UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, DC. 20549 FORM 10-Q [X] QUARTERLY REPORT UNDER SECTION 13 or 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 or [ ] TRANSITION REPORT PURSUANT TO SECTION 13 or 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from __________ to __________ For the Quarterly Period Ended March 31, 2006 Commission file number 000-50175 DORCHESTER MINERALS, L.P. (Exact name of Registrant as specified in its charter) Delaware 81-0551518 (State or other jurisdiction of (I.R.S. Employer Identification No.) Incorporation or organization) 3838 Oak Lawn Avenue, Suite 300, Dallas, Texas 75219 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (214) 559-0300 None Former name, former address and former fiscal year, if changed since last report Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [] Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one): Large accelerated filer [] Accelerated filer [X] Non-accelerated filer [] Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act.): Yes [X] No [] As of May 1, 2006, 28,240,431 common units of partnership interest were outstanding. <page> TABLE OF CONTENTS DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS................................3 PART I.........................................................................3 ITEM 1. FINANCIAL INFORMATION..........................................3 CONDENSED BALANCE SHEETS AS OF MARCH 31, 2006 (UNAUDITED) AND DECEMBER 31, 2005..............................................4 CONDENSED STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED MARCH 31, 2006 AND 2005 (UNAUDITED)............................5 CONDENSED STATEMENTS OF CASH FLOWS FOR THE THREE MONTHS ENDED MARCH 31, 2006 AND 2005 (UNAUDITED)............................6 NOTES TO THE CONDENSED FINANCIAL STATEMENTS..............................7 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS......................................8 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK....12 ITEM 4. CONTROLS AND PROCEDURES.......................................13 PART II.......................................................................13 ITEM 1. LEGAL PROCEEDINGS.............................................13 ITEM 1A. RISK FACTORS..................................................13 ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS...13 ITEM 3. DEFAULTS UPON SENIOR SECURITIES...............................13 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS...........13 ITEM 5. OTHER INFORMATION.............................................13 ITEM 6. EXHIBITS......................................................13 SIGNATURES....................................................................14 INDEX TO EXHIBITS.............................................................15 CERTIFICATIONS................................................................16 <page> DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS Statements included in this report which are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions or forecasts related thereto), are forward-looking statements. These statements can be identified by the use of forward-looking terminology including "may," "believe," "will," "expect," "anticipate," "estimate," "continue" or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other "forward-looking" information. In this report, the term "Partnership," as well as the terms "us," "our," "we," and "its" are sometimes used as abbreviated references to Dorchester Minerals, L.P. itself or Dorchester Minerals, L.P. and its related entities. These forward-looking statements are based upon management's current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements for a number of important reasons. Examples of such reasons include, but are not limited to, changes in the price or demand for oil and natural gas, changes in the operations on or development of our Partnership's properties, changes in economic and industry conditions and changes in regulatory requirements (including changes in environmental requirements) and our Partnership's financial position, business strategy and other plans and objectives for future operations. These and other factors are set forth in our Partnership's filings with the Securities and Exchange Commission. You should read these statements carefully because they discuss our expectations about our future performance, contain projections of our future operating results or our future financial condition, or state other "forward-looking" information. Before you invest, you should be aware that the occurrence of any of the events herein described in this report could substantially harm our business, results of operations and financial condition and that upon the occurrence of any of these events, the trading price of our common units could decline, and you could lose all or part of your investment. PART I ITEM 1. FINANCIAL INFORMATION Dorchester Minerals, L.P. is a publicly traded Delaware limited partnership that commenced operations on January 31, 2003, upon the combination of Dorchester Hugoton, Ltd., which was a publicly traded Texas limited partnership, and Republic Royalty Company and Spinnaker Royalty Company, L.P., both