiaries, or amanager of the general partner of our general partner that is an affiliate of a GP Party signs a binding agreement to purchase oil and natural gas interests, excludingoil and natural gas working interests, then such party must notify us prior to the consummation of the transactions so that we may determine whether to pursue thepurchase of the oil and natural gas interests directly from the seller. If we do not pursue the purchase of the oil and natural gas interests or fail to respond to thepurchasing party's notice within the provided time, the opportunity will also be considered a renounced opportunity. In the event any GP Party or one of their subsidiaries acquires an oil and natural gas interest, including oil and natural gas working interests, in the designatedarea, it will offer to sell these interests to us within one month of completing the acquisition. This obligation also applies to any package of oil and natural gasinterests, including oil and natural gas working interests, if at least 20% of the net acreage of the package is within the designated area; however, this obligationdoes not apply to interests purchased in a transaction in which the procedures described above were applied and followed by the applicable affiliate. Operating Hazards and Uninsured Risks Our operations do not directly involve the operational risks and uncertainties associated with drilling for, and the production and transportation of, oil andnatural gas. However, we may be indirectly affected by the operational risks and uncertainties faced by the operators of our properties, including the operatingpartnership, whose operations may be materially curtailed, delayed or canceled as a result of numerous factors, including: ●the presence of unanticipated pressure or irregularities in formations; 3 ●accidents; ●title problems; ●weather conditions; ●compliance with governmental requirements; and ●shortages or delays in the delivery of equipment. Also, the ability of the operators of our properties to market oil and natural gas production depends on numerous factors, many of which are beyond theircontrol, including: ●capacity and availability of oil and natural gas systems and pipelines; ●effect of federal and state production and transportation regulations; ●changes in supply and demand for oil and natural gas; and ●creditworthiness of the purchasers of oil and natural gas. The occurrence of an operational risk or uncertainty that materially impacts the operations of the operators of our properties could have a material adverseeffect on the amount that we receive in connection with our interests in production from our properties, which could have a material adverse effect on our financialcondition or result of operations. In accordance with customary industry practices, we maintain insurance against some, but not all, of the risks to which our business exposes us. While webelieve that we are reasonably insured against these risks, the occurrence of an uninsured loss could have a material adverse effect on our financial condition orresults of operations. Employees As of February 25, 2016, the operating partnership had 24 full-time employees in our Dallas, Texas office and six full-time employees in field locations. ITEM 1A. RISK FACTORS Risks Related to Our Business Our cash distributions are highly dependent on oil and natural gas prices, which have historically been very volatile. Our quarterly cash distributions depend significantly on the prices realized from the sale of oil and, in particular, natural gas. Historically, the markets for oiland natural gas have been volatile and may continue to be volatile in the future. Various factors that are beyond our control will affect prices of oil and natural gas,such as: ●the worldwide and domestic supplies of oil and natural gas; ●the ability of the members of the Organization of Petroleum Exporting Countries and others to agree to and maintain oil prices and production controls; ●political instability or armed conflict in oil-producing regions; ●the price and level of foreign imports; ●the level of consumer demand; ●the price and availability of alternative fuels; ●the availability of pipeline capacity; ●weather conditions; ●domestic and foreign governmental regulations and taxes; and ●the overall economic environment. Lower oil and natural gas prices may reduce the amount of oil and natural gas that is economic to produce and may reduce our revenues and operating income.The volatility of oil and natural gas prices reduces the accuracy of estimates of future cash distributions to unitholders. 4 We do not control operations and development of the Royalty Properties or the properties underlying the N PIs that the operating partnership does not operate,which could impact the amount of our cash distributions. As the owner of a fractional undivided mineral or royalty interest, we do not control the development of the Royalty or NPI properties or the volumes of oiland natural gas produced from them, and our ability to influence development of nonproducing properties is severely limited. Also, since one of our stated businessobjectives is to avoid the generation of unrelated business taxable income, we are prohibited from participation in the development of our properties as a workinginterest or other expense-bearing owner. The decision to explore or develop these properties, including infill drilling, exploration of horizons deeper or shallowerthan the currently producing intervals, and application of enhanced recovery techniques will be made by the operator and other working interest owners of eachproperty (including our lessees) and may be influenced by factors beyond our control, including but not limited to oil and natural gas prices, interest rates,budgetary considerations and general industry and economic conditions. Our unitholders are not able to influence or control the operation or future development of the properties underlying the NPIs. The operating partnership isunable to influence significantly the operations or future development of properties that it does not operate. The operating partnership and the other currentoperators of the properties underlying the NPIs are under no obligation to continue operating the underlying properties. The operating partnership can sell any ofthe properties underlying the NPIs that it operates and relinquish the ability to control or influence operations. Any such sale or transfer must also simultaneouslyinclude the NPIs at a corresponding price. Our unitholders do not have the right to replace an operator. Our lease bonus revenue depends in significant part on the actions of third parties, which are outside of our control. Significant portions of the Royalty Properties are unleased mineral interests. With limited exceptions, we have the right to grant leases of these interests tothird parties. We anticipate receiving cash payments as bonus consideration for granting these leases in most instances. Our ability to influence third parties'decisions to become our lessees with respect to these nonproducing properties is severely limited, and those decisions may be influenced by factors beyond ourcontrol, including but not limited to oil and natural gas prices, interest rates, budgetary considerations and general industry and economic conditions. The operating partnership may transfer or abandon properties that are subject to the NPIs. Our general partner, through the operating partnership, may at any time transfer all or part of the properties underlying the NPIs. Our unitholders are notentitled to vote on any transfer; however, any such transfer must also simultaneously include the NPIs at a corresponding price. The operating partnership or any transferee may abandon any well or property if it reasonably believes that the well or property can no longer produce incommercially economic quantities. This could result in termination of the NPIs relating to the abandoned well. Cash distributions are affected by production and other costs, some of which are outside of our control. The cash available for distribution that comes from our royalty and mineral interests, including the NPIs, is directly affected by increases in production costsand other costs. Some of these costs are outside of our control, including costs of regulatory compliance and severance and other similar taxes. Other expendituresare dictated by business necessity, such as drilling additional wells in response to the drilling activity of others. Our oil and natural gas reserves and the underlying properties are depleting assets, and there are limitations on our ability to replace them. Our revenues and distributions depend in large part on the quantity of oil and natural gas produced from properties in which we hold an interest. Over time, allof our producing oil and natural gas properties will experience declines in production due to depletion of their oil and natural gas reservoirs, with the rates ofdecline varying by property. Replacement of reserves to maintain production levels requires maintenance, development or exploration projects on existingproperties, or the acquisition of additional properties. The timing and size of maintenance, development or exploration projects will depend on the market prices of oil and natural gas and on other factors beyondour control. Many of the decisions regarding implementation of such projects, including drilling or exploration on any unleased and undeveloped acreage, will bemade by third parties. In addition, development possibilities by the operating partnership in the Hugoton field are limited by the developed nature of that field andby regulatory restrictions. Our ability to increase reserves through future acquisitions is limited by restrictions on our use of cash and limited partnership interests for acquisitions and byour general partner's obligation to use all reasonable efforts such as NPIs to avoid unrelated business taxable income. In addition, the ability of affiliates of ourgeneral partner to pursue business opportunities for their own accounts without tendering them to us in certain circumstances may reduce the acquisitions presentedto us for consideration. 5 Drilling activities on our properties may not be productive, which could have an adverse effect on future results of operations and financial condition. The operating partnership may undertake drilling activities in limited circumstances on the properties underlying the NPIs, and third parties may undertakedrilling activities on our other properties. Any increases in our reserves will come from such drilling activities or from acquisitions. Drilling involves a wide variety of risks, including the risk that no commercially productive oil or natural gas reservoirs will be encountered. The cost ofdrilling, completing and operating wells is often uncertain, and drilling operations may be delayed or canceled as a result of a variety of factors, including: ●pressure or irregularities in formations; ●equipment failures or accidents; ●unexpected drilling conditions; ●shortages or delays in the delivery of equipment; ●adverse weather conditions; and ●disputes with drill-site owners. Future drilling activities on our properties may not be successful. If these activities are unsuccessful, this failure could have an adverse effect on our futureresults of operations and financial condition. In addition, under the terms of the NPIs, the costs of unsuccessful future drilling on the working interest propertiesthat are subject to the NPIs will reduce amounts payable to us under the NPIs by 96.97% of these costs. Our ability to identify and capitalize on acquisitions is limited by contractual provisions and substantial competition. Our partnership agreement limits our ability to acquire oil and natural gas properties in the future, especially for consideration other than our limitedpartnership interests. Because of the limitations on our use of cash for acquisitions and on our ability to accumulate cash for acquisition purposes, we may berequired to attempt to effect acquisitions with our limited partnership interests. However, sellers of properties we would like to acquire may be unwilling to take ourlimited partnership interests in exchange for properties. Our partnership agreement obligates our general partner to use all reasonable efforts to avoid generating unrelated business taxable income. Accordingly, toacquire working interests we would have to arrange for them to be converted into overriding royalty interests, net profits interests, or another type of interest thatdoes not generate unrelated business taxable income. Third parties may be less likely to deal with us than with a purchaser to which such a condition would notapply. These restrictions could prevent us from pursuing or completing business opportunities that might benefit us and our unitholders, particularly unitholderswho are not tax-exempt investors. The duty of affiliates of our general partner to present acquisition opportunities to our Partnership is limited, pursuant to the terms of the business opportunitiesagreement. Accordingly, business opportunities that could potentially be pursued by us might not necessarily come to our attention, which could limit our ability topursue a business strategy of acquiring oil and natural gas properties. We compete with other companies and producers for acquisitions of oil and natural gas interests. Many of these competitors have substantially greaterfinancial and other resources than we do. Any future acquisitions will involve risks that could adversely affect our business, which our unitholders generally will not have the opportunity to evaluate. Our current strategy contemplates that we may grow through acquisitions and development of our undeveloped property. We expect to participate indiscussions relating to potential acquisition and investment opportunities. If we consummate any additional acquisitions and investments, our capitalization andresults of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant informationthat we will consider in connection with the acquisition, unless the terms of the acquisition require approval of our unitholders. Additionally, our unitholders willbear 100% of the dilution from issuing new common units while receiving essentially 96% of the benefit as 4% of the benefit goes to our general partner. Acquisitions and business expansions involve numerous risks, including assimilation difficulties, unfamiliarity with new assets or new geographic areas andthe diversion of management's attention from other business concerns. In addition, the success of any acquisition will depend on a number of factors, including theability to estimate accurately the recoverable volumes of reserves, rates of future production and future net revenues attributable to reserves and to assess possibleenvironmental liabilities. Our review and analysis of properties prior to any acquisition will be subject to uncertainties and, consistent with industry practice, maybe limited in scope. We may not be able to successfully integrate any oil and natural gas properties that we acquire into our operations, or we may not achievedesired profitability objectives. 6 A natural disaster or catastrophe could damage pipelines, gathering systems and other facilities that service our properties, which could substantially limit ouroperations and adversely affect our cash flow. If gathering systems, pipelines or other facilities that serve our properties are damaged by any natural disaster, accident, catastrophe or other event, our incomecould be significantly interrupted. Any event that interrupts the production, gathering or transportation of our oil and natural gas, or which causes us to share insignificant expenditures not covered by insurance, could adversely impact the market price of our limited partnership units and the amount of cash available fordistribution to our unitholders. We do not carry business interruption insurance. A significant portion of the properties subject to the NPIs are geographically concentrated, which could cause net proceeds payable under the NPIs to beimpacted by regional events. A significant portion of the properties subject to the NPIs are natural gas properties located in the Hugoton field in Oklahoma. Because of this geographicconcentration, any regional events, including natural disasters that increase costs, reduce availability of equipment or supplies, reduce demand or limit productionmay impact the net proceeds payable under the NPIs more than if the properties were more geographically diversified. The number of prospective natural gas purchasers and methods of delivery are considerably less than would otherwise exist from a more geographicallydiverse group of properties. As a result, natural gas sales after gathering and compression tend to be sold to one buyer, thereby increasing credit risk. Under the terms of the NPIs, much of the economic risk of the underlying properties is passed along to us. Under the terms of the NPIs, virtually all costs that may be incurred in connection with the properties, including overhead costs that are not subject to anannual reimbursement limit, are deducted as production costs or excess production costs in determining amounts payable to us. Therefore, to the extent of therevenues from the burdened properties, we bear 96.97% of the costs of the working interest properties. If costs exceed revenues, we do not receive any paymentsunder the NPIs. However, except as described below, we are not required to pay any excess costs. The terms of the NPIs provide for excess costs that cannot be charged currently because they exceed current revenues to be accumulated and charged in futureperiods, which could result in us not receiving any payments under the NPIs until all prior uncharged costs have been recovered by the operating partnership. Damages associated with the production and gathering of our oil and natural gas properties could affect our cash flow. The operating partnership owns and operates gathering systems and compression facilities. Casualty losses or damages from these operations would beproduction costs under the terms of the NPIs and could adversely affect our cash flow. We may indirectly experience costs from repair or replacement of aging equipment. Some of the operating partnership's current working interest wells were drilled and have been producing since prior to 1954. The 132-mile Oklahoma gaspipeline gathering system was originally installed in or about 1948 and because of its age is in need of periodic repairs and upgrades. Should major components ofthis system require significant repairs or replacement, the operating partnership may incur substantial capital expenditures in the operation of the Oklahomaproperties, which, as production costs, would reduce our cash flow from these properties. Our cash flow is subject to operating hazards and unforeseen interruptions for which we may not be fully insured. Neither we nor the operating partnership are fully insured against certain risks, either because such insurance is not available or because of high premiumcosts. Operations that affect the properties are subject to all of the risks normally incident to the oil and natural gas business, including blowouts, cratering,explosions and pollution and other environmental damage, any of which could result in substantial decreases in the cash flow from our royalty interests and otherinterests due to injury or loss of life, damage to or destruction of wells, production facilities or other property, clean-up responsibilities, regulatory investigationsand penalties and suspension of operations. Any uninsured costs relating to the properties underlying the NPIs will be deducted as a production cost in calculatingthe net proceeds payable to us. Governmental policies, laws and regulations could have an adverse impact on our business and cash distributions. Our business and the properties in which we hold interests are subject to federal, state and local laws and regulations relating to the oil and natural gas industryas well as regulations relating to safety matters. These laws and regulations can have a significant impact on production and costs of production. For example, inOklahoma, where properties that are subject to the NPIs are located, regulators have the ability, directly or indirectly, to limit production from those properties, andsuch limitations or changes in those limitations could negatively impact us in the future. 7 As another example, Oklahoma regulations currently require administrative hearings to change the concentration of the operating partnership’s gas productionwells from one well for each 640 acres in the Guymon-Hugoton field. Previously, certain interested parties have sought regulatory changes in Oklahoma for"infill," or increased density drilling similar to that which is available in Kansas, which allows one well for each 320 acres. Should Oklahoma change its existingregulations to readily permit infill drilling, it is possible that a number of producers will commence increased density drilling in areas adjacent to the properties inOklahoma that are subject to the NPIs. If the operating partnership or other operators of our properties do not do the same, our production levels relating to theseproperties may decrease, or mineral owners may demand increased density drilling. Capital expenditures relating to increased density on the properties underlyingthe NPIs would be deducted from amounts payable to us under the NPIs. Environmental costs and liabilities and changing environmental regulation could affect our cash flow. As with other companies engaged in the ownership and production of oil and natural gas, we always have possible risk of exposure to environmental costs andliabilities because the costs associated with environmental compliance or remediation could reduce the amount we would receive from our properties. Theproperties in which we hold interests are subject to extensive federal, state, tribal and local regulatory requirements relating to environmental affairs, health andsafety and waste management. Governmental authorities have the power to enforce compliance with applicable regulations and permits, which could increaseproduction costs on our properties and affect their cash flow. Third parties may also have the right to pursue legal actions to enforce compliance. Because we do notdirectly operate our properties, our direct liability under environmental laws is limited. It is likely, however, that expenditures in connection with environmentalmatters, individually or as part of normal capital expenditure programs, will affect the net cash flow from our properties. Future environmental law developments,such as stricter laws, regulations or enforcement policies, could significantly increase the costs of production from our properties and reduce our cash flow. The following is a summary of some of the existing environmental laws, rules and regulations that apply to oil and gas operations, and that may indirectlyaffect our cash flow. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”). CERCLA, also known as the Superfund law, and comparablestate statutes impose strict liability, and under certain circumstances, joint and several liability, on classes of persons who are considered to be responsible for therelease of a hazardous substance into the environment. The term “hazardous substance” is specifically defined to exclude petroleum, including crude oil and anyfraction thereof, natural gas and natural gas liquids. Despite this exclusion, certain hazardous substances are commonly used in connection with oil and gasoperations. Responsible persons include the owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of ahazardous substance released at the site. Under CERCLA, such persons may be subject to strict, joint and several liabilities for the costs of investigating releases ofhazardous substances, cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs ofcertain health studies. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damageallegedly caused by the hazardous substances released into the environment. The operators of our properties may be responsible under CERCLA for all or part ofthe costs to clean up sites at which hazardous substances have been disposed. Although we are not an operator, our ownership of royalty interests could cause us tobe responsible for all or part of such costs to the extent that CERCLA imposes such responsibilities on such parties as “owners.” The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal andcleanup of hazardous and non-hazardous wastes. Drilling fluids, produced water and most of the other wastes associated with the exploration, development andproduction of oil or gas are currently excluded from regulation under RCRA’s hazardous waste provisions. However, it is possible that certain oil and gasexploration and production wastes could be classified as hazardous wastes in the future. In addition, exploration and production wastes are regulated under statelaws analogous to RCRA. Many of our properties have produced oil and/or gas for many years. We have no knowledge of current and prior operators’ procedureswith respect to the disposal of oil and gas wastes. Hydrocarbons or other solid or hazardous wastes may have been released on or under our properties by theoperators or prior operators. Our properties and the materials disposed or released on, at, under or from them may be subject to CERCLA, RCRA and analogousstate laws, and removal or remediation of such materials could be required by a governmental authority. The Federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and otherrequirements. Existing laws and regulations and possible future laws and regulations may require our operators to obtain pre-approval for the expansion ormodification of existing facilities or the construction of new facilities expected to produce air emissions and may impose stringent air permit requirements or usespecific equipment or technologies to control emissions. The EPA continues to develop stringent regulations governing emissions of toxic air pollutants from oiland gas facilities. Specifically, on April 18, 2012, the EPA issued new final regulations under the New Source Performance Standards (“NSPS”) and NationalEmission Standards for Hazardous Air Pollutants (“NESHAPs”). The new regulations are designed to reduce volatile organic compound (“VOC”) emissions fromhydraulically fractured wells and other equipment. Under the regulations, since January 1, 2015 owners and operators of hydraulically fractured natural gas wells(wells drilled principally for the production of natural gas) have been required to use so-called “green completion” technology to recover natural gas that formerlywould have been flared or vented. Obtaining permits and complying with these new requirements has the potential to increase costs of production and delay thedevelopment of our properties. 8 The Federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws impose restrictions and strict controls on the discharge ofpollutants and fill material, including spills and leaks of oil and other substances into regulated waters, including wetlands. The discharge of pollutants intoregulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA, an analogous state agency, or, in the case of fill material, theUnited States Army Corps of Engineers. Compliance with the Clean Water Act may restrict the location of certain facilities, require the mitigation of impactedwetlands, increase the cost of capital expenditures, and may result in permitting delays. The potential adoption of federal and state hydraulic fracturing legislation or executive orders could delay or restrict development of our oil and natural gasproperties . The Energy Policy Act of 2005 exempts hydraulic fracturing from federal regulation under the Safe Drinking Water Act (SDWA), provided that diesel fuel isnot used in the fracturing process. In prior Congressional Sessions, legislation has been introduced that would have repealed this exemption. If similar legislationwere enacted, it could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications,fulfill monitoring, reporting and recordkeeping obligations and meet plugging and abandonment requirements. Such federal legislation could lead to operationaldelays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing. In 2010, the EPA asserted federal regulatory authority over hydraulic fracturing involving diesel additives through an informal policy statement posted on theagency’s website. Industry groups filed a lawsuit challenging the EPA’s decision. In February 2012, the EPA and industry reached a settlement under which theEPA agreed to issue hydraulic fracturing permitting guidance through the notice and comment process. The EPA published a draft guidance document in May2012, and accepted comments through August 2012. In February 2014, the EPA published final guidance that broadly defined diesel fuel and which requires theissuance of a Class II Underground Injection Control permit for hydraulic fracturing treatments using diesel fuel. These requirements may cause additional costsand delays in the hydraulic fracturing process using diesel fuel. The EPA has also asserted in certain cases involving alleged groundwater contamination that it has emergency authority under the SDWA to issueadministrative compliance orders to require clean-up of groundwater. Although the United States Supreme Court has held that such orders are subject to pre-enforcement judicial review, the EPA maintains that it has the authority to continue to issue such orders. The EPA’s Office of Research and Development (ORD) has conducted a scientific study to investigate the possible relationships between hydraulic fracturingand drinking water. The ORD published draft results in 2015, concluding that hydraulic fracturing operations do impact drinking water resources but declining toreach conclusions about the frequency or severity of those impacts. In addition to the EPA study, there are other governmental reviews that focus on environmentalaspects of hydraulic fracturing. In April 2012, President Obama issued an executive order establishing an interagency working group to coordinate Federal policiesrelated to unconventional gas development. In addition, a committee of the United States House of Representatives has conducted an investigation of hydraulicfracturing. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulicfracturing. For example, in 2011 the U.S. Department of Energy conducted an investigation to identify best practices for hydraulic fracturing. These investigations,initiatives, and studies could result in additional efforts to regulate hydraulic fracturing. Beyond studying hydraulic fracturing, certain members of Congress have called upon the Government Accountability Office to investigate how hydraulicfracturing might adversely affect water resources and asked the Securities and Exchange Commission to investigate the natural gas industry and any possiblemisleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing. Any newfederal restrictions on hydraulic fracturing resulting from these efforts could result in delays, additional permitting and financial assurance requirements, and morestringent construction requirements, thereby significantly increasing operating, capital and compliance costs. Such cost increases could delay or restrictdevelopment by operators of our oil and natural gas properties. Additionally, certain states in which our properties are located, including Texas and Wyoming, have adopted, and other states are considering adopting,regulations that could impose more stringent permitting, public disclosure and well construction requirements on hydraulic-fracturing operations or otherwise seekto ban fracturing activities altogether. For example, pursuant to legislation adopted by the State of Texas in June 2011, the Railroad Commission of Texas enacted arule in December 2011, requiring public disclosure of certain information regarding additives, chemical ingredients, concentrations and water volumes used inhydraulic fracturing. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit well drilling in general and/or hydraulicfracturing in particular. In response to a 2014 ballot initiative by the voters of the City of Denton, Texas banning hydraulic fracturing, the Texas legislature enacteda statute preempting local government regulation of oil and gas activities, including hydraulic fracturing. In other states, however, local governments may retain theability to directly or indirectly regulate hydraulic fracturing. State and local governments may also seek to regulate or recover costs of activities tangentiallyassociated with hydraulic fracturing, such as increased truck traffic. In the event state, local, or municipal legal restrictions are adopted in areas where ourproperties are located, the cost of the operators of our oil and natural gas properties complying with such requirements may be significant in nature, which maycause delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even preclude the operators from drilling wells. 9 The adoption of climate change legislation by Congress or executive orders or regulations could result in increased operating costs and reduced demand for theoil and natural gas production from our properties. Congress has, from time to time, considered legislation to reduce greenhouse gas (GHG) emissions. To date, Congress has not passed a bill specificallyaddressing GHG regulation. Almost half of the states, however, have developed GHG emission inventories and/or regional GHG cap and trade programs. Thesecap and trade programs require major sources of emissions or major fuel producers to acquire and surrender emission allowances corresponding with their annualemissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. Many statesalso have enacted renewable portfolio standards, which require utilities to purchase a certain percentage of their energy from renewable fuel sources. In December 2009, the EPA determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and theenvironment by contributing to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA required the agency to adopt regulationsto restrict GHG emissions under the Federal Clean Air Act. In 2010, the EPA issued a final rule “tailoring” its New Source Review permitting and FederalOperating Permit programs to apply to facilities with certain thresholds of GHG emissions. This “Tailoring Rule” was challenged in court, and on June 23, 2014,the United States Supreme Court struck down the Tailoring Rule in Utility Air Regulatory Group v. Environmental Protection Agency . In its decision, the Courtheld that the EPA may not impose permitting requirements on facilities based solely on their emissions of GHGs. But, the Court also held that the EPA mayregulate GHG emissions if a facility is otherwise subject to permitting based on the emissions of conventional, non-GHG pollutants. Thus, any new facilities ormajor modifications to existing facilities that exceed the federal New Source Review emission thresholds for conventional pollutants may be required to use “bestavailable control technology” and energy efficiency measures to minimize GHG emissions. In December 2010, the EPA enacted final regulations on mandatoryreporting of GHGs. Those regulations required owners or operators of facilities that contain petroleum and natural gas systems and emit 25,000 metric tons or moreof GHGs per year (expressed as carbon dioxide equivalent or CO2E) to annually report carbon dioxide, methane and nitrous oxide emissions, beginning inSeptember 2012. The EPA has indicated that it will use data collected through the reporting rules to decide whether to promulgate future GHG emission limits. Although it is not possible at this time to predict whether or when Congress may act on climate change legislation, any laws or regulations that may be adoptedto restrict or reduce emissions of GHGs could require the operating partnership and oil and natural gas operators that develop our properties to incur increasedoperating costs and could have an adverse effect on demand for the oil and natural gas produced from our properties. Our oil and natural gas reserve data and future net revenue estimates are uncertain. Estimates of proved reserves and related future net revenues are projections based on engineering data and reports of independent consulting petroleumengineers hired for that purpose. The process of estimating reserves requires substantial judgment, resulting in imprecise determinations. Different reserveengineers may make different estimates of reserve quantities and related revenue based on the same data. Therefore, those estimates should not be construed asbeing accurate estimates of the current market value of our proved reserves. If these estimates prove to be inaccurate, our business may be adversely affected bylower revenues. We are affected by changes in oil and natural gas prices. Oil prices and natural gas prices may experience inverse price changes. Risks Inherent In An Investment In Our Common Units Cost reimbursement due our general partner may be substantial and reduce our cash available to distribute to our unitholders. Prior to making any distribution on the common units, we reimburse the general partner and its affiliates for reasonable costs and expenses of management.The reimbursement of expenses could adversely affect our ability to pay cash distributions to our unitholders. Our general partner has sole discretion to determinethe amount of these expenses, subject to the annual limit of 5% of an amount primarily based on our distributions to partners for that fiscal year. The annual limitincludes carry-forward and carry-back features, which could allow costs in a year to exceed what would otherwise be the annual reimbursement limit. In addition,our general partner and its affiliates may provide us with other services for which we will be charged fees as determined by our general partner. Our net income as reported for tax and financial statement purposes may differ significantly from our cash flow that is used to determine cash available fordistributions. Net income as reported for financial statement purposes is presented on an accrual basis in conformity with accounting principles generally accepted in theUnited States of America. Unitholder K-1 tax statements are calculated based on applicable tax conventions, and taxable income as calculated for each year will beallocated among unitholders who hold units on the last day of each month. Distributions, however, are calculated on the basis of actual cash receipts, changes incash reserves, and disbursements during the relevant reporting period. Consequently, due to timing differences between the receipt of proceeds of production andthe point in time at which the production giving rise to those proceeds actually occurs, net income reported on our consolidated financial statements and onunitholder K-1's will not reflect actual cash distributions during that reporting period. 10 Our unitholders have limited voting rights and do not control our general partner, and their ability to remove our general partner is limited. Our unitholders have only limited voting rights on matters affecting our business. The general partner of our general partner manages our activities. Ourunitholders only have the right to annually elect the managers comprising the Advisory Committee of the Board of Managers of the general partner of our generalpartner. Our unitholders do not have the right to elect the other managers of the general partner of our general partner on an annual or any other basis. Our general partner may not be removed as our general partner except upon approval by the affirmative vote of the holders of at least a majority of ouroutstanding common units (including common units owned by our general partner and its affiliates), subject to the satisfaction of certain conditions. Our generalpartner and its affiliates do not own sufficient common units to be able to prevent its removal as general partner, but they do own sufficient common units to makethe removal of our general partner by other unitholders difficult. These provisions may discourage a person or group from attempting to remove our general partner or acquire control of us without the consent of our generalpartner. As a result of these provisions, the price at which our common units trade may be lower because of the absence or reduction of a takeover premium in thetrading price. The control of our general partner may be transferred to a third party without unitholder consent. Our general partner may withdraw or transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets withoutthe consent of our unitholders. Other than some transfer restrictions agreed to among the owners of our general partner relating to their interests in our generalpartner, there is no restriction in our partnership agreement or otherwise for the benefit of our limited partners on the ability of the owners of our general partner totransfer their ownership interests to a third party. The new owner of the general partner would then be in a position to replace the management of our Partnershipwith its own choices. Our general partner and its affiliates have conflicts of interests, which may permit our general partner and its affiliates to favor their own interests to thedetriment of unitholders. We and our general partner and its affiliates share, and therefore compete for, the time and effort of general partner personnel who provide services to us.Officers of our general partner and its affiliates do not, and are not required to, spend any specified percentage or amount of time on our business. In fact, ourgeneral partner has a duty to manage our Partnership in the best interests of our unitholders, but it also has a duty to operate its business for the benefit of itspartners. Some of our officers are also involved in management and ownership roles in other oil and natural gas enterprises and have similar duties to them anddevote time to their businesses. Because these shared officers function as both our representatives and those of our general partner and its affiliates and of thirdparties, conflicts of interest could arise between our general partner and its affiliates, on the one hand, and us or our unitholders, on the other, or between us or ourunitholders on the one hand and the third parties for which our officers also serve management functions. As a result of these conflicts, our general partner and itsaffiliates may favor their own interests over the interests of unitholders. We may issue additional securities, diluting our unitholders' interests. We can and may issue additional common units and other capital securities representing limited partnership units, including options, warrants, rights,appreciation rights and securities with rights to distributions and allocations or in liquidation equal or superior to our common units; however, a majority of theunitholders must approve such issuance if (i) the partnership securities to be issued will have greater rights or powers than our common units or (ii) if after givingeffect to such issuance, such newly issued partnership securities represent over 20% of the outstanding limited partnership interests. If we issue additional common units, it will reduce our unitholders' proportionate ownership interest in us. This could cause the market price of the commonunits to fall and reduce the per unit cash distributions paid to our unitholders. In addition, if we issued limited partnership units with voting rights superior to thecommon units, it could adversely affect our unitholders' voting power. Our unitholders may not have limited liability in the circumstances described below and may be liable for the return of certain distributions. Under Delaware law, our unitholders could be held liable for our obligations to the same extent as a general partner if a court determined that the right ofunitholders to remove our general partner or to take other action under our partnership agreement constituted participation in the "control" of our business. Our general partner generally has unlimited liability for the obligations of our Partnership, such as its debts and environmental liabilities, except for thosecontractual obligations of our Partnership that are expressly made without recourse to the general partner. In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that, under certain circumstances, a unitholder may be liablefor the amount of distribution for a period of three years from the date of distribution. Because we conduct our business in various states, the laws of those states may pose similar risks to our unitholders. To the extent to which we conductbusiness in any state, our unitholders might be held liable for our obligations as if they were general partners if a court or government agency determined that wehad not complied with that state's partnership statute, or if rights of unitholders constituted participation in the "control" of our business under that state'spartnership statute. In some of the states in which we conduct business, the limitations on the liability of limited partners for the obligations of a limited partnershiphave not been clearly established. 