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 June 30, 2005 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 if the Registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes X No As of August 3, 2005, 28,240,431 common units of partnership interest were outstanding. Page 1 <page> TABLE OF CONTENTS DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS................................3 PART I.........................................................................3 ITEM 1. FINANCIAL INFORMATION...............................................3 CONDENSED BALANCE SHEETS AS OF JUNE 30, 2005 (UNAUDITED) AND DECEMBER 31, 2004......................................................4 CONDENSED STATEMENTS OF OPERATIONS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2005 AND 2004 (UNAUDITED).....................................5 CONDENSED STATEMENTS OF CASH FLOWS FOR THE THREE AND SIX MONTHS ENDED JUNE 30,2005 AND 2004 (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.........13 ITEM 4. CONTROLS AND PROCEDURES............................................13 PART II.......................................................................14 ITEM 1. LEGAL PROCEEDINGS..................................................14 ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS........14 ITEM 3. DEFAULTS UPON SENIOR SECURITIES....................................14 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS................14 ITEM 5. OTHER INFORMATION..................................................14 ITEM 6. EXHIBITS...........................................................14 SIGNATURES....................................................................14 INDEX TO EXHIBITS.............................................................15 CERTIFICATIONS................................................................16 Page 2
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 the Partnership's properties, changes in economic and industry conditions and changes in regulatory requirements (including changes in environmental requirements) and the Partnership's financial position, business strategy and other plans and objectives for future operations. These and other factors are set forth in the 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 3
DORCHESTER MINERALS, L.P. (A Delaware Limited Partnership) CONDENSED BALANCE SHEETS (Dollars in Thousands) June 30, December 31, 2005 2004 ---------- ----------- (unaudited) ASSETS Current assets: Cash and cash equivalents....................... $ 15,449 $ 12,365 Trade receivables............................... 4,866 5,389 Net profits interest receivable - related party. 4,618 4,750 Note receivable - related party................. 130 155 Prepaid expenses ............................... 50 25 -------- -------- Total current assets........................ 25,113 22,684 Properties and leasehold improvements - at cost: Oil and natural gas properties (full cost method) 291,932 291,855 Less full cost depletion ....................... 119,312 108,834 -------- ------- Total......................................... 172,620 183,021 Leasehold improvements.......................... 512 480 Less amortization............................... 36 12 -------- ------- Total ...................................... 476 468 -------- -------- Net properties and leasehold improvements....... 173,096 183,489 -------- -------- Total assets................................ $198,209 $206,173 ======== ======== LIABILITIES AND PARTNERSHIP CAPITAL Current liabilities Accounts payable and other current liabilities.. $ 973 $ 669 -------- -------- Total current liabilities.................. 973 669 Deferred rent incentive.............................. 346 366 -------- ------- Total liabilities.......................... 1,319 1,035 -------- ------- Commitments and contingencies Partnership capital: General partner................................. 7,601 7,807 Unitholders..................................... 189,289 197,331 -------- -------- Total partnership capital.................. 196,890 205,138 -------- -------- Total liabilities and partnership capital............ $198,209 $206,173 ======== ======== The accompanying condensed notes are an integral part of these financial statements. Page 4
DORCHESTER MINERALS, L.P. (A Delaware Limited Partnership) CONDENSED STATEMENT OF OPERATIONS (Dollars in Thousands except Earnings per Unit) (Unaudited) Three Months Ended Six Months Ended June 30, June 30, ----------------- ------------------ 2005 2004 2005 2004 ------- --------- -------- --------- Operating revenues: Net profits interests................. $ 6,458 $ 6,292 $12,574 $ 12,286 Royalties............................. 10,414 6,816 18,635 13,855 Lease Bonus........................... 90 272 150 680 ------- --------- -------- --------- Total operating revenues.............. 16,962 13,380 31,359 26,821 Cost and expenses: Operating, including production taxes. 772 497 1,473 1,080 Depletion and amortization............ 5,365 5,022 10,502 10,323 General and administrative expenses... 