of which were privately held Texas partnerships. The combination was accounted for using the purchase method of accounting. <page> DORCHESTER MINERALS, L.P. (A Delaware Limited Partnership) CONDENSED BALANCE SHEETS (Dollars in Thousands) March 31, December 31, 2006 2005 ----------- ----------- ASSETS (unaudited) Current assets: Cash and cash equivalents $ 21,514 $ 23,389 Trade receivables 6,569 7,615 Net profits interests receivable - related party 4,435 6,996 Current portion of note receivable - related party 50 50 Prepaid expenses 27 22 -------- -------- Total current assets 32,595 38,072 Note receivable - related party less current portion 42 55 Other non-current assets 19 19 -------- -------- Total 61 74 Property and leasehold improvements - at cost: Oil and natural gas properties (full cost method): 291,875 291,875 Less accumulated full cost depletion 134,339 129,643 -------- -------- Total 157,536 162,232 Leasehold improvements 512 512 Less accumulated amortization 72 60 -------- -------- Total 440 452 -------- -------- Net property and leasehold improvements 157,976 162,684 -------- -------- Total assets $190,632 $200,830 ======== ======= LIABILITIES AND PARTNERSHIP CAPITAL Current liabilities Accounts payable and other current liabilities $ 714 $ 580 Current portion of deferred rent incentive 39 39 -------- --------- Total current liabilities 753 619 -------- -------- Deferred rent incentive less current portion 316 326 -------- -------- Total liabilities 1,069 945 -------- -------- Commitments and contingencies Partnership capital: General partner 7,408 7,663 Unitholders 182,155 192,222 -------- -------- Total partnership capital 189,563 199,885 -------- -------- Total liabilities and partnership capital $190,632 $200,830 ======== ======== The accompanying condensed notes are an integral part of these financial statements. <page> DORCHESTER MINERALS, L.P. (A Delaware Limited Partnership) CONDENSED STATEMENTS OF OPERATIONS (Dollars in Thousands, except Earnings Per Unit) (Unaudited) Three Months Ended March 31, ---------------------------- 2006 2005 --------- --------- Operating revenues: Net profits interests $ 6,556 $ 6,116 Royalties 11,947 8,221 Lease bonus 764 60 -------- --------- Total operating revenues 19,267 14,397 Costs and expenses: Operating, including production taxes 850 701 Depletion and amortization 4,708 5,137 General and administrative expenses 847 746 -------- --------- Total costs and expenses 6,405 6,584 -------- --------- Operating income 12,862 7,813 Other income (expense), net: Investment income 192 51 Other income (expense), net 6 12 -------- --------- Total other income (expense), net 198 63 -------- --------- Net earnings $ 13,060 $ 7,876 ======== ========= Allocation of net earnings: General partner $ 378 $ 204 ======== ========= Unitholders $ 12,682 $ 7,672 ======== ========= Net earnings per common unit (in dollars) $ 0.45 $ 0.27 ======== ========= Weighted average common units outstanding (000's) 28,240 28,240 ======== ========= The accompanying condensed notes are an integral part of these financial statements. <page> DORCHESTER MINERALS, L.P. (A Delaware Limited Partnership) CONDENSED STATEMENTS OF CASH FLOWS (In Thousands) (Unaudited) Three Months Ended March 31, -------------------- 2006 2005 --------- --------- Net cash provided by operating activities $ 21,494 $ 14,253 Cash flows used in investing activities: Proceeds from related party note receivable 13 13 Capital expenditures - (62) ------- -------- Total cash flows provided by (used in) investing activities 13 (49) ------- -------- Cash flows used in financing activities: Distributions paid to general partner and unitholders (23,382) (12,361) -------- -------- Increase (decrease) in cash and cash equivalents (1,875) 1,843 Cash and cash equivalents at January 1, 23,389 12,365 -------- -------- Cash and cash equivalents at March 31, $ 21,514 $ 14,208 ======== ======== The accompanying condensed notes are an integral part of these financial statements. <page> DORCHESTER MINERALS, L.P. (A Delaware Limited Partnership) NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Unaudited) 1. BASIS OF PRESENTATION: Dorchester Minerals, L.P. is a publicly traded Delaware limited partnership that commenced operations on January 31, 2003, upon the combination of Dorchester Hugoton, Ltd., which was a publicly traded Texas limited partnership, and Republic Royalty Company and Spinnaker Royalty Company, L.P., both of which were privately held Texas partnerships. The combination was accounted for using the purchase method of accounting. The condensed financial statements reflect all adjustments (consisting only of normal and recurring adjustments unless indicated otherwise) that are, in the opinion of management, necessary for the fair presentation of our Partnership's financial position and operating results for the interim period. Interim period results are not necessarily indicative of the results for the calendar year. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" for additional information. Per-unit information is calculated by dividing the income applicable to holders of our Partnership's common units by the weighted average number of units outstanding. Certain amounts in the 2005 financial statements have been reclassified to conform with the 2006 presentation. 