11 We are dependent upon key personnel, and the loss of services of any of our key personnel could adversely affect our operations. Our continued success depends to a considerable extent upon the abilities and efforts of the senior management of our general partner, particularly WilliamCasey McManemin, its Chief Executive Officer, Bradley J. Ehrman, its Chief Operating Officer and Leslie A. Moriyama, its Chief Financial Officer. The loss ofthe services of any of these key personnel could have a material adverse effect on the results of our operations. We have not obtained insurance or entered intoemployment agreements with any of these key personnel. We are dependent on service providers who assist us with providing Schedule K-1 tax statements to our unitholders. There are a very limited number of service firms that currently perform the detailed computations needed to provide each unitholder with estimated depletionand other tax information to assist the unitholder in various United States income tax computations. There are also very few publicly traded limited partnershipsthat need these services. As a result, the future costs and timeliness of providing Schedule K-1 tax statements to our unitholders is uncertain. Tax Risks The tax consequences to a unitholder of the ownership and sale of common units will depend in part on the unitholder’s tax circumstances. Each unitholdershould, therefore, consult such unitholder’s own tax advisor about the federal, state and local tax consequences of the ownership of common units. We generally do not obtain rulings or assurances from the IRS or state or local taxing authorities on matters affecting us. We generally have not requested, and do not intend to request, rulings from the Internal Revenue Service, or IRS, or state or local taxing authorities withrespect to owning and disposing of our common units or other matters affecting us. It may be necessary to resort to administrative or court proceedings in an effortto sustain some or all of those conclusions or positions taken or expressed by us, and some or all of those conclusions or positions ultimately may not be sustained.Our unitholders and general partner will bear, directly or indirectly, the costs of any contest with the IRS or other taxing authority. Notwithstanding the foregoing,in 2013 we obtained a ruling from the IRS permitting us to aggregate the Minerals NPI and the Maecenas NPI for federal income tax purposes effective January 1,2013. We will be subject to federal income tax and possibly certain state corporate income or franchise taxes if we are classified as a corporation and not as apartnership for federal income tax purposes. As stated above, we have not requested, and will not request, any ruling from the IRS as to our status as a partnership for federal income tax purposes. If theIRS were to challenge our federal income tax status, such a challenge could result in an audit of our unitholders’ tax returns and adjustments to items on their taxreturns that are unrelated to their ownership of our common units. In addition, our unitholders would bear the cost of any expenses incurred in connection with anexamination of their personal tax returns. If we were taxable as a corporation for federal income tax purposes in any taxable year, our income, gains, losses and deductions would be reflected on our taxreturn rather than being passed through proportionately to our unitholders, and our net income would be taxed at corporate rates. In addition, some or all of thedistributions made to our unitholders would be treated as dividend income without offset for depletion, and distributions would be reduced as a result of the federal,state and local taxes paid by us. If we were taxable as a corporation for federal income tax purposes, we may also be subject to additional state-level corporate income or franchise taxes. The IRS could reallocate items of income, gain, deduction and loss between transferors and transferees of common units if the IRS does not accept our monthlyconvention for allocating such items. In general, each of our items of income, gain, loss and deduction will, for federal income tax purposes, be determined annually, and one twelfth of each annualamount will be allocated to those unitholders who hold common units on the last business day of each month in that year. In certain circumstances we may makethese allocations in connection with extraordinary or nonrecurring events on a more frequent basis. As a result, transferees of our common units may be allocateditems of our income, gain, loss and deduction realized by us prior to the date of their acquisition of our common units. The U.S. Treasury Department has issuedfinal Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocatetax items among transferors and transferee unitholders. Nonetheless, if this method is determined to be an unreasonable method of allocation, our income, gain, lossand deduction would be reallocated among our unitholders and our general partner, and our unitholders may have more taxable income or less taxable loss. Ourgeneral partner is authorized to revise our method of allocation between transferors and transferees, as well as among our other unitholders whose common unitsotherwise vary during a taxable period, to conform to a method permitted or required by the Internal Revenue Code and the regulations or rulings promulgatedthereunder. 12 Our unitholders may not be able to deduct losses attributable to their common units. Any losses relating to our unitholders’ common units will be losses related to portfolio income and their ability to use such losses may be limited. O ur unitholders’ partnership tax information may be audited. We will furnish our unitholders with a Schedule K-1 tax statement that sets forth their allocable share of income, gains, losses and deductions. In preparing thisschedule, we will use various accounting and reporting conventions and various depreciation and amortization methods we have adopted. This schedule may notyield a result that conforms to statutory or regulatory requirements or to administrative pronouncements of the IRS. Further, our tax return may be audited, and anysuch audit could result in an audit of our unitholders’ individual income tax returns as well as increased liabilities for taxes because of adjustments resulting fromthe audit. An audit of our unitholders’ returns also could be triggered if the tax information relating to their common units is not consistent with the Schedule K-1that we are required to provide to the IRS. O u r unitholders may have more taxable income or less taxable loss with respect to thei r common units if the IRS does not respect our method for determi ningthe adjusted tax basis of thei r common units. We have adopted a reporting convention that will enable our unitholders to track the basis of their individual common units or unit groups and use this basis incalculating their basis adjustments under Section 743 of the Internal Revenue Code and gain or loss on the sale of common units. This method does not complywith an IRS ruling that requires a portion of the combined tax basis of all common units to be allocated to each of the common units owned by a unitholder upon asale or disposition of less than all of the common units and may be challenged by the IRS. If such a challenge is successful, our unitholders may have to recognizemore taxable income or less taxable loss with respect to common units disposed of and common units they continue to hold. Tax-exempt investors may recognize unrelated business taxable income. Generally, unrelated business taxable income, or UBTI, can arise from a trade or business unrelated to the exempt purposes of the tax-exempt entity that isregularly carried on by either the tax-exempt entity or a partnership in which the tax-exempt entity is a partner. However, UBTI does not apply to interest income,royalties (including overriding royalties) or net profits interests, whether the royalties or net profits are measured by production or by gross or taxable income fromthe property. Pursuant to the provisions of our partnership agreement, our general partner shall use all reasonable efforts to prevent us from realizing income thatwould constitute UBTI. In addition, our general partner is prohibited from incurring certain types and amounts of indebtedness and from directly owning workinginterests or cost bearing interests and, in the event that any of our assets become working interests or cost bearing interests, is required to assign such interests to theoperating partnership subject to the reservation of a net profits overriding royalty interest. However, it is possible that we may realize income that would constituteUBTI in an effort to maximize unitholder value. Tax consequences of certain NPIs are uncertain. We are prohibited from owning working interests or cost-bearing interests. At the time of the creation of the Minerals NPI, we assigned to the operatingpartnership all rights in any such working interests or cost-bearing interests that might subsequently be created from the mineral properties that were and are subjectof the Minerals NPI. As additional working interests and other cost-bearing interests are created out of such mineral properties, they are owned by the operatingpartnership pursuant to such original assignment, and we have executed various documents since the creation of the Minerals NPI to confirm such treatment underthe original assignment. This treatment could be characterized differently by the IRS, and in such a case we are unable to predict, with certainty, all of the incometax consequences relating to the Minerals NPI as it relates to such working interests and other cost-bearing interests. Our unitholders may not be entitled to deductions for percentage depletion with respect to our oil and natural gas interests. Our unitholders will be entitled to deductions for the greater of either cost depletion or (if otherwise allowable) percentage depletion with respect to the oil andnatural gas interests owned by us. However, percentage depletion is generally available to a unitholder only if he qualifies under the independent producerexemption contained in the Internal Revenue Code. For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil,natural gas, or derivative products or the operation of a major refinery. If a unitholder does not qualify under the independent producer exemption, he generally willbe restricted to deductions based on cost depletion. 13 Our unitholders may have more taxable income or less taxable loss on an ongoing basis if the IRS does not accept our method of allocating depletiondeductions. The Internal Revenue Code requires that income, gain, loss and deduction attributable to appreciated or depreciated property that is contributed to a partnershipin exchange for a partnership interest in the partnership must be allocated so that the contributing partner is charged with, or benefits from, unrealized gain orunrealized loss, referred to as “Built-in Gain” and “Built-in Loss,” respectively, associated with the property at the time of its contribution to the partnership. Ourpartnership agreement provides that the adjusted tax basis of the oil and natural gas properties contributed to us is allocated to the contributing partners for thepurpose of separately determining depletion deductions. Any gain or loss resulting from the sale of property contributed to us will be allocated to the partners thatcontributed the property, in proportion to their percentage interest in the contributed property, to take into account any Built-in Gain or Built-in Loss. This methodof allocating Built-in Gain and Built-in Loss is not specifically permitted by United States Treasury regulations, and the IRS may challenge this method. Such achallenge, if successful, could cause our unitholders to recognize more taxable income or less taxable loss on an ongoing basis in respect of their common units. Our unitholders may have more taxable income or less taxable loss on an ongoing basis if the IRS does not accept our method of determining a unitholder'sshare of the basis of partnership property. Our general partner utilizes a method of calculating each unitholder's share of the basis of partnership property that results in an aggregate basis for depletionpurposes that reflects the purchase price of common units as paid by the unitholder. This method is not specifically authorized under applicable Treasuryregulations, and the IRS may challenge this method. Such a challenge, if successful, could cause our unitholders to recognize more taxable income or less taxableloss on an ongoing basis in respect of their common units. The ratio of the amount of taxable inco me that will be allocated to a unitholder to the amount of cash that will be distributed to a unitholder is uncertain , andcash dist ributed to a unitholder may not be sufficient to pay tax on the income we allocate to a unitholder . The amount of taxable income realized by a unitholder will be dependent upon a number of factors including: (i) the amount of taxable income recognized byus; (ii) the amount of any gain recognized by us that is attributable to specific asset sales that may be wholly or partially attributable to Built-in Gain and theresulting allocation of such gain to a unitholder, depending on the asset being sold; (iii) the amount of basis adjustment pursuant to the Internal Revenue Codeavailable to a unitholder based on the purchase price for any common units and the amount by which such price was greater or less than a unitholder’sproportionate share of inside tax basis of our assets attributable to the common units when the common units were purchased; and (iv) the method of depletionavailable to a unitholder. Therefore, it is not possible for us to predict the ratio of the amount of taxable income that will be allocated to a unitholder to the amountof cash that will be distributed to a unitholder. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal tothe actual tax liability that results from that income. A unitholder may lose his status as a partner of our Partnership for federal income tax purposes if he lend s our common units to a short seller to cover a shortsale of such common units. If a unitholder loans his common units to a short seller to cover a short sale of common units, he may be considered as having disposed of his ownership ofthose common units for federal income tax purposes. If so, the unitholder would no longer be a partner of our Partnership for tax purposes with respect to thosecommon units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period, any of our income, gain, loss ordeduction with respect to those common units would not be reportable, and any cash distributions received for those common units would be fully taxable and maybe treated as ordinary income. If we are not notified (either directly or through a broker) of a sale or other transfer of common units, some distributions and federal income tax information orreports with respect to such units may not be provided to the purchaser or other transferee of the units and may instead continue to be provided to the originaltransferor. If our transfer agent or any other nominee holding common units on behalf of a partner is not timely notified of a sale or other transfer of common units, and aproper transfer of ownership is not recorded on the appropriate books and records, some distributions and federal income tax information or reports with respect tothese common units may not be made or provided to the transferee of the units and may instead continue to be made or provided to the original transferor.Notwithstanding a transferee's failure to receive distributions and federal income tax information or reports from us with respect to these units, the IRS maycontend that such transferee is a partner for federal income tax purposes and that some allocations of income, gain, loss or deduction by us should have beenreported by such transferee. Alternatively, the IRS may contend that the transferor continues to be a partner for federal income tax purposes and that allocations ofincome, gain, loss or deduction by us should have been reported by such transferor. If the transferor is not treated as a partner for federal income tax purposes, anycash distributions received by such transferor with respect to the transferred units following the transfer would be fully taxable as ordinary income to the transferor. 14 A sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period could result in adverse tax consequences to aunitholder . We will terminate for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. A termination would result in the closing of our taxable year for a unitholder. As a result, if a unitholder has a different taxable year than we have, hemay be required to include his allocable share of our income, gain, loss, deduction, credits and other items from both the taxable year ending prior to the year of ourtermination and the short taxable year ending at the time of our termination in the same taxable year. A termination also could result in penalties if we were unableto determine that the termination occurred. Foreign, state and local taxes could be withheld on amount s otherwise distributable to a unitholder . A unitholder may be required to file tax returns and be subject to tax liability in the foreign, state or local jurisdictions where he resides and in each state orlocal jurisdiction in which we have assets or otherwise do business. We also may be required to withhold state income tax from distributions otherwise payable to aunitholder, and state income tax may be withheld by others on royalty payments to us. Certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result offuture legislation. Both the Proposed Fiscal Year 2017 Federal Budget and proposed legislation in Congress would, if enacted into law, make significant changes to United Statestax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration activities. These changesinclude, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions forintangible drilling and development costs, (iii) the repeal of the domestic manufacturing tax deduction for oil and natural gas companies, and (iv) an extension ofthe amortization period for certain geological and geophysical expenditures. It is unclear whether any such changes will be enacted or how soon any such changescould become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminatecertain tax deductions that are currently available to our unitholders and to oil and natural gas operators that we rely upon to develop our properties. Suchlegislation or changes could negatively impact both our unitholders and our Partnership financially. If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it may collect any resulting taxes (including any applicablepenalties and interest) directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced. Pursuant to the Bipartisan Budget Act of 2015, if the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it may collectany resulting taxes (including any applicable penalties and interest) directly from us. We generally will have the ability to shift any such tax liability to our generalpartner and our unitholders in accordance with their interests in us during the year under audit, but there can be no assurance that we will be able to do so under allcircumstances. If we are required to make payments of taxes, penalties and interest resulting from audit adjustments, our cash available for distribution to ourunitholders might be substantially reduced. Di sclosure Regarding Forward-Looking Statements Statements included in this report that are not historical facts (including any statements concerning plans and objectives of management for future operationsor 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 futureexpectations, contain projections of results of operations or of financial condition or state other forward-looking information. These forward-looking statements are made based upon management's current plans, expectations, estimates, assumptions and beliefs concerning future eventsimpacting us and, therefore, involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual resultscould differ materially from those expressed or implied in the forward-looking statements for a number of important reasons, including those discussed under "RiskFactors" and elsewhere in this report. You should read these statements carefully because they may discuss our expectations about our future performance, contain projections of our futureoperating results or our future financial condition, or state other forward-looking information. Before you invest, you should be aware that the occurrence of any ofthe events herein described in "Risk Factors" and elsewhere in this report could substantially harm our business, results of operations and financial condition andthat 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. 15 ITEM 1B. UNRESOLVED STAFF COMMENTS None. ITEM 2. PROPERTIES Facilities Our office in Dallas consists of 11,847 square feet of leased office space. The operating partnership owns a field office in Hooker, Oklahoma.   Properties We own two categories of properties: Royalty Properties and Net Profits Interests (“NPIs”). Royalty Properties We own Royalty Properties representing producing and nonproducing mineral, royalty, overriding royalty, net profits and leasehold interests in propertieslocated in 574 counties and parishes in 25 states. Acreage amounts listed herein represent our best estimates based on information provided to us as a royaltyowner. Due to the significant number of individual deeds, leases and similar instruments involved in the acquisition and development of the Royalty Properties byus or our predecessors, acreage amounts are subject to change as new information becomes available. In addition, as a royalty owner, our access to informationconcerning activity and operations on the Royalty Properties is limited. Most of our producing properties are subject to old leases and other contracts pursuant towhich we are not entitled to well information. Some of our newer leases provide for access to technical data and other information. We may have limited access topublic data in some areas through third party subscription services. Consequently, the exact number of wells producing from or drilling on the Royalty Properties isnot determinable. The primary manner by which we will become aware of activity on the Royalty Properties is the receipt of division orders or othercorrespondence from operators or purchasers. Acreage Summary The following table sets forth, as of December 31, 2015, a summary of our gross and net acres, where applicable, of mineral, royalty, overriding royalty andleasehold interests, and a compilation of the number of counties and parishes and states in which these interests are located. The majority of our net mineral acresare unleased. Acreage amounts may not add across due to overlapping ownership among categories. Mineral Royalty Overriding Royalty Leasehold Total Number of States 25 18 18 8 25 Number of Counties/Parishes 465 190 137 34 574 Gross Acres 2,307,000 618,000 208,000 33,000 3,113,000 Net Acres (where applicable) 377,000 — — — 377,000 Our net interest in production from royalty, overriding royalty and leasehold interests is based on lease royalty and other third-party contractual terms, whichvary from property to property. Consequently, net acreage ownership in these categories is not determinable. Our net interest in production from properties inwhich we own a royalty or overriding royalty interest may be affected by royalty terms negotiated by the previous mineral interest owners in such tracts and theirlessees. Our interest in the majority of these properties is perpetual in nature. However, a minor portion of the properties are subject to terms and conditionspursuant to which a portion of our interest may terminate upon cessation of production. 