714 748 1,460 1,590 ------- --------- -------- -------- Total costs and expenses................... 6,851 6,267 13,435 12,993 ------- --------- -------- --------- Operating income .......................... 10,111 7,113 17,924 13,828 Other income (expense), net: Investment income..................... 73 19 124 36 Other income (expense), net........... 7 176 19 95 ------- --------- -------- --------- Total other income (expense), net..... 80 195 143 131 Net earnings .............................. $10,191 $ 7,308 $18,067 $ 13,959 ======= ========= ======== ========= Allocation of net earnings: General partner....................... $ 281 $ 180 $ 485 $ 346 ======= ========= ======== ========= Unitholders........................... $ 9,910 $ 7,128 $17,582 $ 13,613 ======= ========= ======== ========= Net earnings per common unit............... $ 0.35 $ 0.26 $ 0.62 $ 0.50 ======= ========= ======== ========= Wtd. avg. common units outstanding (000's) 28,240 27,040 28,240 27,040 ======= ========= ======== ========= The accompanying condensed notes are an integral part of these financial statements. Page 5
DORCHESTER MINERALS, L.P. (A Delaware Limited Partnership) CONDENSED STATEMENTS OF CASH FLOWS (Dollars in Thousands) (Unaudited) Six Months Ended June 30, --------------------- 2005 2004 -------- -------- Net cash provided by operating activities. ........... $ 29,508 $ 23,518 Cash flows used in investing activities: Capital expenditures.......................... (109) (128) Cash flows used in financing activities: Distributions paid to general partner and unitholders............................. (26,315) (22,370) -------- -------- Increase in cash and cash equivalents................. 3,084 1,020 Cash and cash equivalents at January 1,............... 12,365 10,881 -------- -------- Cash and cash equivalents at June 30,................. $ 15,449 $ 11,901 ======== ======== The accompanying condensed notes are an integral part of these financial statements. Page 6
DORCHESTER MINERALS, L.P. (A Delaware Limited Partnership) NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Unaudited) 1. BASIS OF PRESENTATION: Dorchester Minerals, L.P.(the "Partnership") is a publicly traded Delaware limited partnership that was formed in December 2001 in connection with the combination, which was completed on January 31, 2003, of Dorchester Hugoton, Ltd., which was a publicly traded Texas limited partnership, and Republic Royalty Company (Republic) and Spinnaker Royalty Company, L.P. (Spinnaker) both of which were privately held Texas partnerships. 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 the 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 the Partnership's common units by the weighted average number of units outstanding. 2. CONTINGENCIES: In January 2002, some individuals and an association called Rural Residents for Natural Gas Rights, referred to as RRNGR, sued Dorchester Hugoton, Ltd., along with several other operators in Texas County, Oklahoma. Dorchester Minerals Operating LP, owned directly and indirectly by our general partner, 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 the Partnership. The suit is currently pending in the District Court and discovery is partically completed by the plaintiffs and defendants. The individuals and RRNGR 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 lease agreements with defendants 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 the Partnership receives from the Net Profits Interests. The 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 the 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 Distributions since the third quarter of 2004 have been paid on 28,240,431 units; previous distributions were paid on 27,040,431 units. The next cash distribution will be paid by November 15, 2005. Page 7
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Overview Dorchester Minerals, L.P. is a publicly traded Delaware limited partnership that was formed in December 2001 in connection with the combination, which was completed on January 31, 2003, of Dorchester Hugoton, which was a publicly traded Texas limited partnership, and Republic and Spinnaker both of which were privately held Texas partnerships. We own producing and non-producing mineral,royalty,overriding royalty, net profits and leasehold interests. We refer to these interests as the Royalty Properties. We currently own Royalty Properties in 585 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 interest properties previously owned by Republic and Spinnaker. We refer to Dorchester Minerals Operating LP as the "operating partnership." Our Partnership directly and indirectly holds 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. After the close of each month, we receive a payment equaling 96.97% of the net proceeds actually received during that month from the properties subject to the Net Profits Interests. 