2. CONTINGENCIES: In January 2002, some individuals and an association called Rural Residents for Natural Gas Rights sued Dorchester Hugoton, Ltd., along with several other operators in Texas County, Oklahoma. Dorchester Minerals Operating LP now owns and operates the properties formerly owned by Dorchester Hugoton. These properties contribute a major portion of the Net Profits Interests amounts paid to our Partnership. The plaintiffs consist primarily of Texas County, Oklahoma residents who, in residences located on leases use natural gas from gas wells located on the same leases, at their own risk, free of cost. The plaintiffs seek declaration that their domestic gas use is not limited to stoves and inside lights and is not limited to a principal dwelling as provided in the oil and gas leases entered into in the 1930s to the 1950s. Plaintiffs' claims against defendants include failure to prudently operate wells, violation of rights to free domestic gas, and fraud. Plaintiffs also seek certification of class action against defendants. On October 1, 2004, the plaintiffs severed claims against Dorchester Minerals Operating LP regarding royalty underpayments. Dorchester Minerals Operating LP believes plaintiffs' claims, including severed claims, are completely without merit. Based upon past measurements of such domestic gas usage, Dorchester Minerals Operating LP believes the domestic gas damages sought by plaintiffs to be minimal. An adverse decision could reduce amounts our Partnership receives from the Net Profits Interests. Our Partnership and Dorchester Minerals Operating LP 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 financial position or operating results. 3. DISTRIBUTIONS TO HOLDERS OF COMMON UNITS: Since our Partnership's combination on January 31, 2003, unitholder cash distributions per common unit have been or will be: Year Quarter Record Date Payment Date Amount - ---- ------------- ---------------- ----------------- ---------- 2003 1st (partial) April 28, 2003 May 8, 2003 $0.206469 2003 2nd July 28, 2003 August 7, 2003 $0.458087 2003 3rd October 31, 2003 November 10, 2003 $0.422674 2003 4th January 26, 2004 February 5, 2004 $0.391066 2004 1st April 30, 2004 May 10, 2004 $0.415634 2004 2nd July 26, 2004 August 5, 2004 $0.415315 2004 3rd October 25, 2004 November 4, 2004 $0.476196 2004 4th February 1, 2005 February 11, 2005 $0.426076 2005 1st April 29, 2005 May 9, 2005 $0.481242 2005 2nd July 25, 2005 August 4, 2005 $0.514542 2005 3rd October 24, 2005 November 3, 2005 $0.577287 2005 4th January 30, 2006 February 9, 2006 $0.805543 2006 1st May 1, 2006 May 11, 2006 $0.729852 Distributions beginning with the third quarter of 2004 were paid on 28,240,431 units; previous distributions were paid on 27,040,431 units. Our partnership agreement requires the next cash distribution to be paid by August 15, 2006. ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Overview We own producing and nonproducing mineral, royalty, overriding royalty, net profits and leasehold interests. We refer to these interests as the Royalty Properties. We currently own Royalty Properties in 573 counties and parishes in 25 states. Dorchester Minerals Operating LP, a Delaware limited partnership owned directly and indirectly by our general partner, holds the working interest properties previously owned by Dorchester Hugoton and a minor portion of mineral, royalty and working interest properties previously owned by Republic and Spinnaker. We refer to Dorchester Minerals Operating LP as the "operating partnership." We directly and indirectly own a 96.97% net profits overriding royalty interest in these properties. We refer to our net profits overriding royalty interest in these properties as the Net Profits Interests. We receive monthly payments equaling 96.97% of the net profits actually realized by the operating partnership from these properties in the preceding month. In accordance with our partnership agreement we have the continuing right to create additional net profits interests by transferring properties to the operating partnership subject to the reservation of a Net Profits Interest identical to the Net Profits Interests created upon our formation. One such interest, called the 2003/2004/2005 NPI, resulted from transferring various properties to the operating partnership subject to a Net Profits Interest. As of March 31, 2006 cumulative costs and expenses, which include an interest equivalent, totaled $3,367,000 attributable to the 2003/2004/2005 NPI properties and exceeded cumulative revenues by $422,000, an amount which we refer to as the 2003/2004/2005 NPI deficit. The Spinnaker NPI was in a temporary deficit status of $10,000. The 2006 NPI had incurred no cash expenses through March 31, 2006. Our financial statements do not reflect activity attributable to properties subject to Net Profits Interests that are in a deficit status, except for temporary deficits. Consequently, revenues, expenses, production sales volumes and prices set forth herein do not reflect amounts attributable to the 2003/2004/2005 NPI or the 2006 NPI properties, however, information concerning acreage