16 The following table sets forth, as of December 31, 2015, the combined summary of total gross and net acres, where applicable, of mineral, royalty, overridingroyalty and leasehold interests in each of the states in which these interests are located. State Gross  Net  State Gross Net  Alabama 105,000 8,000 Missouri <500 < 500 Arkansas 47,000 15,000 Montana 282,000 63,000 California 1,000 < 500 Nebraska 3,000 < 500 Colorado 23,000 1,000 New Mexico. 42,000 3,000 Florida 89,000 25,000 New York 23,000 19,000 Georgia 4,000 1,000 North Dakota 292,000 46,000 Illinois 5,000 1,000 Oklahoma 230,000 17,000 Indiana < 500 < 500 Pennsylvania. 10,000 6,000 Kansas 14,000 2,000 South Dakota 14,000 1,000 Kentucky 2,000 1,000 Texas 1,636,000 152,000 Louisiana 132,000 3,000 Utah 6,000 < 500 Michigan 54,000 3,000 Wyoming 27,000 1,000 Mississippi 72,000 9,000 < 500 means acreage owned did not round up to 1,000. Leasing Activity The operating partnership and we received cash payments in the amount of $51,000 during 2015 attributable to lease bonus on 11 leases and 3 poolingelections in lands located in 10 counties and parishes in four states. These leases reflected bonus payments ranging up to $1,000/acre and initial royalty termsranging up to 25%. The following table sets forth a summary of leases and pooling elections consummated during 2013 through 2015. 2015 2014 2013 Number 14 107 33 Number of States 4 5 6 Number of Counties 10 33 21 Average Royalty 24.8% 24.4% 24.9%Average Bonus, $/acre $305 $818 $3,221 Total Lease Bonus – cash basis $51,000 $2,264,000 $2,109,000 Amounts reflected above may differ from our consolidated financial statements, which are presented on an accrual basis. Some activity may be in Net ProfitsInterests income. Average royalty and average bonus exclude amounts attributable to pooling elections, lease extensions and amendments. Payments received forgas storage, shut-in and delay rental payments, coal royalty, surface use agreements, litigation judgments and settlement proceeds are reflected in our consolidatedfinancial statements in various categories including, but not limited to, other operating revenues and other income. Net Profits Interests We own net profits overriding royalty interests (referred to as the Net Profits Interests, or “NPIs”) in various properties owned by Dorchester MineralsOperating 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 theseproperties in the preceding month. In the event costs, including budgeted capital expenditures, exceed revenues on a cash basis in a given month for propertiessubject 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 netprofit. Each of the five NPIs has previously had cumulative revenue that exceeded cumulative costs, such excess constituting net proceeds on which NPI paymentswere 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 financialstatements in accordance with generally accepted accounting principles (“GAAP”). Effective third quarter 2011, our consolidated financial statements reflectactivity attributable to the Minerals NPI, and include cash receipts and disbursements and accrued revenues and costs not yet received or paid by the Minerals NPI.Our financial statements will continue to reflect such information even if the Minerals NPI is in temporary deficit due to capital expenditures. Minerals NPIproduction volumes and prices are within the consolidated financial statements in accordance with GAAP, although accrued net profits income in the twelvemonth periods of 2014 and 2015 from the Minerals NPI was zero because accrued cumulative capital costs have exceeded accrued cumulative operating income.The amount that is included in Net Profits Income for the Minerals NPI properties for the year ended December 31, 2013 was $2,583,000. 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 equaledoutstanding capital commitments (resulting in a zero balance, i.e. neither a deficit nor surplus). Since that time, DMOLP received production revenue, paidoperating and capital expenses and made additional capital commitments, resulting in the temporary deficit on a GAAP basis described above. The Minerals NPIagain achieved a cumulative surplus on a cash basis as of September 30, 2015. The Minerals NPI had a temporary deficit balance of $500,000 at December 31,2015 due to outstanding capital commitments of $8,300,000 exceeding cash on hand of $7,800,000. (1)(1)(1)(1) 17 Acreage Summary The following tables set forth, as of December 31, 2015, information concerning properties owned by the operating partnership and subject to the NPIs.Acreage amounts listed under “Leasehold” reflect gross acres leased by the operating partnership and the working interest share (net acres) in those properties.Acreage amounts listed under “Mineral” reflect gross acres in which the operating partnership owns a mineral interest and the undivided mineral interest (netacres) in those properties. The operating partnership's interest in these properties may be unleased, leased by others or a combination thereof. Acreage amountsmay not add across due to overlapping ownership among categories. In addition to amounts listed below, the operating partnership owns interests limited to certainwellbores located on lands in which we own mineral, royalty or leasehold interests. The acreage amounts associated with the wellbore interests are included inRoyalty Properties Acreage Summary and not in the table below. Mineral Royalty Leasehold Total Number of States 12 2 6 12 Number of Counties/Parishes 61 2 12 65 Gross Acres 50,000 1,000 92,000 143,000 Net Acres 6,000 — 75,000 81,000 The following table reflects the states in which the acreage amounts listed above are located. Mineral/Royalty Leasehold Total   Gross Net  Gross Net  Gross Net  Oklahoma 12,000 1,000 80,000 74,000 92,000 75,000 Arkansas 1,000 < 500 8,000 1,000 9,000 1,000 All Others 38,000 5,000 4,000 < 500 42,000 5,000 Totals 51,000 6,000 92,000 75,000 143,000 81,000 < 500 means acreage owned did not round up to 1,000. The leasehold acreage in Arkansas listed above includes all of the acreage in the Fayetteville Shale properties in which the operating partnership participatesas a working interest owner. Costs Incurred The following table sets forth information regarding 100% of the costs incurred on a cash basis by the operating partnership during the periods indicated inconnection with the properties underlying the NPIs. Years ended December 31,   2015  2014  2013   (in thousands) Acquisition costs $— $— $— Development costs 15,120 19,034 5,974 Total $15,120 $19,034 $5,974 Productive Well Summary The following table sets forth, as of December 31, 2015, the combined number of producing wells on the properties subject to the NPIs. Gross wells referto wells in which a working interest is owned. Net wells are determined by multiplying gross wells by the working interest in those wells. Productive Wells/Units Location Gross  Net Oklahoma 138 117.4 All others 790 26.7 Total 928 144.1 Drilling Activity During 2015, we received division orders or first payments for 459 new wells completed on our Royalty Properties in twelve states, and 118 new wellscompleted on our NPI Properties in five states. Included in these totals are wells in which we own both a royalty interest and a net profits interest. Wells withsuch overlapping interests are counted in both categories. Additional information concerning selected properties is summarized below: 18(1)(1)(1)(1) (1)(1)Large, multi- well units which are forecasted in aggregate are included as one gross well. 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 741 wells had been issued on these lands as of December 31, 2015. Intotal, 636 wells were spud, of which 580 were completed as producers including wells for which we may not yet have received division orders or first payment. Insome 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 royaltyequal 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 interestafter 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 operatingpartnership subject to the Minerals NPI burden. Non-consenting mineral owners are not entitled to well data other than public information available from the NorthDakota Industrial Commission. As of December 31, 2015, 46 of these wells had achieved 150% payout. We have and will continue to consider a range of transaction structures for our unleased mineral interests including leasing to third parties, working interestparticipation through the operating partnership, electing non-consent under North Dakota law, or a combination thereof. Oil and Natural Gas Reserves The following table reflects the Partnership's proved developed and total proved reserves at December 31, 2015. The reserves are based on the reports oftwo independent petroleum engineering consulting firms: Calhoun, Blair & Associates and LaRoche Petroleum Consultants, Ltd. Calhoun Blair & Associatesis registered with the Engineering Board of the State of Texas, and has been engaged in the business of oil and natural gas property evaluation since 1998.LaRoche Petroleum Consultants, Ltd. is registered with the Engineering Board of the State of Texas. The LaRoche firm has been engaged in the business of oiland natural gas property evaluation since its formation in 1979. Other than our filings with the SEC, we have not filed the estimated proved reserves with, orincluded them in any reports to, any federal agency. Copies of the reports prepared by Calhoun, Blair & Associates and LaRoche Petroleum Consultants, Ltd.are attached hereto as Exhibits 99.1 and 99.2. As described above, the Partnership does not have information that would be available to a company with oil and natural gas operations because detailedinformation is not generally available to owners of royalty interests. The Partnership’s Chief Operating Officer (“COO”) gathers production information andprovides such information to our two independent petroleum engineering consulting firms who extrapolate from such information estimates of the reservesattributable to the Royalty Properties and NPIs based on their expertise in the oil and natural gas fields where the Royalty Properties and NPIs are situated, aswell as publicly available information. Ensuring compliance with generally accepted petroleum engineering and evaluation methods and procedures is theresponsibility of the COO. Our COO has a bachelor’s degree in Petroleum Engineering from the University of Alberta, and has worked in the upstream oil andnatural gas business in various capacities since 1996. The COO reports directly to the Chief Executive Officer (“CEO”). Our CEO ensures compliance withSEC guidance. Our CEO received his Bachelor of Science degree in Petroleum Engineering from Texas A&M University in 1984, and has been a RegisteredProfessional Engineer in Texas since 1988. Summary of Oil and Gas Reserves as of Fiscal Year-EndAll Proved Developed and located in the United States  Royalty Properties  Net Profits Interests   Total Year Oil (mbbls) NaturalGas (mmcf) Oil (mbbls) NaturalGas (mmcf) Oil (mbbls) NaturalGas (mmcf) 2015 4,631 23,618 1,047 25,752 5,678 49,370 2014 4,482 26,808 1,264 28,893 5,746 55,701 2013 4,293 31,929 794 28,544 5,087 60,473 Reserves reflect 96.97% of the corresponding amounts assigned to the operating partnership’s interests in the properties underlying the NetProfits Interests. 19(1)(1) Proved oil and natural gas reserves means those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimatedwith reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions,operating methods, and governmental regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates thatrenewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbonsmust have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Please see “Item 7 –Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations” for average sales prices. The Hugoton Field reflected in the Net Profits Interests above is the only significant field, defined as more than 15% of total proved developed reserves.Hugoton Field production (not sales) for the last three years is listed below:   Production by Significant Field   Oil bbls  Gas mcf  Boe 2015 — 2,276,000 379,000 2014 — 2,677,000 446,000 2013 — 3,000,000 500,000 Title to Properties We believe we have satisfactory title to all of our assets. Record title to essentially all of our assets has undergone the appropriate filings in the jurisdictions inwhich such assets are located. Title to property may be subject to encumbrances. We believe that none of such encumbrances should materially detract from thevalue of our properties or from our interest in these properties or should materially interfere with their use in the operation of our business. ITEM 3. LEGAL PROCEEDINGS The Partnership and the operating partnership are involved in legal and/or administrative proceedings arising in the ordinary course of their businesses, noneof which have predictable outcomes and none of which are believed to have any significant effect on financial position or operating results. ITEM 4. MINE SAFETY DISCLOSURES Not applicable. 20 PART II  ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OFEQUITY SECURITIES Our common units began trading on the NASDAQ National Market (now the NASDAQ Global Select Market) on February 3, 2003. The following tablesummarizes the high and low sales information for the common units for the period indicated.   201 5  20 14   High  Low  High  Low First Quarter $26.76 $22.50 $26.31 $24.08 Second Quarter $23.77 $21.26 $30.61 $26.15 Third Quarter $21.67 $12.84 $35.55 $28.51 Fourth Quarter $16.75 $8.77 $31.72 $22.02 As of December 31, 2015, there were 12,739 common unitholders. Beginning with the quarter ended March 31, 2003, as required by our partnership agreement, we distributed and will continue to distribute, on a quarterlybasis, within 45 days of the end of the quarter, all of our available cash. Available cash means all cash and cash equivalents on hand at the end of that quarter, lessany amount of cash reserves that our general partner determines is necessary or appropriate to provide for the conduct of its business or to comply with applicablelaws or agreements or obligations to which we may be subject. Unitholder cash distributions per common unit for the past three years have been:   Per Unit Amount   201 5  201 4  201 3 First Quarter $0.306553 $0.496172 $0.448209 Second Quarter $0.167430 $0.490861 $0.395583 Third Quarter $0.194234 $0.447805 $0.455287 Fourth Quarter $0.199076 $0.485780 $0.468560 Each of the foregoing distributions were paid on 30,675,431 units. Fourth quarter distributions are paid in February of the following calendar year tounitholders of record in January or February of such following year. The partnership agreement requires the next cash distribution to be paid by May 15, 2016. Please see "Fourth Quarter 2015 Distribution Indicated Price" discussion contained in “Item 7. Management's Discussion and Analysis of FinancialCondition and Results of Operations Liquidity and Capital Resources Distributions” for production periods and cash receipts and weighted average pricescorresponding to the fourth quarter 2015 distribution.  21__ ___ ___  Performance Graph The following graph compares the performance of our common units with the performance of the NASDAQ Composite Index (the “NASDAQ Index”) anda peer group index from December 31, 2010 through December 31, 2015. The graph assumes that at the beginning of the period, $100 was invested in each of(1) our common units, (2) the NASDAQ Index, and (3) the peer group, and that all distributions or dividends were reinvested quarterly. We do not believe thatany published industry or line-of-business index accurately reflects our business. Accordingly, we have created a special peer group index consisting ofcompanies whose royalty trust units are publicly traded on the New York Stock Exchange. Our peer group index includes the units of the following companies:Cross Timbers Royalty Trust, Mesa Royalty Trust, Sabine Royalty Trust, Permian Basin Royalty Trust, Hugoton Royalty Trust and the San Juan Basin RoyaltyTrust. ISSUER PURCHASES OF EQUITY SECURITIES Period(a)(b)(c)(d)   Total Number of UnitsPurchased  Average Price Paid perUnit  Total Number of UnitsPurchased as Part ofPublicly Announced Plansor ProgramsMaximum Number (orApproximate Dollar Value)of Units that May Yet BePurchased Under the Plansor ProgramsMonth #1(October 1, 2015 – October31, 2015)0N/A068,992 Month #2 (November 1,2015 – November 30, 2015)0N/A068,992 Month #3 (December 1,2015 – December 31, 2015)9,247 9.909,24768,992 Total9,247 9.909,24768,992 (1)The number of common units that the operating partnership may grant under the Dorchester Minerals Operating LP Equity Incentive Program, which wasapproved by our common unitholders on May 20, 2015 (the “Equity Incentive Program”), each fiscal year may not exceed 0.333% of the number ofcommon units outstanding at the beginning of the fiscal year. In 2015, the maximum number of common units that could be granted under the EquityIncentive plan was 102,149 common units. 22(1)(1)(2)(1)(2)(1) (2)Includes 0 common units purchased by the operating partnership on the open market pursuant to the Sale Plan for the purpose of satisfying equity awardsto be granted pursuant to the Equity Incentive Program and 9,247 common units withheld from grants of common units made pursuant to the EquityIncentive Program to pay withholding taxes payable by the grantee upon such grants. ITEM 6. SELECTED FINANCIAL DATA Basis of Presentation This table should be read in conjunction with the consolidated financial statements and related notes included elsewhere in this document.   Fiscal Year Ended December 31, (in thousands, except per unit data)   2015  201 4  2013  2012  20 11 Total operating revenues $31,863 $65,170 $65,869 $63,204 $69,489 Depreciation, depletion and amortization 10,068 10,050 13,143 16,583 18,348 Net income 13,255 45,239 43,576 38,022 42,215 Net income per unit (basic and diluted) 0.42 1.42 1.37 1.20 1.33 Cash distributions 36,608 60,539 55,015 56,870 52,505 Cash distributions per unit 1.15 1.90 1.73 1.79 1.65 Total assets 73,729 97,509 112,785 123,800 142,769 Total liabilities 558 985 961 537 658 Partners' capital 73,171 96,524 111,824 123,263 142,111 Because of depletion (which is usually higher in the early years of production), a portion of every distribution of revenues from propertiesrepresents a return of a limited partner's original investment. Until a limited partner receives cash distributions equal to his original investment,in certain circumstances, 100% of such distributions may be deemed to be a return of capital. Cash distributions by year exclude the fourthquarter distribution declared in January of the following year, but include the prior year fourth quarter distribution declared in January of thecurrent year.  23(1)(1)(1) ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 2015 Overview Our results during 2015 were highly affected by industrywide decreases in realized oil and natural gas prices and the related reduction in drilling activity.Significant results include the following: ●Net income of $13.3 million; ●Distributions of $35.4 million to our limited partners; ●Identification of 459 new wells completed on our Royalty Properties in twelve states, and 118 new wells completed on our NPI Properties in five states.Included in these totals are wells in which we own both a royalty interest and a net profits interest. Wells with such overlapping interests are counted inboth categories. ●Consummation of 14 leases and pooling elections of our mineral interest in undeveloped properties located in 10 counties and parishes in four states. Critical Accounting Policies We utilize the full cost method of accounting for costs related to our oil and natural gas properties. Under this method, all such costs are capitalized andamortized 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 testthat 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% plusthe lower of cost or market value of unproved properties. Our Partnership did not assign any book or market value to unproved properties, including nonproducingroyalty, mineral and leasehold interests. The full cost ceiling is evaluated at the end of each quarter and when events indicate possible impairment. No impairmentshave been recorded since 2003. The discounted present value of our proved oil and natural gas reserves is a major component of the ceiling test calculation and requires many subjectivejudgments. Estimates of reserves are forecasts based on engineering and geological analyses. Different reserve engineers could reach different conclusions as toestimated quantities of natural gas or crude oil reserves based on the same information. Our reserve estimates are prepared by independent consultants. Thepassage 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 more significant revisions will not be necessary in the future. Significant downward revisions could result in animpairment representing a non-cash charge to income. In addition to the impact on calculation of the ceiling test, estimates of proved reserves are also a majorcomponent 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 discountedpresent value of our reserves are objectively determined. The ceiling test calculation requires use of the unweighted arithmetic average of the first day of the monthprice 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 constantfor 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 havehistorically 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 tomake estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of thefinancial statements and the reported amounts of revenues and expenses during the reporting period. For example, estimates of uncollected revenues and unpaidexpenses from Royalty Properties and NPIs operated by non-affiliated entities are particularly subjective due to the inability to gain accurate and timelyinformation. Therefore, actual results could differ from those estimates. Please see “Item 1. Business—Customers and Pricing” and “Item 2. Properties—RoyaltyProperties” for additional discussion. Contractual Obligations Our office lease in Dallas, Texas comprises our contractual obligations.       Payments due by Period Contractual Obligations Total Less than 1year 1-3 years 3-5 years More than 5years Operating Lease Obligations $777,000 $318,000 $459,000 — —   24 Results of Operations Normally, our period-to-period changes in net income and cash flows from operating activities are principally determined by changes in oil and natural gassales volumes and prices, and to a lesser extent, by capital expenditures deducted under the NPI calculation. Our portion of oil and natural gas sales volumes andweighted average sales prices are shown in the following table.   