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 Interests identical to the Net Profits Interests created upon our formation. One such interest, called the 2003/2004 NPI, resulted from transferring various properties to the operating partnership subject to a Net Profits Interest. As of June 30, 2005 cumulative costs and expenses attributable to the 2003/2004 NPI exceeded cumulative revenues by $966,000, an amount which we refer to as the 2003/2004 NPI deficit. The 2005 NPI deficit was $47,000. OUR FINANCIAL STATEMENTS DO NOT REFLECT ACTIVITY ATTRIBUTABLE TO PROPERTIES SUBJECT TO NET PROFITS INTERESTS THAT ARE IN A DEFICIT STATUS. CONSEQUENTLY, REVENUES, EXPENSES, PRODUCTION SALES VOLUMES AND PRICES SET FORTH HEREIN DO NOT REFLECT AMOUNTS ATTRIBUTABLE TO THE 2003/2004 NPI OR THE 2005 NPI PROPERTIES; INFORMATION CONCERNING ACREAGE OWNED AND DRILLING ACTIVITY ATTRIBUTABLE TO THESE PROPERTIES IS INCLUDED. Commodity Price Risks Our profitability is affected by volatility in prevailing oil and natural gas prices. Oil and natural gas prices have been subject to significant volatility in recent years in response to changes in the supply and demand for oil and natural gas in the market and general market volatility. Page 8
Results of Operations Three and Six Months Ended June 30, 2005 as compared to Three and Six Months Ended June 30, 2004 Normally, our period-to-period changes in net earnings and cash flows from operating activities are principally determined by changes in crude oil and natural gas sales volumes and prices. Our portion of oil and natural gas sales and weighted average prices were: Three Months Ended Six Months Ended ----------------------- ---------------- June 30, March 31, June 30, -------------- --------- ---------------- Accrual Basis Sales Volumes: 2005 2004 2005 2005 2004 - ---------------------------- ------- ------- ------- ------- ------ Net Profits Interests Gas Sales (mmcf) 1,215 1,352 1,223 2,438 2,699 Net Profits Interests Oil Sales (mbbls) 3 2 2 5 4 Royalty Properties Gas Sales (mmcf) 974 822 890 1,864 1,710 Royalty Properties Oil Sales (mbbls) 90 67 80 170 147 Weighted Average Sales Price: Net Profits Interests Gas Sales ($/mcf) $ 6.64 $ 5.81 $ 6.18 $ 6.41 $ 5.64 Net Profits Interests Oil Sales ($/bbl) $47.31 $35.25 $40.55 $44.17 $32.28 Royalty Properties Gas Sales ($/mcf) $ 6.19 $ 5.28 $ 5.42 $ 5.82 $ 5.16 Royalty Properties Oil Sales ($/bbl) $48.70 $36.90 $42.50 $45.78 $34.21 Production Costs Deducted Under the Net Profits Interests ($/mcfe) (1) $ 1.45 $ 1.23 $ 1.27 $ 1.36 $ 1.16 ________________________________________________________ (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 second quarter increased 34.3% from 67 mbbls in 2004 to 90 mbbls in 2005. Oil sales volumes attributable to our Royalty Properties during the first six months of 2005 increased 15.6% from 147 mbbls in 2004 to 170 mbbls in 2005. The increases in oil sales volumes are primarily attributable to the effects of the acquisition consummated in the third quarter of 2004 and to increased production from the Little Cedar Creek Fieldwide Unit in Conecuh County, Alabama and the T-Patch Field in Starr County, Texas (see discussion below). Natural gas sales volumes attributable to our Royalty Properties during the second quarter increased 18.5% from 822 mmcf in 2004 to 974 mmcf in 2005. Natural gas sales volumes attributable to our Royalty Properties during the first six months of 2005 increased 9% from 1,710 in 2004 to 1,864 mmcf in 2005. The increases in gas sales volumes are primarily attributable to the effects of the acquisition consummated in the third quarter of 2004 and to increased production from the T-Patch Field in Starr County, Texas (see discussion below). Oil sales volumes attributable to our Net Profits Interests during the second quarter and first six months of 2005 were virtually unchanged when compared to the same periods of 2004. Natural gas sales volumes attributable to our Net Profits Interests during the second quarter and first six months of 2005 decreased from the same periods of 2004. Second quarter sales of 1,215 mmcf during 2005 were 10.1% less than 1,352 mmcf during 2004. First six months sales of 2,438 mmcf during 2005 were 9.7% less than 2,699 mmcf during 2004. Decreases were a result of natural reservoir decline. Natural gas and crude oil sales volumes and prices from the 2003/2004 NPI and the 2005 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 32% from $36.90 per bbl during the second quarter 2004 to $48.70 per bbl during the second quarter 2005 and 33.8% from $34.21 per bbl during the first half of 2004 to $45.78 per bbl during the first half of 2005. Similarly, second quarter weighted average Partnership natural gas sales prices from Royalty Properties increased 17.2% from $5.28 per mcf during 2004 to $6.19 per mcf during 2005 and six months ended June 30 weighted average Partnership natural gas sales prices increased 12.8% from $5.16 per mcf during 2004 to $5.82 per mcf during 2005. Both oil and natural gas price increases resulted from changing market conditions. Second quarter weighted average oil sales prices from the Net Profits Interests' properties increased 34.2% from $35.25 per bbl in 2004 to $47.31 per bbl in 2005. Similarly, the first six months' Net Profits Interests' oil sales prices increased 36.8% from $32.28 per bbl in 2004 to $44.17 per bbl in 2005. Weighted average natural gas sales prices attributable to the Net Profits Interests increased during the second quarter and first six months of 2005 compared to the same periods of 2004. Second quarter natural gas sales prices of $6.64/mcf in 2005 were 14.3% greater than $5.81/mcf in 2004. First six month 2005 prices increased 13.7% to $6.41/mcf from $5.64/mcf. Changing market conditions resulted in the increased oil and natural gas sales prices. Page 9