owned and drilling activity attributable to these properties is included herein. Commodity Price Risks Our profitability is affected by volatility in prevailing oil and natural gas prices. Oil and natural gas prices have been subject to significant volatility in recent years in response to changes in the supply and demand for oil and natural gas in the market and general market volatility. Results of Operations Three Months Ended March 31, 2006 as compared to Three Months Ended March 31, 2005 Normally, our period-to-period changes in net earnings and cash flows from operating activities are principally determined by changes in crude oil and natural gas sales volumes and prices. Our portion of oil and natural gas sales and weighted average prices were: Three Months Ended March 31, ------------------ Accrual Basis Sales Volumes: 2006 2005 ------ ------ Net Profits Interests Gas Sales (mmcf)............ 1,126 1,223 Net Profits Interests Oil Sales (mbbls) .......... 3 2 Royalty Properties Gas Sales (mmcf) .............. 965 890 Royalty Properties Oil Sales (mbbls) ............. 85 80 Accrual Basis Weighted Average Sales Price: Net Profits Interests Gas Sales ($/mcf)........... $ 7.42 $ 6.18 Net Profits Interests Oil Sales ($/bbl)........... $47.04 $40.55 Royalty Properties Gas Sales ($/mcf) ............. $ 7.39 $ 5.42 Royalty Properties Oil Sales ($/bbl).............. $56.67 $42.50 Accrual Basis Production Costs Deducted Under the Net Profits Interests ($/mcfe) (1)........$ 1.75 $ 1.27 ________________________________________________________ (1) Provided to assist in determination of revenues; applies only to Net Profit Interest sales volumes and prices. Oil sales volumes attributable to our Royalty Properties during the first quarter increased 6.3% from 80 mbbls during 2005 to 85 mbbls in 2006. Natural gas sales volumes attributable to our Royalty Properties increased 8.4% from 890 mmcf during 2005 to 965 mmcf during 2006. The increases in oil and natural gas sales volumes are attributable to new wells drilled on the Royalty Properties in late 2004 and early 2005. Oil sales volumes attributable to our Net Profits Interests during the first quarter were virtually unchanged from 2005. Natural gas sales volumes attributable to our Net Profits Interests during the first quarter decreased 7.9% from 1,223 mmcf during 2005 to 1,126 mmcf during 2006 due to natural reservoir decline. Production sales volumes and prices from the 2003/2004/2005 NPI and the 2006 NPI properties are excluded from the above table. See "Overview" above. Weighted average oil sales prices attributable to the Partnership's interest in Royalty Properties increased 33.3% from $42.50 per bbl during the first quarter 2005 to $56.67 per bbl during the first quarter 2006. Similarly, first quarter weighted average Partnership natural gas sales prices from Royalty Properties increased 36.3% from $5.42 per mcf during 2005 to $7.39 per mcf during 2006. Both oil and natural gas price increases resulted from changing market conditions. First quarter weighted average oil sales prices from the Net Profits Interests' properties increased 16.0% from $40.55 per bbl in 2005 to $47.04 per bbl in 2006. First quarter weighted average natural gas sales prices from the Net Profits Interests' properties increased 20.1% from $6.18 per mcf in 2005 to $7.42 per mcf in 2006. Such oil and natural gas price increases are due to changing market conditions. In an effort to provide the reader with information concerning prices of oil and gas sales that correspond to our quarterly distributions, management calculates the weighted average price by dividing gross revenues received by the net volumes of the corresponding product without regard to the timing of the production to which such sales may be attributable. This "indicated price" does not necessarily reflect the contractual terms for such sales and may be affected by transportation costs, location differentials, and quality and gravity adjustments. While the relationship between the Partnership's cash receipts and the timing of the production of oil and gas may be described generally, actual cash receipts may be materially impacted by purchasers' release of suspended funds and by prior period adjustments. Cash receipts attributable to the Partnership's Net Profits Interests during the 2006 first quarter totaled $9,118,000. These receipts generally reflect oil and gas sales from the properties underlying the Net Profits Interests during November 2005 through January 2006. The weighted average indicated prices for oil and gas sales during the 2006 first quarter attributable to the Net Profits Interests were $52.56/bbl and $9.16/mcf, respectively. Cash receipts attributable to the Partnership's Royalty Properties during the 2006 first quarter totaled $12,532,000. These receipts generally reflect oil sales during December 2005 through February 2006 and gas sales during November 2005 through January 2006. The weighted average indicated prices for oil and gas sales during the 2006 first quarter attributable to the Royalty Properties were $56.33/bbl and $9.15/mcf, respectively. Our first quarter net operating revenues increased 33.8% from $14,397,000 during 2005 to $19,267,000 during 