Years Ended December 31, Accrual Basis Sales Volumes: 201 5 201 4 2013 Royalty Properties Gas Sales (mmcf) 3,704 3,574 5,049 Royalty Properties Oil Sales (mbbls) 524 502 379 Net Profits Interests Gas Sales (mmcf) 3,248 3,383 4,111 Net Profits Interests Oil Sales (mbbls) 399 219 140 Accrual Basis Weighted Averages Sales Price: Royalty Properties Gas Sales ($/mcf) $2.30 $4.21 $3.44 Royalty Properties Oil Sales ($/bbl) $42.23 $78.64 $94.15 Net Profits Interests Gas Sales ($/mcf) $2.49 $5.02 $4.15 Net Profits Interests Oil Sales ($/bbl) $49.46 $80.83 $91.85 Accrual Basis Production Costs Deducted under the Net ProfitsInterests ($/mcfe) $5.18 $5.70 $3.98 Comparison of the twelve-month periods ended December 31, 201 5 , 201 4 and 20 13 Royalty Properties’ oil sales volumes increased 32% from 379 mbbls during 2013 to 502 mbbls during 2014, and then increased 4% to 524 mbbls during2015. These increases are primarily due to activity in the Bakken Trend which more than offset natural declines in other regions. Royalty Properties’ gas salesvolumes decreased 29% from 5,049 mmcf during 2013 to 3,574 mmcf during 2014, and then increased 4% to 3,704 mmcf during 2015. The decrease in 2014 wasprimarily due to natural declines in the Fayetteville Shale and Barnett Shale. The increase in 2015 versus the prior year was primarily due to the release ofsuspended payments for prior periods, partially offset by natural declines. NPI properties’ oil sales volumes increased 56% from 140 mbbls during 2013 to 219 mbbls during 2014 and subsequently increased 82% to 399 mbbls during2015 due to continued activity in the Bakken region. NPI properties’ gas sales volumes decreased 18% from 4,111 mmcf during 2013 to 3,383 mmcf during 2014and subsequently decreased 4% to 3,248 mmcf in 2015 due to natural declines in the Fayetteville Shale and the sale of Kansas working interests in 2014. Weighted average oil sales prices attributable to the Royalty Properties decreased 16% from $94.15/bbl in 2013 to $78.64/bbl in 2014 and subsequentlydecreased 46% to $42.23/bbl in 2015. Royalty Properties’ weighted average gas sales prices increased 22% from $3.44/mcf during 2013 to $4.21/mcf during 2014and then decreased 45% to $2.30/mcf during 2015. All fluctuations resulted from changing market conditions. Weighted average NPI properties’ gas sales prices increased 21% from $4.15/mcf during 2013 to $5.02/mcf during 2014 and then decreased 50% to$2.49/mcf in 2015. NPI properties’ weighted average oil sales prices decreased 12% from $91.85/bbl during 2013 to $80.83/bbl during 2014 and subsequentlydecreased 39% to $49.46/bbl in 2015. All fluctuations resulted from changing market conditions. Additionally, 2014 natural gas prices include a natural gas liquidspayment accrual of $0.57/mcf related to 2014 production compared to $0.63/mcf in 2013. The natural gas liquids payments are based on an Oklahoma Guymon-Hugoton field 1994 gas delivery and processing agreement that expired at the end of 2015. During 2015 there were no natural gas liquid payments as the gasprocessing facility incurred significant downtime resulting from plant repairs. Our operating revenues decreased 1% from $65,869,000 during 2013 to $65,170,000 in 2014, and subsequently decreased 51% to $31,863,000 in 2015. In2014 increased natural gas prices and oil production were offset by lower lease bonus, decreased oil prices, and lower natural gas production. In 2015, sharpdeclines in commodity prices, both oil and natural gas, resulted in the significant decrease in operating revenues versus the prior year. Lease bonus income decreased from $2,319,000 in 2013 to $1,590,000 in 2014, and then decreased to $53,000 in 2015. Lease bonus income in 2015 versus2014 decreased 97% due to an industrywide reduction in leasing activity. In 2013, we received proceeds of approximately $1,886,000 from two leasingtransactions to one party in Loving County, Texas and Lea County, New Mexico. Depletion, depreciation and amortization decreased 24% from $13,143,000 in 2013 to $10,050,000 in 2014 primarily as a result of a lower depletion rate dueto upward revisions in oil and natural gas reserve estimates and reduced natural gas production. 2015 depletion and amortization increased less than 1% versusprior year to $10,068,000. Cash flow from operations and cash distributions to unitholders are not affected by depletion, depreciation and amortization. 25(1)(1)Provided to assist in determination of revenues; applies only to Net Profits Interests sales volumes prices. General and administrative (“G&A”) costs increased 22% from $4,196,000 in 2013 to $5,137,000 in 2014, primarily due to additional costs related toadministering the increased Bakken Trend and the Fayetteville Shale activity. G&A decreased 3% to $4,967,000 in 2015 compared to 2014 primarily due todecreased consulting expenses partially offset by higher costs related to outsourcing of information technology services. Other income of $712,000 during 2014 was related to a first quarter 2014 settlement of a dispute on leases in North Dakota. Net cash provided by operating activities was about the same at $56,398,000 during 2013 compared to $57,660,000 during 2014. During 2015 net cashprovided by operating activities decreased 52% to $27,692,000 due to significantly lower oil and natural gas prices, decreased Net Profits Interest natural gasproduction and lower lease bonus income, partially offset by increased Royalty Properties natural gas production and increased oil production in both RoyaltyProperties and Net Profits Interests. Climate Change Climate change has become the subject of an important public policy debate. In response to climate change concerns, many foreign countries are adoptingclimate change legislation and regulations. Although the United States Congress has considered adopting climate change legislation, it has yet to enact suchlegislation and/or regulations at the federal level. Several states have adopted or are considering adopting climate change legislation, including greenhouse gasemissions limits and cap-and-trade programs. Further, the Environmental Protection Agency (“EPA”) issued greenhouse gas monitoring and reporting regulationsthat went into effect January 1, 2010. Those regulations required that regulated facilities begin reporting greenhouse gas emissions beginning in September 2012,and annually thereafter. The EPA has also issued final regulations requiring petroleum and natural gas operators meeting a certain emission threshold to reporttheir greenhouse gas emissions to the EPA. In addition to the measuring and reporting requirements, the EPA issued an "Endangerment Finding" under Section202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of future generations. EPA has issued final regulationsrequiring the owners and operators of certain large stationary sources to obtain greenhouse gas emissions permits. Although these regulations were struck down bya 2014 decision of the United States Supreme Court in Utility Air Regulatory Group v. Environmental Protection Agency, the Court recognized EPA’s authority toimpose greenhouse gas emission limits on certain facilities that were already subject to permitting requirements based on emissions of conventional pollutants.EPA has indicated that additional sources may be subject to greenhouse gas permitting requirements in the future, and that it will use data collected through thereporting rules to decide whether to promulgate future greenhouse gas emission limits. The current state of development of many state and federal climate changeregulatory initiatives makes it difficult to predict with certainty the future impact on us, including accurately estimating the related compliance costs that theoperating partnership and oil and natural gas operators that develop our properties may incur. See Item 1A. Risk Factors – “Environmental costs and liabilities and changing environmental regulation could affect our cash flow” and “The adoption ofclimate change legislation by Congress or executive orders or regulations could result in increased operating costs and reduced demand for the oil and natural gasproduction from our properties.” Texas Margin Tax Texas imposes a franchise tax (commonly referred to as the Texas margin tax) at a rate of 0.95% in 2015 and at a rate of 0.75% in 2016 on gross revenues lesscertain deductions, as specifically set forth in the Texas margin tax statute. The Texas margin tax applies to corporations and limited liability companies, generaland 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 othernon-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 theTexas margin tax as “passive entities.” We believe our Partnership meets the requirements for being considered a “passive entity” for Texas margin tax purposesand, 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 ataxable entity under the Texas margin tax would generally be required to include its portion of Partnership revenues in its own Texas margin tax computation. TheTexas Administrative Code provides such income is sourced according to the principal place of business of the Partnership, which would be the state of Texas. Each unitholder is urged to consult an independent tax advisor regarding the requirements for filing state income, franchise and Texas margin tax returns. 26 L iquidity and Capital Resources Capital Resources Our primary sources of capital are our cash flow from the Royalty Properties and the NPIs. 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 sustainabilityof capital resources. 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 anygiven time or (ii) which would constitute "acquisition indebtedness" (as defined in Section 514 of the Internal Revenue Code of 1986, as amended). Our only cash requirements are the distributions of all our net cash flow to our unitholders, the payment of oil and natural gas production and property taxesnot otherwise deducted from gross production revenues and general and administrative expenses incurred on our behalf and allocated in accordance with ourpartnership agreement. Since the distributions to our unitholders are, by definition, determined after the payment of all expenses actually paid by us, the only cashrequirements that may create liquidity concerns for us are the payments of expenses. Since many of these expenses vary directly with oil and natural gas prices andsales volumes, such as production taxes, we anticipate that sufficient funds will be available at all times for payment of these expenses. Of the expenses that do notvary with oil and natural gas prices and sales volumes, most are reimbursements to our general partner for allocable general and administrative costs includinghome office rent, salaries, and employee benefit plans. Such reimbursements are generally limited to 5% of an amount primarily based on annual distributions toour limited partners. Historically, all such reimbursements have been substantially below the 5% limit established by the partnership agreement. Consequently, ourbusiness risks were essentially limited to distribution amount decreases. See “Item 1. Business – Credit Facilities and Financing Plans.” See “Item 1A. Risk Factors– Risks Related to our Business – Cash distributions are affected by production and other costs, some of which are outside of our control.” See “Item 1A. RiskFactors – Risks Inherent In An Investment In Our Common Units – Cost reimbursement due our general partner may be substantial and reduce our cash available todistribute to our unitholders." See "Notes to Consolidated Financial Statements – Note 3 – Related Party Transactions." Off-Balance Sheet Arrangements We have no significant off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changesin financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that are material to unitholders. Expenses and Capital Expenditures Depending upon gas prices, the operating partnership plans to continue its efforts to increase production in Oklahoma by techniques that may include fracturetreating, deepening, recompleting, and drilling. Costs vary widely and are not predictable as each effort requires specific engineering. Such activities by theoperating partnership could influence the amount we receive from the NPIs as reflected in the accrual basis production costs $/mcfe in the table under “Resultsof Operations.” The operating partnership owns and operates the wells, pipelines and central natural gas compression and dehydration facilities on its properties located inOklahoma. The operating partnership does not anticipate incurring significant expense to replace these facilities at this time. These capital and operating costsare 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 persuadeOklahoma to permit infill drilling in the Guymon-Hugoton field. Infill drilling could require considerable capital expenditures. The outcome and the cost of suchactivities are unpredictable and could influence the amount we receive from the NPIs. The operating partnership believes it now has sufficient field compressionand permits for vacuum operation for the foreseeable future. Liquidity and Working Capital Year-end cash and cash equivalents totaled $7,136,000 for 2015 and $15,912,000 for 2014. 27 Distributions Distributions to limited partners and the general partner related to cash receipts for the period from October 2014 through December 2015 were as follows:             $ in Thousands Year Quarter Record Date Payment Date Per UnitAmount  LimitedPartners  GeneralPartner 2014 4th January 26, 2015 February 5, 2015 $0.485780 $14,901 $455 2015 1st April 27, 2015 May 7, 2015 0.306553 9,404 315 2015 2nd July 27, 2015 August 6, 2015 0.167430 5,136 203 2015 3rd October 26, 2015 November 5, 2015 0.194234 5,958 236 Total distributions paid in 2015 $35,399 $1,209 2015 4th February 1, 2016 February 11, 2016 $0.199076 $6,107 $232 In general, the limited partners are allocated 96% of the Royalty Properties’ net receipts and 99% of our NPI net receipts. Net Profits Interests We receive monthly payments from the operating partnership equal to 96.97% of the net proceeds actually realized by the operating partnership from theproperties underlying the Net Profits Interests (or “NPIs”). The operating partnership retains the 3.03% balance of these net proceeds. Net proceeds generallyreflect gross proceeds attributable to oil and natural gas production actually received during the month, less production costs actually paid during the same month,net of budgeted capital expenditures. Production costs generally reflect drilling, completion, operating and general and administrative costs and exclude depletion,amortization and other non-cash costs. The operating partnership made NPI payments to us totaling $8,498,000 during October 2014 through September 2015,which payments reflected 96.97% of total net proceeds of $8,764,000 realized from September 2014 through August 2015. Net proceeds realized by the operatingpartnership during September through November 2015 were reflected in NPI payments made during October through December 2015. These payments wereincluded in the fourth quarter distribution paid in early 2016 and are excluded from this 2015 analysis. Royalty Properties Revenues from the Royalty Properties are typically paid to us with proportionate severance (production) taxes deducted and remitted by others. Additionally,we generally pay ad valorem taxes, general and administrative costs, and marketing and associated costs since royalties and lease bonuses generally do nototherwise bear operating or similar costs. After deduction of the above described costs including cash reserves, our net cash receipts from the Royalty Propertiesduring the period October 2014 through September 2015 were $28,110,000, of which $26,986,000 (96%) was distributed to the limited partners and $1,124,000(4%) was distributed to the general partner. Proceeds received by us from the Royalty Properties during the period October through December 2015 became part ofthe fourth quarter distribution paid in early 2016, which is excluded from this 2015 analysis. Distribution Determinations The actual calculation of distributions is performed each calendar quarter in accordance with our partnership agreement. The following calculation coveringthe period October 2014 through September 2015 demonstrates the method:   $ In Thousands   LimitedPartners  GeneralPartner 4% of Net Cash Receipts from Royalty Properties $— $1,124 96% of Net Cash Receipts from Royalty Properties 26,986 — 1% of NPI Payments to our Partnership — 85 99% of NPI Payments to our Partnership 8,413 — Total Distributions $35,399 $1,209 Operating Partnership Share (3.03% of Net Proceeds) — 266 Total General Partner Share $1,475 % of Total 96% 4% In summary, our limited partners received 96%, and our general partner received 4% of the net cash generated by our activities and those of the operatingpartnership during this period. Due to these fixed percentages, our general partner does not have any incentive distribution rights or other right or arrangementthat will increase its percentage share of net cash generated by our activities or those of the operating partnership. 28 During the period October 2014 through September 2015, our Partnership's quarterly distribution payments to limited partners were based on all of itsavailable cash. Available cash means all cash and cash equivalents on hand at the end of that quarter, less any amount of cash reserves that our general partnerdetermines is necessary or appropriate to provide for the conduct of its business or to comply with applicable laws or agreements or obligations to which we may besubject. Our practice is to accrue funds quarterly for amounts incurred throughout the year but invoiced and paid annually or semi-annually (e.g. ad valorem taxes,deferred compensation contributions and payroll taxes). These amounts generally are not held for periods over one year. Fourth Quarter 2015 Distribution Indicated Price In an effort to provide information concerning prices of oil and natural gas sales that correspond to our quarterly distributions, management calculates theweighted average price by dividing gross revenues received by the net volumes of the corresponding product without regard to the timing of the production towhich such sales may be attributable. This “indicated price” does not necessarily reflect the contractual terms for such sales and may be affected by transportationcosts, location differentials, and quality and gravity adjustments. While the relationship between the Partnership's cash receipts and the timing of the production ofoil and natural gas may be described generally, actual cash receipts may be materially impacted by purchasers’ release of suspended funds and by prior periodadjustments. Cash receipts attributable to the Partnership's Royalty Properties during the 2015 fourth quarter totaled approximately $7.6 million. These receipts generallyreflect oil sales during September through November 2015 and natural gas sales during August through October 2015. The weighted average indicated prices for oiland natural gas sales during the 2015 fourth quarter attributable to the Royalty Properties were $41.11/bbl and $2.25/mcf. Cash receipts attributable to the Partnership's NPIs during the 2015 fourth quarter totaled approximately $0.7 million. These receipts generally reflect oil andnatural gas sales from the properties underlying the NPIs during August through October 2015. The weighted average indicated prices for oil and natural gas salesduring the 2015 fourth quarter attributable to the NPIs were $45.12/bbl and $2.52/mcf. General and Administrative Costs In accordance with our partnership agreement, we bear all general and administrative and other overhead expenses subject to certain limitations. We reimburseour general partner for certain allocable costs, including rent, wages, salaries and employee benefit plans. This reimbursement is limited to an amount equal to thesum of 5% of our distributions plus certain costs previously paid. Through December 31, 2015, the limitation was in excess of the reimbursement amounts actuallypaid or accrued. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The following information provides quantitative and qualitative information about our potential exposures to market risk. The term "market risk" refers tothe 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 preciseindicators of expected future losses, but rather indicators of possible losses. Market Risk Related to Oil and Natural Gas Prices Essentially all of our assets and sources of income are from the Royalty Properties and the NPIs, which generally entitle us to receive a share of theproceeds from oil and natural gas production on those properties. Consequently, we are subject to market risk from fluctuations in oil and natural gas prices.Pricing for oil and natural gas production has been volatile and unpredictable for several years. We do not anticipate entering into financial hedging activitiesintended to reduce our exposure to oil and natural gas price fluctuations. Absence of Interest Rate and Currency Exchange Rate Risk We do not anticipate having a credit facility or incurring any debt, other than trade debt. Therefore, we do not expect interest rate risk to be material to us.We do not anticipate engaging in transactions in foreign currencies which could expose us to foreign currency related market risk. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The consolidated financial statements are set forth herein commencing on page F-1. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. 29 ITEM 9A. CONTROLS AND PROCEDURES Evaluation of Disclosure Controls and Procedures Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controlsand procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2015. Based on this evaluation, our Chief ExecutiveOfficer and Chief Financial Officer have concluded that, as of December 31, 2015, our disclosure controls and procedures were effective, in that they ensure thatinformation required to be disclosed by us in the reports that we file or submit under the Exchange Act is (1) recorded, processed, summarized and reported withinthe time periods specified in the SEC’s rules and forms, and (2) accumulated and communicated to our management, including our Chief Executive Officer andChief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.   