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 volume of the corresponding product without regard to the timing of the production to which such sales may be attributable. This "indicated price" does not necessarily reflect the contract terms for such sales and may be affected by transportation costs, location differentials, and quality and gravity adjustments. While the relationship between 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 second quarter totaled $6,208,000. These receipts generally reflect oil and gas sales from the properties underlying the Net Profits Interests during February through April 2005. The weighted average indicated prices for oil and gas sales during the second quarter attributable the Net Profits Interests were $46.02/bbl and $6.46/mcf, respectively. Cash receipts attributable to the Partnership's Royalty Properties during the second quarter totaled $9,600,000. These receipts generally reflect oil sales during March through May 2005 and gas sales during February through April 2005. The weighted average indicated prices for oil and gas sales during the second quarter attributable the Royalty Properties were $45.88/bbl and $6.06/mcf, respectively. Our second quarter net operating revenues increased 26.8% from $13,380,000 during 2004 to $16,962,000 during 2005. Net operating revenues for the first six months of 2005 increased 16.9% from $26,821,000 to $31,359,000 during 2004. Both such quarterly and half year increases resulted primarily from increased natural gas prices and crude oil prices. Costs and expenses increased 9.3% from $6,267,000 during the second quarter of 2004 to $6,851,000 during the second quarter of 2005, while six months ended June 30 costs and expenses increased 3.4% from $12,993,000 during 2004 to $13,435,000 during 2005. Such increases primarily resulted from increased depletion and amortization, and increased production taxes associated with increased revenues. Other income (expense) was $7,000 during the three month period ended June 30, 2005 compared to $176,000 during the same period of 2004 due to recognition of a legal judgment for $184,000 during the second quarter of 2004. Other income (expense) for the six month period ended June 30, 2005 was $19,000 compared to $95,000 for the same period of 2004. The first six months of 2004 include expenses of $87,000 attributable to evaluation of property acquisitions which were not consummated. Investment income increased 284.2% from $19,000 in the second quarter of 2004 to $73,000 in the same period of 2005, and increased 244.4% from $36,000 in the first six months of 2004 to $124,000 in the same period of 2005 as a result of increased cash flows and higher interest rates. Depletion and amortization increased 6.8% during the three month period ending June 30 and 1.7% during the six month period ended June 30. The increases from $5,022,000 and $10,323,000 during 2004, respectively, to $5,365,000 and $10,502,000 during 2005, resulted from increased production offset by increased reserves due to the addition of properties to the base at the end of the third quarter of 2004 and recent drilling activity. We received cash payments in the amount of $189,000 from various sources during the second quarter of 2005 including lease bonuses attributable to 28 leases and pooling elections located in ten counties and parishes in two states. These leases reflected royalty terms ranging up to 30% and lease bonuses ranging up to $500/acre. Page 10
We received division orders for, or otherwise identified 80 new wells completed on our Royalty Properties and Net Profit Interests in 33 counties and parishes in nine states during the second quarter of 2005. The operating partnership elected to participate in four wells to be drilled on our Net Profits Interests located in three counties in three states. Selected new wells and the royalty interests owned therein by us and the working interests and net revenue interests owned therein by the operating partnership are summarized in the following table: Test Rates Ownership per day ------------ ------------- County/ Gas, Oil, State Parish Operator Well Name WI(1) NRI(1) mcf bbls - ----- ------- -------- ----------------- ---- ------ ------ ----- Royalty Properties - -------------------- Oklahoma Beckham Apache Perryman 6-25 -- 1.5% 3,205 6 Oklahoma Roger Mills Samson Shasta 1-27 -- 2.8% 1,383 -- Texas Starr Petrohawk Cleopatra 4 -- 1.6% 2,996 41 Texas Dewitt Hurd Kornfuehrer -- 1.2% 2,148 