2006 due primarily to increased natural gas prices and crude oil prices. Costs and expenses during the first quarter of 2005 were $6,584,000 compared to $6,405,000 during the first quarter of 2006. Other income during the three month period ended March 31 increased from $63,000 during 2005 to $198,000 during the same period in 2006 primarily as a result of increased interest income due to increased cash flow and increased interest rates. Depletion and amortization during the three month period ended March 31 decreased from $5,137,000 during 2005 to $4,708,000 during 2006, as a result of a lower depletable base due to effects of previous depletion. We received cash payments in the amount of $935,000 from various sources during the first quarter of 2006 including lease bonus attributable to 13 consummated leases and pooling elections located in eight counties and parishes in four states and the non-refundable down payment associated with transaction described below under Fayetteville Shale Trend of Northern Arkansas. Each of the consummated leases reflected a royalty term of 25% and lease bonuses ranging up to $500 per acre. We received division orders, or otherwise identified 81 new wells completed on our Royalty Properties and Net Profits Interests located in 31 counties and parishes in eight states. The operating partnership elected to participate in six wells to be drilled on our Net Profits Interests located in five counties in four states. Selected new wells and the royalty interests owned by us and the working and net revenue interests owned by the operating partnership are summarized in the following table and discussion: County/ State Parish Operator Well Name Ownership Test Rates, per day - ----- ------- ----------- --------------- ------------ ------------------- WI(1) NRI(1) Gas,mcf Oil,bbls ----- ------ ------- -------- Royalty Properties - -------------------- OK Beckham St. Mary Reed 4-1 -- 1.2% 5,950 13 TX Wheeler Devon Hayes 18-2 -- 3.1% 2,164 21 OK Custer Cimarex Kephart 4-33 -- 5.4% 1,110 -- TX Panola XTO Powers 7 -- 5.5% 1,237 40 AR Logan Houston Expl. Phillips 15-20 -- 1.2% 1,941 -- Net Profits Interests - --------------------- OK Roger Mills JMA Hutson Farms 6-18 1.6% 1.6% 6,637 15 ____________________________________ (1) WI and NRI mean working interest and net revenue interest, respectively. T-PATCH (REKLAW OSO) FIELD, JIM HOGG AND STARR COUNTIES, TEXAS - We own varying undivided mineral interests totaling 4,994/1,583 gross/net acres in three tracts in Jim Hogg and Starr Counties, Texas and which we leased to EOG Resources, Inc. ("EOG") in 2004. Please refer to the discussion on page 18 of our 2005 10-K for more information about the results of prior activity on our lands in the field. EOG has drilled and completed two wells on the second of these tracts (which we call the Guerra Mineral Trust tract). The Guerra Mineral Trust No. 1 well was drilled in January 2006 to a permitted total depth of 8,100 feet and was tested to sales at rates of 6,531 mcf and 126 barrels per day on March 21, 2006. The Guerra Mineral Trust No. 2 well was drilled in March 2006 to a total depth of 8,000 feet and was tested to sales at rates of 10,778 mcf and 106 barrels per day on March 27, 2006. We own a 10.2% net revenue interest in this tract. We did not receive any cash revenue attributable to production from these two wells in the first quarter of 2006. JEFFRESS (VICKSBURG S) FIELD, HIDALGO COUNTY, TEXAS - We own varying undivided mineral interests in several thousand acres in the greater Jeffress Field area of western Hidalgo County, Texas. Please refer to the discussion on page 18 of our 2005 10-K for more information about the results of prior activity on our lands in the field. The Dan A. Hughes Company Coates-Dorchester 1 well was drilled in November 2005 to a permitted total depth of 11,500 feet and was tested to sales at rates of 3,263 mcf and 96 barrels per day on January 26, 2006. This well was flowing to sales on April 26, 2006 at rates of 3,545 mcf and 49 barrels per day. We own a 6.25% net revenue interest in this well; the operating partnership owns a 1.25 net revenue interest before payout and a 6.25% working interest and a 4.69% net revenue interest after payout. FAYETTEVILLE SHALE TREND OF NORTHERN ARKANSAS - We own varying undivided mineral interests in approximately 20,000 gross/10,000 net acres located in Cleburne, Conway, Faulkner, Franklin, Pope, Van Buren and White Counties, Arkansas in what is commonly referred to as the "Fayetteville Shale" trend of the Arkoma Basin. We received numerous lease offers for and well proposals on our interests in this area during 2004 and 2005. We circulated a Request For Proposals (RFP) to industry participants in January, 2006 which RFP solicited expressions of interest to lease our interests in this area. On March 30, 2006 we entered into an agreement with a large independent oil and gas exploration company pursuant to which we will lease our interest in 9,800 net mineral acres for terms including lease bonus of $625 per acre, one-quarter royalty and optional working interest participation in certain circumstances. We received a non-refundable down payment in the amount of $616,062 on March 29, 2006. The agreement