Management’s Annual Report on Internal Control Over Financial Reporting Management acknowledges its responsibility for establishing and maintaining adequate internal control over financial reporting in accordance with Rule 13a-15(f) promulgated under the Exchange Act. Management has also evaluated the effectiveness of its internal control over financial reporting in accordance withgenerally accepted accounting principles within the guidelines of the Committee of Sponsoring Organizations of the Treadway Commission framework (2013).Based on the results of this evaluation, management has determined that the Partnership’s internal control over financial reporting was effective as of December 31,2015. The independent registered public accounting firm of Grant Thornton LLP, as auditors of the Partnership’s financial statements included in the AnnualReport, has issued an attestation report on the Partnership’s internal control over financial reporting. Changes in Internal Controls There were no changes in our Partnership’s internal control over financial reporting (as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934)during the quarter ended December 31, 2015, that have materially affected, or are reasonably likely to materially affect, our internal control over financialreporting. ITEM 9B. OTHER INFORMATION None.PART III ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE The information required by this item is incorporated herein by reference to the 2016 Proxy Statement, which will be filed with the Securities and ExchangeCommission not later than 120 days subsequent to December 31, 2015. ITEM 11. EXECUTIVE COMPENSATION The information required by this item is incorporated herein by reference to the 2016 Proxy Statement, which will be filed with the Securities and ExchangeCommission not later than 120 days subsequent to December 31, 2015. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS The information required by this item is incorporated herein by reference to the 2016 Proxy Statement, which will be filed with the Securities and ExchangeCommission not later than 120 days subsequent to December 31, 2015. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE The information required by this item is incorporated herein by reference to the 2016 Proxy Statement, which will be filed with the Securities and ExchangeCommission not later than 120 days subsequent to December 31, 2015. ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES The information required by this item is incorporated herein by reference to the 2016 Proxy Statement, which will be filed with the Securities and ExchangeCommission not later than 120 days subsequent to December 31, 2015. 30 PART IV ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES (a)Financial Statements and Schedules (1)See the Index to Consolidated Financial Statements on page F-1. (2)No schedules are required. (3)A list of the exhibits required by Item 601 of Regulation S-K to be filed as part of this report is set forth in the Index to Exhibits beginning onpage E-1, which immediately precedes such exhibits. 31 GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS The definitions set forth below shall apply to the indicated terms as used in this document. All volumes of natural gas referred to herein are stated at the legalpressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple. "bbl" means a standard barrel of 42 U.S. gallons and represents the basic unit for measuring the production of crude oil, natural gas liquids and condensate. "bcf” means one billion cubic feet under prescribed conditions of pressure and temperature and represents a unit for measuring the production of natural gas. “boe” means one barrel of oil equivalent, converting natural gas to oil at the ratio of 6 Mcf of natural gas to 1 Bbl of oil. Also see mcfe below. "Depletion" means (a) the volume of hydrocarbons extracted from a formation over a given period of time, (b) the rate of hydrocarbon extraction over a givenperiod of time expressed as a percentage of the reserves existing at the beginning of such period, or (c) the amount of cost basis at the beginning of a periodattributable to the volume of hydrocarbons extracted during such period. "Division order" means a document to protect lessees and purchasers of production, in which all parties who may have a claim to the proceeds of the sale ofproduction agree upon how the proceeds are to be divided. "Enhanced recovery" means the process or combination of processes applied to a formation to extract hydrocarbons in addition to those that would beproduced utilizing the natural energy existing in that formation. Examples of enhanced recovery include water flooding and carbon dioxide (CO2) injection. "Estimated future net revenues" (also referred to as "estimated future net cash flow") means the result of applying current prices of oil and natural gas toestimated future production from oil and natural gas proved reserves, reduced by estimated future expenditures, based on current costs to be incurred indeveloping and producing the proved reserves, excluding overhead. "Formation" means a distinct geologic interval, sometimes referred to as the strata, which has characteristics (such as permeability, porosity andhydrocarbon saturations) that distinguish it from surrounding intervals. "Gross acre" means the number of surface acres in which a working interest is owned. "Gross well" means a well in which a working interest is owned. "Lease bonus" means the initial cash payment made to a lessor by a lessee in consideration for the execution and conveyance of the lease. "Leasehold" means an acre in which a working interest is owned. "Lessee" means the owner of a lease of a mineral interest in a tract of land. "Lessor" means the owner of the mineral interest who grants a lease of his interest in a tract of land to a third party, referred to as the lessee. "Mineral interest" means the interest in the minerals beneath the surface of a tract of land. A mineral interest may be severed from the ownership of the surfaceof the tract. Ownership of a mineral interest generally involves four incidents of ownership: (1) the right to use the surface; (2) the right to incur costs and retainprofits, also called the right to develop; (3) the right to transfer all or a portion of the mineral interest; and (4) the right to retain lease benefits, including bonusesand delay rentals. "mcf” means one thousand cubic feet under prescribed conditions of pressure and temperature and represents the basic unit for measuring theproduction of natural gas. “mcfe” means one thousand cubic feet of natural gas equivalent, converting oil or condensate to natural gas at the ratio of 1 Bbl of oil or condensate to 6 Mcfof natural gas. This conversion ratio, which is typically used in the oil and gas industry, represents the approximate energy equivalent of a barrel of oil orcondensate to an Mcf of natural gas. The sales price of one barrel of oil or condensate has been much higher than the sales price of six Mcf of natural gas over thelast several years, so a six to one conversion ratio does not represent the economic equivalency of six Mcf of natural gas to one barrel of oil or condensate. "mbbls" means one thousand standard barrels of 42 U.S. gallons and represents the basic unit for measuring the production of crude oil, natural gas liquids andcondensate. "mmcf” means one million cubic feet under prescribed conditions of pressure and temperature and represents the basic unit for measuring the production ofnatural gas. "Net acre" means the product determined by multiplying gross acres by the interest in such acres. 32 "Net well" means the product determined by multiplying gross oil and natural gas wells by the interest in such wells. "Net profits interest" means a non-operating interest that creates a share in gross production from another (operating or non-operating) interest in oil andnatural gas properties. The share is determined by net profits from the sale of production and customarily provides for the deduction of capital and operating costsfrom the proceeds of the sale of production. The owner of a net profits interest is customarily liable for the payment of capital and operating costs only to the extentthat revenue is sufficient to pay such costs but not otherwise. "Operator" means the individual or company responsible for the exploration, development, and production of an oil or natural gas well or lease. "Overriding royalty interest" means a royalty interest created or reserved from another (operating or non-operating) interest in oil and natural gas properties.Its term extends for the same term as the interest from which it is created. “Payout” or “Back-in” occurs when the working interest owners who participate in the costs of drilling and completing a well recoup the costs andexpenses, or a multiple of the costs and expenses, of drilling and completing that well. Only then are the owners who chose not to contribute to these initial costsentitled to participate with the other owners in production and share in the expenses and revenues associated with the well. The reversionary interest or back-ininterest of an owner similarly occurs when the owner becomes entitled to a specified share of the working or overriding royalty interest when specified costs havebeen recovered from production. "Proved developed reserves" means reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methodsor in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment andinfrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. "Proved reserves" or “Proved oil and natural gas reserves” means those quantities of oil and natural gas, which, by analysis of geoscience and engineeringdata, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economicconditions, operating methods, and governmental regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicatesthat renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract thehydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. "Royalty" means an interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leasedacreage (or of the proceeds of the sale thereof) but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on theleased acreage. "Severance tax" means an amount of tax, surcharge or levy recovered by governmental agencies from the gross proceeds of oil and natural gas sales.Severance tax may be determined as a percentage of proceeds or as a specific amount per volumetric unit of sales. Severance tax is usually withheld from the grossproceeds of oil and natural gas sales by the first purchaser (e.g., pipeline or refinery) of production. "Standardized measure of discounted future net cash flows" (also referred to as "standardized measure") means the pretax present value of estimatedfuture net revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated production andfuture development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expensessuch as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. "Undeveloped acreage" means lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercialquantities of oil and natural gas regardless of whether such acreage contains proved reserves. "Unitization" means the process of combining mineral interests or leases thereof in separate tracts of land into a single entity for administrative, operatingor ownership purposes. Unitization is sometimes called "pooling" or "communitization" and may be voluntary or involuntary. "Working interest" (also referred to as an "operating interest") means a real property interest entitling the owner to receive a specified percentage of theproceeds of the sale of oil and natural gas production or a percentage of the production but requiring the owner of the working interest to bear the cost to explorefor, develop and produce such oil and natural gas. A working interest owner who owns a portion of the working interest may participate either as operator or byvoting his percentage interest to approve or disapprove the appointment of an operator and certain activities in connection with the development and operation ofa property. 33 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on itsbehalf by the undersigned, thereunto duly authorized. DORCHESTER MINERALS, L.P. By:Dorchester Minerals Management LP, its general partner By:Dorchester Minerals Management GP LLC, its general partner By:/s/ William Casey McManemin William Casey McManemin Chief Executive Officer Date: February 25, 2016 Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of theRegistrant and in the capacities and on the dates indicated. /s/ William Casey McManemin /s/ H.C. Allen, Jr. William Casey McManemin H.C. Allen, Jr. Chief Executive Officer and Manager Manager (Principal Executive Officer) Date: February 25, 2016 Date: February 25, 2016 /s/ James E. Raley /s/ Buford P. Berry James E. Raley Buford P. Berry Vice Chairman and Manager Manager Date: February 25, 2016 Date: February 25, 2016 /s/ Martha Ann Peak Rochelle /s/ C. W. Russell Martha Ann Peak Rochelle C. W. Russell Manager Manager Date: February 25, 2016 Date: February 25, 2016 /s/ Ronald P. Trout /s/ Robert C. Vaughn Ronald P. Trout Robert C. Vaughn Manager Manager Date: February 25, 2016 Date: February 25, 2016 34 DORCHESTER MINERALS, L.P.(A Delaware Limited Partnership) INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Dorchester Minerals, L.P. Reports of Independent Registered Public Accounting FirmF-2 Consolidated Balance Sheets as of December 31, 2015 and 2014F-4 Consolidated Income Statements for each of the Years Ended December 31, 2015, 2014 and 2013F-5 Consolidated Statements of Cash Flows for each of the Years Ended December 31, 2015, 2014 and 2013F-6 Consolidated Statements of Changes in Partnership Capital for each of the Years Ended December 31, 2015, 2014 and 2013F-7 Notes to Consolidated Financial StatementsF-8 Supplemental Oil and Natural Gas Data (Unaudited)F-12 Supplemental Quarterly Data (Unaudited)F-14 F-1 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM General Partner and UnitholdersDorchester Minerals, L.P. We have audited the internal control over financial reporting of Dorchester Minerals, L.P. (a Delaware Limited Partnership) and subsidiaries (collectively, the“Partnership”) as of December 31, 2015, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee ofSponsoring Organizations of the Treadway Commission (COSO). The Partnership’s management is responsible for maintaining effective internal control overfinancial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s AnnualReport on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reportingbased on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that weplan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluatingthe design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in thecircumstances. We believe that our audit provides a reasonable basis for our opinion. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and thepreparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financialreporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect thetransactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation offinancial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only inaccordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection ofunauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation ofeffectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance withthe policies or procedures may deteriorate. In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteriaestablished in the 2013 Internal Control—Integrated Framework issued by COSO. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statementsof the Partnership as of and for the year ended December 31, 2015 and our report dated February 25, 2016 expressed an unqualified opinion on those financialstatements. /s/ GRANT THORNTON LLP Dallas, TexasFebruary 25, 2016 F-2 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMGeneral Partner and UnitholdersDorchester Minerals, L.P. We have audited the accompanying consolidated balance sheets of Dorchester Minerals, L.P. (a Delaware Limited Partnership) and subsidiaries (collectively, the“Partnership”) as of December 31, 2015 and 2014, and the related consolidated income statements, statements of cash flows, and statements of changes inpartnership capital for each of the three years in the period ended December 31, 2015. These financial statements are the responsibility of the Partnership’smanagement. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that weplan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, ona test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used andsignificant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basisfor our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Dorchester Minerals, L.P. andsubsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31,2015 in conformity with accounting principles generally accepted in the United States of America. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership’s internal control overfinancial reporting as of December 31, 2015, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee ofSponsoring Organizations of the Treadway Commission (COSO), and our report dated February 25, 2016 expressed an unqualified opinion. /s/ GRANT THORNTON LLP Dallas, TexasFebruary 25, 2016 F-3 DORCHESTER MINERALS, L.P.(A Delaware Limited Partnership) CONSOLIDATED BALANCE SHEETSDecember 31, 2015 and 2014(Dollars in Thousands)  2015 2014 ASSETS Current assets: Cash and cash equivalents $7,136 $15,912 Trade and other receivables 2,639 4,761 Net profits interests receivable—related party 3,005 5,792 Total current assets 12,780 26,465 Other non-current assets 19 19 Property and leasehold improvements—at cost: Oil and natural gas properties (full cost method) 340,563 340,703 Accumulated full cost depletion (279,710) (269,690)Total 60,853 71,013 Leasehold improvements 625 512 Accumulated amortization (548) (500)Total 77 12 Total assets $73,729 $97,509 LIABILITIES AND PARTNERSHIP CAPITAL Current Liabilities: Accounts payable and other current liabilities $481 $975 Current portion of deferred rent incentive 54 10 Total current liabilities 535 985 Deferred rent incentive less current portion 23 -- Total liabilities 558 985 Commitments and contingencies (Note 4) Partnership capital: General partner 1,996 2,692 Unitholders 71,175 93,832 Total partnership capital 73,171 96,524 Total liabilities and partnership capital $73,729 $97,509 The accompanying notes are an integral part of these consolidated financial statements F-4 DORCHESTER MINERALS, L.P.(A Delaware Limited Partnership) CONSOLIDATED INCOME STATEMENTSFor each of the Years Ended December 31, 2015, 2014 and 2013 (Dollars in Thousands, except per unit amounts)  2015 2014 2013 Operating revenues: Royalties $30,654 $54,513 $53,077 Net profits interests 995 8,870 10,348 Lease bonus 53 1,590 2,319 Other 161 197 125 Total operating revenues 31,863 65,170 65,869 Costs and expenses Production taxes 1,336 2,548 2,475 Operating expenses 2,244 2,908 2,655 Depreciation, depletion and amortization 10,068 10,050 13,143 General and administrative expenses 4,967 5,137 4,196 Total costs and expenses 18,615 20,643 22,469 Operating income 13,248 44,527 43,400 Other income, net 7 712 176 Net income $13,255 $45,239 $43,576 Allocation of net income: General partner $513 $1,593 $1,501 Unitholders $12,742 $43,646 $42,075 Net income per common unit (basic and diluted) $0.42 $1.42 $1.37 Weighted average common units outstanding (000's) 30,675 30,675 30,675  The accompanying notes are an integral part of these consolidated financial statements F-5 DORCHESTER MINERALS, L.P.(A Delaware Limited Partnership) CONSOLIDATED STATEMENTS OF CASH FLOWSFor each of the Years Ended December 31, 2015, 2014 and 2013(Dollars in Thousands)  2015 2014 2013 Cash flows from operating activities: Net income $13,255 $45,239 $43,576 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 10,068 10,050 13,143 Amortization of deferred rent incentive (46) (40) (39)Changes in operating assets and liabilities: Trade and other receivables 2,122 1,747 (702)Net profits interests receivable—related party 2,787 600 (43)Accounts payable and other current liabilities (494) 64 463 Net cash provided by operating activities 27,692 57,660 56,398 Cash flows provided by investing activities: Proceeds from sale of NPI reserves 140 3,616 -- Cash flows used in financing activities: Distributions paid to partners (36,608) (60,539) (55,015)(Decrease) increase in cash and cash equivalents (8,776) 737 1,383 Cash and cash equivalents at beginning of year 15,912 15,175 13,792 Cash and cash equivalents at end of year $7,136 $15,912 $15,175 The accompanying notes are an integral part of these consolidated financial statements F-6 DORCHESTER MINERALS, L.P.(A Delaware Limited Partnership) CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERSHIP CAPITALFor each of the Years Ended December 31, 2015, 2014 and 2013(Dollars in Thousands) Year GeneralPartner Unitholders Total UnitholderUnits 2013                Balance at January 1, 2013 $3,625 $119,638 $123,263 30,675,431 Net income 1,501 42,075 43,576 Distributions ($1.732311 per Unit) (1,876) (53,139) (55,015) Balance at December 31, 2013 3,250 108,574 111,824 30,675,431 2014                Net income 1,593 43,646 45,239 Distributions ($1.903398 per Unit) (2,151) (58,388) (60,539) Balance at December 31, 2014 2,692 93,832 96,524 30,675,431 2015                Net income 513 12,742 13,255 Distributions ($1.153997 per Unit) (1,209) (35,399) (36,608) Balance at December 31, 2015 $1,996 $71,175 $73,171 30,675,431 The accompanying notes are an integral part of these consolidated financial statements F-7 DORCHESTER MINERALS, L.P.