24 Louisiana Bienville El Paso Poole A-2 -- 1.1% 1,395 95 Net Profits Interests - --------------------- Montana Richland Headington Childers 24X-2 2.0% 1.4% 237 511 Arkansas Van Buren SEECO Hillis 1-27 6.3% 6.3% 880 -- Oklahoma Roger Mills JMA Hutson Farms 5-18 1.6% 1.6% 3,050 8 ____________________________________ (1) WI and NRI mean working interest and net revenue interest, respectively. T-PATCH (REKLAW OSO) FIELD, STARR COUNTY, TEXAS We disclosed in our Form 10-K for 2004 and Form 10 Q for the quarter ended March 31, 2005 the results of activity on lands located in South Texas in which we own a royalty interest. We previously omitted the identity of the operator, well names and location of this property due to confidentiality restrictions. The operator of this property, EOG Resources, Inc. has filed completion and production reports with the Texas Railroad Commission for some of the wells located in this field. Five wells have been drilled and completed on lands in which we own a 5.12% net revenue interest. A sixth well is currently undergoing completion operations and a seventh well has been permitted to a proposed total depth of 10,000 feet. We received $181,725 during the first quarter of 2005 attributable to production during December 2004 and January 2005 from the first two wells. We received $765,527 during the second quarter of 2005 attributable to production from the first five wells during February, March and April 2005. Management has observed significant variance in flow rates and production declines from these wells and cautions the reader from estimating future performance based on the limited history available. Second quarter net earnings allocable to common units increased 39% from $7,128,000 during 2004 to $9,910,000 during 2005. First six month common unit net earnings increased 29.2% from $13,613,000 during 2004 to $17,582,000 during 2005. Increased crude oil and natural gas sales prices primarily resulted in increased net earnings of common units. Net cash provided by operating activities increased 29.8% from $11,741,000 during the second quarter 2004 to $15,242,000 during the second quarter 2005. Similarly, net cash from operating activities for the first six months increased 25.5% from $23,518,000 in 2004 to $29,508,000 in 2005. The principal reason for such increases is increased crude 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 properly 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. Page 11
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). Liquidity and Working Capital Cash and cash equivalents totaled $15,449,000 at June 30, 2005 and $12,365,000 at December 31, 2004. 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 underway could prompt a reevaluation of this position. Any such drilling is estimated to cost $250,000 to $300,000 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. Two second quarter 2005, fracture treatments in these properties have cost approximately $60,000 per well. One fracture treatment thus far failed to improve production while the other improved profuction from 131 mcf per day to 250 mcf per day while also increasing well shut-in pressure. The wells 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 to remain competitive with adjoining operators for the foreseeable future. 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 (productive and nonproductive) 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. Page 12
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 are prohibited from incurring any debt, other than trade debt as discussed previously in this document. 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 or in other factors 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. Page 13
PART II Item 1. Legal Proceedings 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 a) We held our Annual Unitholders meeting on Wednesday, May 4, 2005 in Dallas Texas. b) Proxies were solicited by the Board of Managers pursuant to Regulation 14A under the Securities Exchange Act of 1934. There were no solicitations in opposition to the nominees listed in the proxy statement and all of such nominees were duly elected. c) The only matter voted on at the meeting was the election of the three nominees to the Board of Managers. Out of the 28,240,431 units issued and outstanding and entitled to vote at the meeting, 26,323,553 units were present in person or by proxy. The results were as follows: Votes Votes Withheld Broker Nominee for Election from Election Non-Votes ------------------ ------------ ------------- --------- Buford P. Berry 26,050,762 272,791 1,916,878 Rawles Fulgham 26,261,102 62,451 1,916,878 C.W. "Bill" Russell 26,282,226 41,327 1,916,878 Item 5. Other Information None. Item 6. Exhibits See the attached Index to Exhibits. 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: August 3, 2005 Chief Executive Officer /s/ H.C. Allen, Jr. --------------------------------- H.C. Allen, Jr. Date: August 3, 2005 Chief Financial Officer Page 14
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) Page 15