provides for payment of the remaining bonus consideration, estimated to be approximately $5,500,000, on or before June 29, 2006. Payment of the remaining lease bonus is contingent upon conditions customarily found in transactions of this type including confirmation of our title to the properties. First quarter net earnings allocable to common units increased 65.3% from $7,672,000 during 2005 to $12,682,000 during 2006 due primarily to increased crude oil and natural gas sales prices. Net cash provided by operating activities increased 50.8% from $14,253,000 during the first quarter 2005 to $21,494,000 during the first quarter 2006, principally due to higher oil and natural gas sales prices. Liquidity and Capital Resources Capital Resources Our primary sources of capital are our cash flow from the Net Profits Interests and the Royalty Properties. Our only cash requirements are the distributions to our unitholders, the payment of oil and natural gas production and property taxes not otherwise deducted from gross production revenues and general and administrative expenses incurred on our behalf and allocated in accordance with our partnership agreement. Since the distributions to our unitholders are, by definition, determined after the payment of all expenses actually paid by us, the only cash requirements that may create liquidity concerns for us are the payments of expenses. Since most of these expenses vary directly with oil and natural gas prices and sales volumes, we anticipate that sufficient funds will be available at all times for payment of these expenses. See Note 3 of the Notes to the Condensed Financial Statements for the amounts and dates of cash distributions to unitholders. We are not directly liable for the payment of any exploration, development or production costs. We do not have any transactions, arrangements or other relationships that could materially affect our liquidity or the availability of capital resources. We have not guaranteed the debt of any other party, nor do we have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt. Pursuant to the terms of our Partnership Agreement, we cannot incur indebtedness, other than trade payables, (i) in excess of $50,000 in the aggregate at any given time or (ii) which would constitute "acquisition indebtedness" (as defined in Section 514 of the Internal Revenue Code of 1986, as amended). Expenses and Capital Expenditures The operating partnership does not currently anticipate drilling additional wells as a working interest owner in the Fort Riley zone or the Council Grove formations or elsewhere in the Oklahoma properties previously owned by Dorchester Hugoton. Successful activities by others in these formations or other developments could prompt a reevaluation of this position. Any such drilling is estimated to cost $300,000 to $350,000 per well. The operating partnership anticipates continuing additional fracture treating in the Oklahoma properties previously owned by Dorchester Hugoton but is unable to predict the cost as a specific engineering study is required for each fracture treatment. Previous fracture treatments in these properties have cost between $50,000 and $80,000 per well. They did not require casing repairs. Such activities by the operating partnership could influence the amount we receive from the Net Profits Interests. The operating partnership owns and operates the wells, pipelines and gas compression and dehydration facilities located in Kansas and Oklahoma previously owned by Dorchester Hugoton. The operating partnership anticipates gradual increases in expenses as repairs to these facilities become more frequent, and anticipates gradual increases in field operating expenses as reservoir pressure declines. The operating partnership does not anticipate incurring significant expense to replace these facilities at this time. These capital and operating costs are reflected in the Net Profit Interests payments we receive from the operating partnership. In 1998, Oklahoma regulations removed production quantity restrictions in the Guymon-Hugoton field, and did not address efforts by third parties to persuade Oklahoma to permit infill drilling in the Guymon-Hugoton field. Both infill drilling and removal of production limits could require considerable capital expenditures. The outcome and the cost of such activities are unpredictable. Such activities by the operating partnership could influence the amount we receive from the Net Profits Interests. No additional compression affecting the wells formerly owned by Dorchester Hugoton has been installed since 2000 by operators on adjoining acreage. The operating partnership believes it now has sufficient field compression and permits for vacuum operation to remain competitive with adjoining operators for the foreseeable future. Liquidity and Working Capital Cash and cash equivalents totaled $21,514,000 at March 31, 2006 and $23,389,000 at December 31, 2005. Critical Accounting Policies We utilize the full cost method of accounting for costs related to our oil and natural gas properties. Under this method, all such costs are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the units-of-production method. These capitalized costs are subject