(A Delaware Limited Partnership) NOTES TO CONSOLIDATED FINANCIAL STATEMENTSDecember 31, 2015, 2014, and 2013 1.General and Summary of Significant Accounting Policies Nature of Operations — In these Notes, the term “Partnership,” as well as the terms “us,” “our,” “we,” and “its” are sometimes used as abbreviatedreferences to Dorchester Minerals, L.P. itself or Dorchester Minerals, L.P. and its related entities. Our Partnership is a Dallas, Texas based owner of producingand nonproducing natural gas and crude oil royalty, net profits, and leasehold interests in 574 counties and 25 states. We are a publicly traded Delaware limitedpartnership that was formed in December 2001, and commenced operations on January 31, 2003. Basis of Presentation — The consolidated financial statements herein have been prepared in accordance with accounting principles generally accepted in theUnited States (“U.S. GAAP”). Basic and Diluted Earnings Per Unit — Per-unit information is calculated by dividing the net income applicable to holders of our Partnership’s common unitsby the weighted average number of units outstanding. The Partnership has no potentially dilutive securities and, consequently, basic and dilutive net income perunit 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 havebeen eliminated in consolidation. Estimates — The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requiresmanagement to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at thedate of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. For example, estimates of uncollectedrevenues and unpaid expenses from royalties and net profits interests in properties operated by non-affiliated entities are particularly subjective due to our inabilityto 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 subjectivejudgments. Estimates of reserves are forecasts based on engineering and geological analyses. Different reserve engineers could reach different conclusions as toestimated quantities of oil and natural gas reserves based on the same information. The passage of time provides more qualitative and quantitative informationregarding reserve estimates, and revisions are made to prior estimates based on updated information. However, there can be no assurance that more significantrevisions will not be necessary in the future. Significant downward revisions could result in an impairment representing a non-cash charge to income. In additionto 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 discussionunder 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 ownsall of the partnership interests in Dorchester Minerals Operating LP, the operating partnership. See Note 3 — Related Party Transactions. The general partner isallocated 4% and 1% of our Royalty Properties’ revenues and Net Profits Interest (or “NPI”) revenues, respectively. Cash and Cash Equivalents— Our principal banking relationships are with major financial institutions. Cash balances in these accounts may, at times, exceedfederally 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 cashequivalents. Short term investments with an original maturity of three months or less are considered to be cash equivalents and are carried at cost, whichapproximates fair value. Concentration of Credit Risks— Our Partnership, as a royalty owner, has no control over the volumes or method of sale of oil and natural gas produced andsold 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 resultsof our operations. Fair Value of Financial Instruments— The carrying amount of cash and cash equivalents, trade receivables and payables approximates fair value because ofthe short maturity of those instruments. These estimated fair values may not be representative of actual values of the financial instruments that could have beenrealized 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 receivableand NPI payments receivable, respectively. Most payments are received two to four months after production date. No allowance for doubtful accounts isdeemed necessary based upon our lack of historical write offs and review of current receivables. F-8 DORCHESTER MINERALS, L.P.(A Delaware Limited Partnership) NOTES TO CONSOLIDATED FINANCIAL STATEMENTSDecember 31, 2015, 2014, and 2013 Oil and Natural Gas Properties — 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. Thesecapitalized 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 oiland 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 unprovedproperties, including nonproducing royalty, mineral and leasehold interests. The full cost ceiling is evaluated at the end of each quarter and when eventsindicate possible impairment. There have been no impairments for the years 2015, 2014, and 2013. While the quantities of proved reserves require substantial judgment, the associated prices of oil and natural gas reserves that are included in the discountedpresent value of our reserves are objectively determined. The ceiling test calculation requires use of the unweighted arithmetic average of the first day of the monthprice 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 constantfor 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 havehistorically 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 arerecognized upon the disposition of oil and natural gas properties involving a significant portion (greater than 25%) of our Partnership’s reserves. Proceeds fromother dispositions of oil and natural gas properties are credited to the full cost pool. See Note 6 below for property sales. Leasehold Improvements — Leasehold improvements include $113,000 received in 2015 as non-cash incentives in our office space lease and is offset inliabilities as deferred rent. Leasehold improvements are amortized over the shorter of their estimated useful lives or the related life of the lease. For leases withrenewal periods at the Partnership’s option, we have used the original lease term, excluding renewal option periods to determine useful life. Deferred rent is beingamortized 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 no 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 inthe marketplace and can fluctuate considerably. As a royalty owner, we have extremely limited involvement and operational control over the volumes andmethod 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’ statementaccompanying the revenue check. Since the revenue checks are generally received two to four months after the production month, the Partnership accrues forrevenue earned but not received by estimating production volumes and product prices. 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 individualunitholders. Depletion of oil and natural gas properties is an expense allowable to each individual partner, and the depletion expense as reported on the consolidatedfinancial 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 0.95% on gross revenues less certain deductions, as specifically setforth in the Texas margin tax statute. The Texas margin tax applies to corporations and limited liability companies, general and limited partnerships (unlessotherwise exempt), limited liability partnerships, trusts (unless otherwise exempt), business trusts, business associations, professional associations, joint stockcompanies, holding companies, joint ventures and certain other business entities having limited liability protection. F-9 DORCHESTER MINERALS, L.P.(A Delaware Limited Partnership) NOTES TO CONSOLIDATED FINANCIAL STATEMENTSDecember 31, 2015, 2014, and 2013 Limited partnerships that receive at least 90% of their gross income from designated passive sources, including royalties from mineral properties and othernon-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 theTexas margin tax as “passive entities.” We believe our Partnership meets the requirements for being considered a “passive entity” for Texas margin tax purposesand, 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 ataxable entity under the Texas margin tax would generally be required to include its portion of Partnership revenues in its own Texas margin tax computation. TheTexas 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. 2.Acquisition for Units We have effective shelf registration statements on Form S-4 registering an aggregate of 8,000,000 common units that may be offered and issued by thePartnership from time to time in connection with asset acquisitions or other business combination transactions. As of December 31, 2015, all units remainavailable under the shelf registration statement. 3.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 otherproperties underlying our NPIs, and provides day-to-day operational and administrative services to us and the general partner. In accordance with our partnershipagreement, we reimburse the general partner for certain allocable general and administrative costs, including rent, salaries, employee equity and benefit plans.These types of reimbursements are limited to 5% of distributions, plus certain costs previously paid. All such costs have been below the 5% limit amount for theyears ended December 31, 2015, 2014, and 2013. Additionally, certain reimbursable direct costs such as professional and regulatory fees and ad valorem andseverance taxes are not limited. Significant activity between the partnership and the operating partnership consists of the following:   In Thousands From/To Operating Partnership 201 5 201 4 2013 Net Profits Interests Payments Receivable or Accrued $3,005 $5,792 $6,515 General & Administrative Amounts Payable $125 $304 $118 Total General & Administrative Expense $3,466 $3,348 $2,349 All Net Profits Interests income on the financial statements is from the operating partnership. 4.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 operatingresults. Operating Leases— We have entered into a non-cancelable operating lease agreement in the ordinary course of our business activities. This lease wasoriginally extended on January 28, 2015, for a term of 25 months beginning on May 1, 2015, with an extension option of one (1) year, which was subsequentlysigned on February 17, 2016. The lease is for our office space at 3838 Oak Lawn Avenue, Suite 300, Dallas, Texas, and now expires in 2018. Under the January28, 2015 lease and February 17, 2016 extension, monthly rental payments range from $26,000-$27,000 and the Partnership received a tenant improvementallowance of $113,000. The Partnership recognizes a deferred rent liability for the rent escalations when the amount of straight-line rent exceeds the leasepayments, and reduces the deferred rent liability when the lease payments exceed the straight-line rent expense. For the tenant improvement allowance, thePartnership recorded a deferred rent liability and we amortize the deferred rent over the lease term as a reduction to rent expense. F-10(1)(1) DORCHESTER MINERALS, L.P.(A Delaware Limited Partnership) NOTES TO CONSOLIDATED FINANCIAL STATEMENTSDecember 31, 2015, 2014, and 2013 Rental expense related to the lease, including operating expenses and consumption of electricity, was $231,000, $268,000, and $223,000 for the years endedDecember 31, 2015, 2014 and 2013, respectively. Minimum rental commitments under the terms of our operating lease are as follows: Years Ended December 31, MinimumPayments 2016 $318,000 2017 $323,000 2018 $136,000 Total $777,000 5.Distribution To Holders Of Common Units Unitholder cash distributions per common unit have been: Per Unit Amount   2015  2014  2013 First Quarter $0.306553 $0.496172 $0.448209 Second Quarter $0.167430 $0.490861 $0.395583 Third Quarter $0.194234 $0.447805 $0.455287 Fourth Quarter $0.199076 $0.485780 $0.468560 Each of the foregoing distributions were paid on 30,675,431 units. Fourth quarter distributions are paid in February of the following calendar year tounitholders of record in January or February of such following year. The partnership agreement requires the next cash distribution to be paid by May 15, 2016. 6.Property Sale On September 24, 2014, the Partnership and DMOLP closed a transaction selling Kansas working interests in the Hugoton NPI to Linn Energy. The salewas effective June 1, with an initial purchase price of $3,800,000. In accordance with full cost accounting for oil and gas properties, the Partnership’s share ofproceeds less costs of sale of approximately $3,500,000 has been credited to the full cost pool as the sale did not represent a significant portion of thePartnership’s reserves. There were no significant sales during 2015. 7.New Accounting Pronouncements In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (ASU 2014-09), which supersedesnearly all existing revenue recognition guidance under U.S. GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods orservices are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU2014-09 defines a five step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognitionprocess 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 transitionmethods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practicalexpedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includesadditional footnote disclosures). We are currently evaluating the impact of our pending adoption of ASU 2014-09 on our consolidated financial statements andhave not yet determined the method by which we will adopt the standard in 2018. F-11  DORCHESTER MINERALS, L.P.(A Delaware Limited Partnership) NOTES TO CONSOLIDATED FINANCIAL STATEMENTSDecember 31, 2015, 2014, and 2013 Oil and Natural Gas Reserve and Standardized Measure The NPIs represent net profits overriding royalty interests in various properties owned by the operating partnership. The Royalty Properties consist ofproducing and nonproducing mineral, royalty, overriding royalty, net profits, and leasehold interests located in 574 counties and parishes in 25 states. Amounts setforth herein attributable to the NPIs reflect our 96.97% net share. Although new activity has occurred on certain of the Royalty Properties, based on engineeringstudies available to date, no events have occurred since December 31, 2015 that would have a material effect on our estimated proved developed reserves. In accordance with FASB ASC 932 and Securities and Exchange Commission rules and regulations, the following information is presented with regard to theRoyalty Properties and NPIs oil and natural gas reserves, all of which are proved, developed and located in the United States. These rules require inclusion as asupplement to the basic financial statements a standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves. Thestandardized measure, in management's opinion, should be examined with caution. The basis for these disclosures are petroleum engineers’ reserve studies whichcontain imprecise estimates of quantities and rates of production of reserves. Revision of prior year estimates can have a significant impact on the results.Changes in production costs may result in significant revisions to previous estimates of proved reserves and their future value. Therefore, the standardizedmeasure is not necessarily a best estimate of the fair value of oil and natural gas properties or of future net cash flows. The following summaries of changes in reserves and standardized measure of discounted future net cash flows were prepared from estimates of provedreserves. The production volumes and reserve volumes included for properties formerly owned by Dorchester Hugoton are wellhead volumes, which differ fromsales volumes shown in “Item 7. — Management's Discussion and Analysis of Financial Condition and Results of Operations” because of fuel, shrinkage andpipeline loss. The Standardized Measure of Discounted Future Net Cash Flows reflects adjustments for such fuel, shrinkage and pipeline loss.   Oil (mbbls)  Natural Gas (mmcf)   201 5  2014  2013  201 5  2014  2013 Estimated quantity, beginning ofyear. 5,746 5,087 3,647 55,701 60,473 64,141 Revisions in previous estimates 904 1,380 1,959 416 4,910 5,860 Sales of reserves in place — — — — (2,426) — Production (972) (721) (519) (6,747) (7,256) (9,528)Estimated quantity, end of year 5,678 5,746 5,087 49,370 55,701 60,473 Changes in oil reserves for the years ended December 31, 2015, 2014 and 2013, includes upward revisions of 904 mmbls, 1,380 mmbls and 1,959mbbls, respectively, predominately due to ongoing development on our Bakken properties and well performance exceeding previous projections in variousareas. Changes in natural gas reserves for the years ended December 31, 2015, 2014 and 2013, includes upward revisions of 416 mmcf, 4,910 mmcf and 5,860mmcf, respectively, predominately due to well performance exceeding previous projections in various areas. Effective for the January 1, 2014 reserve reports, product volumes are included in oil quantities, not natural gas quantities. Such volumes were 997 mboeor 5,981 mmcfe at January 1, 2013, 644 mboe or 3,864 mmcfe at January 1, 2014, and 671 mboe or 4,024 mmcfe at January 1, 2015. The Partnership and DMOLP sold Kansas working interests in the Hugoton NPI. F-12(1)(2)(1) (2 )  DORCHESTER MINERALS, L.P.(A Delaware Limited Partnership) NOTES TO CONSOLIDATED FINANCIAL STATEMENTSDecember 31, 2015, 2014, and 2013 Standardized Measure of Discounted Future Net Cash Flows (Dollars in Thousands Except Where Noted) 2015 2014 2013 Future estimated gross revenues $275,883 $603,283 $557,492 Future estimated production costs (14,888) (28,125) (31,335)Future estimated net revenues 260,995 575,158 526,157 10% annual discount for estimated timing of cash flows (124,711) (273,732) (254,869)Standardized measure of discounted future estimated net cash flows $136,284 $301,426 $271,288 Sales of oil and natural gas produced, net of production costs $(28,069) $(57,926) $(58,295)Net changes in prices and production costs (174,054) 16,605 35,215 Revisions of previous quantity estimates 14,906 49,488 60,453 Accretion of discount 30,143 27,129 21,169 Sale of reserves in place — (878) — Change in production rate and other (8,068) (4,280) 1,052 Net change in standardized measure of discounted future estimated net cash flows $(165,142) $30,138 $59,594 Depletion of oil and natural gas properties (dollars per mcfe) $0.80 $0.86 $1.04 Average oil price per barrel $41.54 $82.49 $85.95 Average natural gas price per mcf $2.10 $4.14 $3.36 (1)Includes Royalty and NPI prices combined by volumetric proportions.(2)Includes oil and natural gas liquids prices combined by volumetric proportions. F-13(1) (2)(1) DORCHESTER MINERALS, L.P.(A Delaware Limited Partnership) NOTES TO CONSOLIDATED FINANCIAL STATEMENTSDecember 31, 2015, 2014, and 2013  Quarterly financial data for the last two years (in thousands except per unit data) is summarized as follows:   201 5 Quarter Ended 2014 Quarter Ended   March 31 June 30 Sept. 30 Dec. 31 March 31 June 30 Sept. 30 Dec. 31 Total operating revenues $8,804 $8,280 $7,387 $7,392 $17,339 $17,973 $15,716 $14,142 Net income $4,031 $3,816 $2,683 $2,725 $12,897 $12,669 $10,969 $8,704 Net income per Unit (basic anddiluted) $0.13 $0.12 $0.08 $0.09 $0.41 $0.39 $0.35 $0 .27 Weighted average common unitsoutstanding 30,675 30,675 30,675 30,675 30,675 30,675 30,675 30,675 F-14 INDEX TO EXHIBITS NumberDescription3.1Certificate of Limited Partnership of Dorchester Minerals, L.P. (incorporated by reference to Exhibit 3.1 to Dorchester Minerals’ RegistrationStatement on Form S-4, Registration Number 333-88282)3.2Amended and Restated Agreement of Limited Partnership of Dorchester Minerals, L.P. (incorporated by reference to Exhibit 3.2 to DorchesterMinerals’ Annual Report on Form 10-K for the year ended December 31, 2002)3.3Certificate 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)3.4Amended and Restated Agreement of Limited Partnership of Dorchester Minerals Management LP (incorporated by reference to Exhibit 3.4 toDorchester Minerals’ Annual Report on Form 10-K for the year ended December 31, 2002)3.5Certificate 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)3.6Amended and Restated Limited Liability Company Agreement of Dorchester Minerals Management GP LLC (incorporated by reference toExhibit 3.6 to Dorchester Minerals’ Annual Report on Form 10-K for the year ended December 31, 2002)3.7Certificate 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)3.8Limited Liability Company Agreement of Dorchester Minerals Operating GP LLC (incorporated by reference to Exhibit 3.11 to DorchesterMinerals’ Registration Statement on Form S-4, Registration Number 333-88282)3.9Certificate 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)3.10Amended and Restated Agreement of Limited Partnership of Dorchester Minerals Operating LP (incorporated by reference to Exhibit 3.10 toDorchester Minerals’ Annual Report on Form 10-K for the year ended December 31, 2002)3.11Certificate of Limited Partnership of Dorchester Minerals Oklahoma LP (incorporated by reference to Exhibit 3.11 to DorchesterMinerals’ Annual Report on Form 10-K for the year ended December 31, 2002)3.12Agreement of Limited Partnership of Dorchester Minerals Oklahoma LP (incorporated by reference to Exhibit 3.12 to DorchesterMinerals’ Annual Report on Form 10-K for the year ended December 31, 2002)3.13Certificate of Incorporation of Dorchester Minerals Oklahoma GP, Inc. (incorporated by reference to Exhibit 3.13 to Dorchester Minerals’ AnnualReport on Form 10-K for the year ended December 31, 2002)3.14Bylaws of Dorchester Minerals Oklahoma GP, Inc. (incorporated by reference to Exhibit 3.14 to Dorchester Minerals’ Annual Report onForm 10-K for the year ended December 31, 2002)10.1Amended and Restated Business Opportunities Agreement dated as of December 13, 2001 by and between the Registrant, the General Partner,Dorchester Minerals Management GP LLC, SAM Partners, Ltd., Vaughn Petroleum, Ltd., Smith Allen Oil & Gas, Inc., P.A. Peak, Inc., JamesE. Raley, Inc., and certain other parties (incorporated by reference to Exhibit 10.1 to Dorchester Minerals’ Annual Report on Form 10-K for theyear ended December 31, 2002)10.2Transfer Restriction Agreement (incorporated by reference to Exhibit 10.2 to Dorchester Minerals’ Annual Report on Form 10-K for the yearended December 31, 2002)10.3Registration Rights Agreement (incorporated by reference to Exhibit 10.3 to Dorchester Minerals’ Annual Report on Form 10-K for the yearended December 31, 2002)10.4Lock-Up Agreement by William Casey McManemin (incorporated by reference to Exhibit 10.4 to Dorchester Minerals’ Annual Report onForm 10-K for the year ended December 31, 2002)10.5Form of Indemnity Agreement (incorporated by reference to Exhibit 10.1 to Dorchester Minerals’ Quarterly Report on Form 10-Q for thequarter ended June 30, 2004)10.6Dorchester Minerals Operating LP Equity Incentive Program (incorporated by reference to Annex A to Dorchester Minerals’ Proxy Statement onSchedule 14A filed with the SEC on March 16, 2015.21.1*Subsidiaries of the Registrant23.1*Consent of Grant Thornton LLP23.2*Consent of Calhoun, Blair & Associates23.3*Consent of LaRoche Petroleum Consultants, Ltd.31.1*Certification of Chief Executive Officer of our Partnership pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 E-1 NumberDescription 31.2*Certification of Chief Financial Officer of our Partnership pursuant to Rule 13a-14(a) of the Securities Exchange Act of 193432.1**Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Sec. 135099.1*Report of Calhoun, Blair & Associates 99.2*Report of LaRoche Petroleum Consultants, Ltd. 101.INS**XBRL Instance Document 101.SCH**XBRL Taxonomy Extension Schema Document 101.CAL**XBRL Taxonomy Extension Calculation Linkbase Document 101.DEF**XBRL Taxonomy Extension Definition Document 101.LAB**XBRL Taxonomy Extension Label Linkbase Document 101.PRE**XBRL Taxonomy Extension Presentation Linkbase Document * Filed herewith** Furnished herewith E-2Exhibit 21.1 Subsidiaries of Registrant 1.Dorchester Minerals Oklahoma LP, an Oklahoma limited partnership2.Dorchester Minerals Oklahoma GP, Inc., an Oklahoma corporation3.Maecenas Minerals LLP, a Texas limited liability partnership4.Dorchester-Maecenas GP LLC, a Texas limited liability company Exhibit 23.1 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We have issued our reports dated February 25, 2016, with respect to the consolidated financial statements and internal control over financial reporting included inthe Annual Report of Dorchester Minerals, L.P. on Form 10-K for the year ended December 31, 2015. We consent to the incorporation by reference of said reportsin the Registration Statements of Dorchester Minerals, L.P. on Forms S-4 (File No. 333-124544 and File No. 333-202918). /s/ GRANT THORNTON LLP Dallas, TexasFebruary 25, 2016 Exhibit 23.2 CALHOUN, BLAIR & ASSOCIATESPETROLEUM CONSULTANTS4625 GREENVILLE AVENUE, SUITE 102DALLAS, TEXAS 