to a ceiling test, however, which limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves discounted at 10% plus the lower of cost or market value of unproved properties. In accordance with applicable accounting rules, Dorchester Hugoton was deemed to be the accounting acquiror of the Republic and Spinnaker assets. Our Partnership's acquisition of these assets was recorded at a value based on the closing price of Dorchester Hugoton's common units immediately prior to consummation of the combination transaction, subject to certain adjustments. Consequently, the acquisition of these assets was recorded at values that exceed the historical book value of these assets prior to consummation of the combination transaction. Our Partnership did not assign any book or market value to unproved properties, including nonproducing royalty, mineral and leasehold interests. Oil and gas properties are evaluated using the full cost ceiling test at the end of each quarter. The discounted present value of our proved oil and natural gas reserves is a major component of the ceiling calculation and requires many subjective judgments. Estimates of reserves are forecasts based on engineering and geological analyses. Different reserve engineers may reach different conclusions as to estimated quantities of natural gas reserves based on the same information. Our reserve estimates are prepared by independent consultants. The passage of time provides more qualitative information regarding reserve estimates, and revisions are made to prior estimates based on updated information. However, there can be no assurance that more significant revisions will not be necessary in the future. Significant downward revisions could result in an impairment representing a non-cash charge to earnings. In addition to the impact on calculation of the ceiling test, estimates of proved reserves are also a major component of the calculation of depletion. While the quantities of proved reserves require substantial judgment, the associated prices of oil and natural gas reserves that are included in the discounted present value of our reserves are objectively determined. The ceiling test calculation requires use of prices and costs in effect as of the last day of the accounting period, which are generally held constant for the life of the properties. As a result, the present value is not necessarily an indication of the fair value of the reserves. Oil and natural gas prices have historically been volatile and the prevailing prices at any given time may not reflect our Partnership's or the industry's forecast of future prices. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. For example, estimates of uncollected revenues and unpaid expenses from royalties and net profits interests in properties operated by non-affiliated entities are particularly subjective due to inability to gain accurate and timely information. Therefore, actual results could differ from those estimates. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The following information provides quantitative and qualitative information about our potential exposures to market risk. The term "market risk" refers to the risk of loss arising from adverse changes in oil and natural gas prices, interest rates and currency exchange rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. Market Risk Related to Oil and Natural Gas Prices Essentially all of our assets and sources of income are from the Net Profits Interests and the Royalty Properties, which generally entitle us to receive a share of the proceeds based on oil and natural gas production from those properties. Consequently, we are subject to market risk from fluctuations in oil and natural gas prices. Pricing for oil and natural gas production has been volatile and unpredictable for several years. We do not anticipate entering into financial hedging activities intended to reduce our exposure to oil and natural gas price fluctuations. Absence of Interest Rate and Currency Exchange Rate Risk We do not anticipate having a credit facility or incurring any debt, other than trade debt. Therefore, we do not expect interest rate risk to be material to us. We do not anticipate engaging in transactions in foreign currencies which could expose us to foreign currency related market risk. ITEM 4. CONTROLS AND PROCEDURES Evaluation of Disclosure Controls and Procedures As of the end of the period covered by this report, our Partnership's principal executive officer and principal financial officer, carried out an evaluation of the effectiveness of our disclosure controls and procedures. Based on their evaluation, they have concluded that our Partnership's disclosure controls and procedures effectively ensure that the information required to be disclosed in the reports the Partnership files with the Securities and Exchange Commission is recorded, processed, summarized and reported, within the time periods specified by the Securities and Exchange Commission. Changes in Internal Controls There were no changes in our Partnership's internal controls (as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934) during the quarter ended March 31, 2006 that have materially affected, or are reasonably likely to materially affect, our Partnership's internal controls subsequent to the date of their evaluation of our disclosure controls and procedures. PART II ITEM 1. LEGAL PROCEEDINGS None. ITEM 1A. RISK FACTORS None. ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS None. ITEM 3. DEFAULTS UPON SENIOR SECURITIES None. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. ITEM 5. OTHER INFORMATION The Partnership's Audit Committee engaged Grant Thornton LLP as the independent registered public accounting firm for 2006. ITEM 6. EXHIBITS See the attached Index to Exhibits. <page> SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. DORCHESTER MINERALS, L.P. By: Dorchester Minerals Management LP its General Partner, By: Dorchester Minerals Management GP LLC, its General Partner /s/ William Casey McManemin ----------------------------------------------- William Casey McManemin Date: May 2, 2006 Chief Executive Officer /s/ H.C. Allen, Jr. ------------------------------------------------ H.C. Allen, Jr. Date: May 2, 2006 Chief Financial Officer <page> INDEX TO EXHIBITS Number Description 3.1 Certificate of Limited Partnership of Dorchester Minerals, L.P. (incorporated by reference to Exhibit 3.1 to Dorchester Minerals' Registration Statement on Form S-4, Registration Number 333-88282) 3.2 Amended and Restated Agreement of Limited Partnership of Dorchester Minerals, L.P. (incorporated by reference to Exhibit 3.2 to Dorchester Minerals' Report on Form 10-K filed for the year ended December 31, 2002) 3.3 Certificate of Limited Partnership of Dorchester Minerals Management LP (incorporated by reference to Exhibit 3.4 to Dorchester Minerals Registration Statement on Form S-4, Registration Number 333-88282) 3.4 Amended and Restated Agreement of Limited Partnership of Dorchester Minerals Management LP (incorporated by reference to Exhibit 3.4 to Dorchester Minerals' Report on Form 10-K for the year ended December 31, 2002) 3.5 Certificate of Formation of Dorchester Minerals Management GP LLC (incorporated by reference to Exhibit 3.7 to Dorchester Minerals' Registration Statement on Form S-4, Registration Number 333-88282) 3.6 Amended and Restated Limited Liability Company Agreement of Dorchester Minerals Management GP LLC (incorporated by reference to Exhibit 3.6 to Dorchester Minerals' Report on Form 10-K for the year ended December 31, 2002) 3.7 Certificate of Formation of Dorchester Minerals Operating GP LLC (incorporated by reference to Exhibit 3.10 to Dorchester Minerals' Registration Statement on Form S-4, Registration Number 333-88282) 3.8 Limited Liability Company Agreement of Dorchester Minerals Operating GP LLC (incorporated by reference to Exhibit 3.11 to Dorchester Minerals' Registration Statement on Form S-4, Registration Number 333-88282) 3.9 Certificate of Limited Partnership of Dorchester Minerals Operating LP (incorporated by reference to Exhibit 3.12 to Dorchester Minerals' Registration Statement on Form S-4, Registration Number 333-88282) 3.10 Amended and Restated Agreement of Limited Partnership of Dorchester Minerals Operating LP. (incorporated by reference to Exhibit 3.10 to Dorchester Minerals' Report on Form 10-K for the year ended December 31, 2002) 3.11 Certificate of Limited Partnership of Dorchester Minerals Oklahoma LP (incorporated by reference to Exhibit 3.11 to Dorchester Minerals' Report on Form 10-K for the year ended December 31, 2002) 3.12 Agreement of Limited Partnership of Dorchester Minerals Oklahoma LP (incorporated by reference to Exhibit 3.12 to Dorchester Minerals' Report on Form 10-K for the year ended December 31, 2002) 3.13 Certificate of Incorporation of Dorchester Minerals Oklahoma GP, Inc. (incorporated by reference to Exhibit 3.13 to Dorchester Minerals' Report on Form 10-K for the year ended December 31, 2002) 3.14 Bylaws of Dorchester Minerals Oklahoma GP, Inc. (incorporated by reference to Exhibit 3.14 to Dorchester Minerals' Report on Form 10-K for the year ended December 31, 2002) 3.15 Certificate of Limited Partnership of Dorchester Minerals Acquisition LP (incorporated by reference to Exhibit 3.15 to Dorchester Minerals' Report on Form 10-K for the year ended December 31, 2004) 3.16 Agreement of Limited Partnership of Dorchester Minerals Acquisition LP (incorporated by reference to Exhibit 3.16 to Dorchester Minerals' Report on Form 10-Q for the quarter ended September 30, 2004) 3.17 Certificate of Incorporation of Dorchester Minerals Acquisition GP, Inc. (incorporated by reference to Exhibit 3.17 to Dorchester Minerals' Report on Form 10-Q for the quarter ended September 30, 2004) 3.18 Bylaws of Dorchester Minerals Acquisition GP, Inc. (incorporated by reference to Exhibit 3.18 to Dorchester Minerals' Report on Form 10-Q for the quarter ended September 30, 2004) 31.1 Certification of Chief Executive Officer of the Partnership pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 31.2 Certification of Chief Financial Officer of the Partnership pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 32.1 Certification of Chief Executive Officer of the Partnership pursuant to 18 U.S.C. Sec. 1350 32.2 Certification of Chief Financial Officer of the Partnership pursuant to 18 U.S.C. Sec. 1350 (contained within Exhibit 32.1 hereto) 15