75206214-522-4925FAX 214-346-0310RGBLAIR@SWBELL.NET January 28, 2016 Dorchester Minerals, L.P.3838 Oak Lawn Avenue, Suite 300Dallas, Texas 75219-4541 Gentlemen: Calhoun, Blair & Associates does hereby consent to the incorporation by reference in the Registration Statement on Form S-4 (No. 333-124544) ofDorchester Minerals, L.P. of our estimated reserves included in this Annual Report on Form 10-K including, without limitation, Exhibit 99.1, and to all referencesto our firm included in this Annual Report. /s/ Robert G. Blair, P.E. Calhoun, Blair & Associates Licensed Professional Engineer State of Texas #68057  Exhibit 31.1 CERTIFICATIONS I, William Casey McManemin, certify that: 1.I have reviewed this annual report on Form 10-K of Dorchester Minerals, L.P.; 2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4.The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in ExchangeAct Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for theregistrant and have: a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within thoseentities, particularly during the period in which this report is being prepared; b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements forexternal purposes in accordance with generally accepted accounting principles; c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recentfiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 5.The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonablylikely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controlover financial reporting. /s/ William Casey McManemin William Casey McManemin Date: February 25, 2016 Chief Executive Officer of Dorchester Minerals Management GP LLC The General Partner of Dorchester Minerals Management LP The General Partner of Dorchester Minerals, L. P. Exhibit 31.2 I, Leslie Moriyama, certify that: 1.I have reviewed this annual report on Form 10-K of Dorchester Minerals, L.P.; 2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4.The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in ExchangeAct Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for theregistrant and have: a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within thoseentities, particularly during the period in which this report is being prepared; b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements forexternal purposes in accordance with generally accepted accounting principles; c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recentfiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 5.The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonablylikely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controlover financial reporting. /s/ Leslie Moriyama Leslie Moriyama Date: February 25, 2016 Chief Financial Officer of Dorchester Minerals Management GP LLC, The General Partner of Dorchester Minerals Management LP The General Partner of Dorchester Minerals, L.P. Exhibit 32.1 CERTIFICATION PURSUANT TOSECTION 906 OF THE SARBANES-OXLEY ACT OF 2002(18 U.S.C. SECTION 1350) In connection with the accompanying Annual Report of Dorchester Minerals, L.P., (the "Partnership") on Form 10-K for the period ended December 31, 2015(the "Report”), each of the undersigned officers of Dorchester Minerals Management GP LLC, General Partner of Dorchester Minerals Management LP, GeneralPartner of the Partnership, hereby certifies that: (1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and (2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership. /s/ William Casey McManemin William Casey McManemin Date: February 25, 2016 Chief Executive Officer /s/ Leslie Moriyama Leslie Moriyama Date: February 25, 2016 Chief Financial Officer Exhibit 99.1 CALHOUN, BLAIR & ASSOCIATES January 27, 2016 Dorchester Minerals Operating GP LLCGeneral Partner3838 Oak Lawn Avenue, Suite 300Dallas, Texas 75219-4541 Gentlemen: In accordance with your instructions we have prepared estimates of oil and gas reserves from certain leasehold and royalty interests owned by DorchesterMinerals Operating LP, which consists of properties grouped by Hugoton NPI, Republic NPI, Spinnaker NPI, Minerals NPI and Bradley NPI. We have projectedour estimates of future oil and gas production annually, as of December 31, 2015, for these properties. This report includes 100% of the oil and gas reserves ownedby Dorchester Minerals Operating, LP, all of which are located in the contiguous United States. This report was prepared to provide Dorchester Minerals OperatingLP with Securities and Exchange Commission compliant reserve estimates. Information necessary for the preparation of these estimates was obtained from records furnished by Dorchester Minerals Operating LP, from records on filewith the state regulatory bodies, and from our own files . No special tests were obtained to assist in the preparation of this report. For the purpose of this report, theindividual well tests and production information as reported in the records on file with the state regulatory bodies were accepted as represented, together with allother factual data provided by Dorchester Minerals Operating LP, including the extent and character of the interest appraised. The following table contains the estimated net reserves and revenues attributable to the property groups as of December 31, 2015. Hugoton NPIRepublic NPISpin n aker NPINet Oil Reserves, BBL021,110110Net Gas Reserves, MMCF21,777.39069.89032.580Net Products Reserves, BBL02,340570Net Oil and Gas Revenue, $44,016,6401,103,010101,860Net Operating Expense, $37,562,120353,70032,010Net Taxes, $3,170,660114,1706,670Net Capital Costs, $000Net Income, $3,283,870635,14063,180Net Present Worth at 10%, $1,720,640454,84040,810  CALHOUN, BLAIR & ASSOCIATES Minerals NPIBradley NPITotal NPINet Oil Reserves, BBL1,003,88014,9101,040,010Net Gas Reserves, MMCF4,621.22055.79026,556.870Net Products Reserves, BBL36,92025040,080Net Oil and Gas Revenue, $52,209,250858,44098,289,200Net Lease Operating Expense, $19,036,700254,54057,239,060Net Taxes, $5,048,35069,9908,409,830Net Capital Costs, $000Net Income, $28,124,210533,91032,640,310Net Present Worth at 10%, $19,910,610398,76022,525,670 All estimated reserves in this report are considered as proved developed producing. Proved developed producing reserves are those proved to a high degreeof certainty by reason of actual completion or successful testing. Estimates of proved reserves were made using standard geological and engineering methodsaccepted by the petroleum industry. The method, or combination of methods, utilized was tempered by experience in the area, state of development, quality andextent of the basic data and production history. These methods and procedures were appropriate for the purpose served by this report and we have used all methodsnecessary under the circumstances to prepare this report. When the information was available and the method was applicable, oil and gas reserves in this report were estimated by the extrapolation of historicaltrends of pressure decline as a function of cumulative production, oil and gas production decline as a function of time and oil and gas production decline as afunction of cumulative production. For certain wells having a limited production history, reserves were estimated by analogy with nearby similar wells in the sameformation. All gas volumes are raw wellhead gas volumes expressed at 60 degrees Fahrenheit and at a standard pressure base of 14.65 pounds per square inchabsolute. Reserves in this report are expressed as gross and net oil and gas production. Net oil and gas production represents those reserves net to the appraisedinterest after deducting all leasehold and royalty interests owned by others. Values of reserves are expressed in terms of net operating revenues, cash flow beforetaxes, and present worth. Net operating revenue is revenue, which would accrue to the appraised interests from the production and sale of the estimated netreserves. Cash flow before taxes is obtained by deducting severance and ad valorem taxes, net operating expenses and capital costs from net operating revenue. Oiland gas prices, net operating expenses and future capital costs were furnished by Dorchester Minerals Operating LP. Present worth is defined as the future cashflow before taxes discounted at the rate of ten (10.00) percent per year compounded annually. For the purpose of this report no estimate was made of salvage valuefor the existing lease and well equipment, or costs involved in abandonment of the wells.  CALHOUN, BLAIR & ASSOCIATES Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, the reserves included in this report are estimates onlyand should not be construed as being exact quantities. The revenues from such reserves and the actual costs related thereto could be more or less than the estimatedamounts. The scope of this investigation did not include an environmental study of these properties, nor was an on-site field inspection conducted. For the purposeof this report, it was necessary to assume that these properties are in compliance with existing government regulations. Because of governmental policies anduncertainties of supply and demand, the prices actually received for the reserves included in this report, and the costs incurred in recovering such reserves, mayvary from price and cost assumptions in this report. In any case, estimates of reserves may increase or decrease as a result of future operation and as moreproduction history becomes available. There are no known pending regulations that would affect the ability of Dorchester Minerals Operating LP to recover theestimated reserves in this report. The oil and gas prices included in this report were provided by Dorchester Minerals Operating LP and were adjusted for BTU, fuel and line losses as well asfor local markets. The Hugoton prices were determined as an unweighted arithmetic average of the Panhandle Eastern (Texas and Oklahoma) first day of the monthprice during the twelve month period of 2015. The benchmark gas price for the Hugoton operated properties was $2.27 per MMBTU after adjustments for fuel andshrink. The benchmark prices for the other NPI properties were determined as an unweighted arithmetic average of the NYMEX Henry Hub and West TexasIntermediate-Cushing first day of the month price during the twelve month period of 2015. The benchmark oil, gas and plant products prices for the NPI propertieswere $50.28 per barrel, $2.59 per MMBTU and $19.19 per barrel respectively. The overall weighted average prices were $40.97 per barrel, $2.07 per MMBTU and$19.19 per barrel. Calhoun, Blair & Associates have not examined the title to these properties, nor has the actual degree or type of interest owned been independentlyconfirmed. We are independent petroleum engineers; we do not own an interest in these properties and are not employed on a contingent basis. Basic fieldperformance data together with our engineering work sheets are maintained on file in our office and are available for review. Calhoun Blair & Associates have metthe requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the “Standards Pertaining to the Estimating and Auditing of Oiland Gas Reserves Information” (revised February 2007) promulgated by the Society of Petroleum Engineers. The engineer responsible for the preparation ofreserve and revenue estimates in this report is Robert G. Blair. Mr. Blair is a Licensed Professional Engineer in the State of Texas who has 35 years of experiencein the oil and gas industry. Mr. Blair earned his Bachelor of Science degree in Petroleum Engineering from Mississippi State University and his Master of Sciencein Management and Administrative Sciences from the University of Texas at Dallas. He has prepared reserve reports for public and private filings for the past 32years. Included in this report are summaries of gross and net oil and gas reserves grouped by Hugoton NPI, Republic NPI, Spinnaker NPI, Minerals NPI andBradley NPI. Also included are projections of estimated annual gross and net oil and gas production, net operating revenue, severance and ad valorem taxes, netoperating expenses, net capital costs, cash flow before taxes, and present worth for all properties appraised as of December 31, 2015. Present worth of future cashflow is not meant to represent the Fair Market Value of these properties or of Dorchester Minerals Operating LP. Yours very truly, /s/ Robert G. Blair, P.E. Calhoun, Blair & Associates Licensed Professional Engineer State of Texas #68057 Exhibit 99.2  January 27, 2016 Mr. Brad EhrmanDorchester Minerals, L.P.3838 Oak Lawn, Suite 300Dallas, Texas 75219-4541 Dear Mr. Ehrman: At your request, LaRoche Petroleum Consultants, Ltd. (LPC) has estimated the proved reserves and future cash flow, as of December 31, 2015, to theDorchester Minerals, L.P. (DMLP) royalty interest in certain properties located onshore in the continental United States. This report was completed as of the dateof this letter. This report was prepared to provide DMLP with Securities and Exchange Commission (SEC) compliant reserve estimates. It is our understanding thatthe report comprises one-hundred (100%) percent of DMLP’s royalty interests of which ninety-one percent (91%) were evaluated by LPC and nine percent (9%) byCalhoun Blair & Associates Inc. on a net reserve basis. We believe that the assumptions, data, methods, and procedures used in preparing this report, as set outbelow, are appropriate for the purpose of this report. This report has been prepared using constant prices and costs and conforms to our understanding of the SECguidelines, reserves definitions, and applicable financial accounting rules. The Fayetteville Royalty properties (Group 22) were projected by Calhoun Blair & Associates Inc. in Dallas, Texas at the request of DMLP. We note that we have necessarily included composite projections of net oil and gas reserves for certain properties due to the limited information availableto DMLP as a royalty interest owner and relatively small net reserves attributable to any specific property within the composite group. Summarized below are LPC’s estimates of net reserves and future net cash flow. Future net cash flow is after deducting production and ad valorem taxesand operating expenses but before consideration of federal income taxes. The discounted cash flow values included in this report are intended to represent the timevalue of money and should not be construed to represent an estimate of fair market value. We estimate the net reserves and future net cash flow to the DMLPinterest, as of December 31, 2015, to be: Net Reserves Future Net Cash Flow (M$) Category Oil(Mbbl) Gas(MMcf) NGL(Mbbl) Total Present Worthat 10% Proved Developed Producing 4,003 23,618 627 $229,276 $114,440 The oil reserves include crude oil and condensate. Oil and natural gas liquid (NGL) reserves are expressed in of barrels which are equivalent to 42 UnitedStates gallons. Gas reserves are expressed in thousands of standard cubic feet (MMcf) at the contract temperature and pressure bases.  The estimated reserves and future cash flow shown in this report are for proved developed producing reserves. No study was made to determine if proveddeveloped non-producing or proved undeveloped reserves might be established for these properties. This report does not include any value that could be attributedto interests in undeveloped acreage. Estimates of reserves for this report were prepared using standard geological and engineering methods generally accepted by the petroleum industry. Thereserves in this report have been estimated using deterministic methods. The method or combination of methods utilized in the evaluation of each reservoirincluded consideration of the stage of development of the reservoir, quality and completeness of basic data, and production history. Recovery from variousreservoirs and leases was estimated after consideration of the type of energy inherent in the reservoirs, the structural positions of the properties, and reservoir andwell performance. In some instances, comparisons were made to similar properties for which more complete data were available. We have used all methods andprocedures that we considered necessary under the circumstances to prepare this report. We have excluded from our consideration all matters as to which thecontrolling interpretation may be legal or accounting rather than engineering or geoscience. The estimated reserves and future cash flow amounts in this report are related to hydrocarbon prices. Historical prices through December 2015 were usedin the preparation of this report as required by SEC guidelines; however, actual future prices may vary significantly from the SEC prices. In addition, futurechanges in environmental and administrative regulations may significantly affect the ability of DMLP to produce oil and gas at the projected levels. Therefore,volumes of reserves actually recovered and amounts of cash flow actually received may differ significantly from the estimated quantities presented in this report. Benchmark prices used in this report are based on the twelve-month, unweighted arithmetic average of the first day of the month price for the periodJanuary through December 2015. Gas prices are referenced to a Henry Hub price of $2.59 per MMBtu, as published in the Platts Gas Daily, and are adjusted forenergy content, transportation fees, and regional price differentials. Oil and NGL prices are referenced to a West Texas Intermediate crude oil price of $50.28 perbarrel at Cushing Oklahoma and are adjusted for gravity, crude quality, transportation fees, and regional price differentials. These benchmark prices are heldconstant in accordance with SEC guidelines. The weighted average prices after adjustments over the life of the properties are $45.51 per barrel for oil, $2.13 permcf for gas, and $18.60 per barrel for NGL. The interests evaluated in this report consist of only royalty interests that are not burdened by operating and capital costs. LPC has made no investigation of possible gas volume and value imbalances that may have resulted from the overdelivery or underdelivery to the DMLPinterest. Our projections are based on the DMLP interest receiving its net revenue interest share of estimated future gross oil, gas, and NGL production. Technical information necessary for the preparation of the reserve estimates herein was furnished by DMLP or was obtained from state regulatoryagencies and commercially available data sources. No special tests were obtained to assist in the preparation of this report. For the purpose of this report, theindividual well test and production data as reported by the above sources were accepted as represented together with all other factual data presented by DMLPincluding the extent and character of the interest evaluated.  An on-site inspection of the properties has not been performed nor has the mechanical operation or condition of the wells and their related facilities beenexamined by LPC. The evaluation of potential environmental liability from the operation and abandonment of the properties is beyond the scope of this report. In addition, noevaluation was made to determine the degree of operator compliance with current environmental rules, regulations, and reporting requirements. Therefore, noestimate of the potential economic liability, if any, from environmental concerns is included in the projections presented herein. There are inherent uncertainties in the estimation and projection of future reserves and revenues. The reserves included in this report are estimates onlyand should not be construed as exact quantities. They may or may not be recovered; if recovered, the revenues therefrom and the costs related thereto could bemore or less than the estimated amounts. These estimates should be accepted with the understanding that future development, production history, changes inregulations, product prices, and operating expenses would probably cause us to make revisions in subsequent evaluations. A portion of these reserves are forproducing wells that lack sufficient production history to utilize performance-related reserve estimates. Therefore, these reserves are based on estimates of reservoirvolumes and recovery efficiencies along with analogies to similar production. These reserve estimates are subject to a greater degree of uncertainty than thosebased on substantial production and pressure data. It may be necessary to revise these estimates up or down in the future as additional performance data becomeavailable. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geological data; therefore, ourconclusions represent informed professional judgments only, not statements of fact. The results of our third-party study were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for publicdisclosure as an exhibit in filings made with the SEC by DMLP. DMLP makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, DMLP has certain registration statements filedwith the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation byreference in the registration statements on Form S-3 and Form S-8 of DMLP of the references to our name as well as to the references to our third-party report forDMLP which appears in the December 31, 2015 annual report on Form 10-K and/or 10-K/A of DMLP. Our written consent for such use is included as a separateexhibit to the filings made with the SEC by DMLP. We have provided DMLP with a digital version of the original signed copy of this report letter. In the event there are any differences between the digitalversion included in filings made by DMLP and the original signed report letter, the original signed report letter shall control and supersede the digital version. The technical persons responsible for preparing the reserve estimates presented herein meet the requirements regarding qualifications, independence,objectivity, and confidentiality set forth in the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by theSociety of Petroleum Engineers. The technical person primarily responsible for overseeing the preparation of reserves estimates herein is Joe A. Young. Mr. Youngis a Professional Engineer licensed in the State of Texas who has 34 years of engineering experience in the oil and gas industry. Mr. Young earned a Bachelor ofScience degree in Petroleum Engineering from Texas A&M University and has prepared reserves estimates for his employers and his own companies throughouthis career. He has prepared and overseen preparation of reports for public filings for LPC for the past 19 years. LPC is an independent firm of petroleum engineers,geologists, and geophysicists and is not employed on a contingent basis. Data pertinent to this report are maintained on file in our office. Very truly yours, LaRoche Petroleum Consultants, Ltd. State of Texas Registration Number F-1360 /s/ Joe A. Young Joe A. Young Licensed Professional Engineer State of Texas No. 62866 /s/ Al Iakovakis Al Iakovakis Manager of Unconventional Resources Evaluations Senior Staff Engineer

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