Dorchester Minerals - 10-Q quarterly report FY

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As of November 6, 2007, 28,240,431 common units of partnership interest were outstanding.

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 “DMLP,” “us,” “our,” “we,” and “its” are sometimes used as abbreviated references to Dorchester Minerals, L.P. itself or Dorchester Minerals, L.P. and its related entities.

These forward-looking statements are based upon management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements for a number of important reasons. Examples of such reasons include, but are not limited to, changes in the price or demand for oil and natural gas, changes in the operations on or development of our properties, changes in economic and industry conditions and changes in regulatory requirements (including changes in environmental requirements) and our financial position, business strategy and other plans and objectives for future operations. These and other factors are set forth in our filings with the Securities and Exchange Commission.

You should read these statements carefully because they discuss our expectations about our future performance, contain projections of our future operating results or our future financial condition, or state other “forward-looking” information. Before you invest, you should be aware that the occurrence of any of the events 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.

See attached financial statements on the following pages.

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 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 common units by the weighted average number of units outstanding. Certain amounts in the 2006 financial statements have been reclassified to conform with the 2007 presentation.  Such reclassifications did not impact net income, total assets, or total liabilities.

Distributions beginning with the third quarter of 2004 were paid on 28,240,431 units; previous distributions were paid on 27,040,431 units.  Fourth quarter distributions shown above are paid in the first calendar quarter of the following year.  Our partnership agreement requires the next cash distribution to be paid by February 15, 2008.

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 working interests properties and a minor portion of mineral and royalty interest properties. We refer to Dorchester Minerals Operating LP as the “operating partnership” or “DMOLP.” We directly and indirectly own a 96.97% net profits overriding royalty interest in property groups primarily made up of the three NPIs created when we commenced operations and the 2003-2006 NPI. We refer to our net profits overriding royalty interest in these property groups as the Net Profits Interests. We currently receive monthly payments equaling 96.97% of the preceding month’s net profits actually realized by the operating partnership from three of the property groups.

In accordance with our partnership agreement we have the continuing right and obligation 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 when we commenced operations in 2003. The purpose of such Net Profits Interests is to avoid the Partnership’s participation as a working interest or other cost-bearing owner that could result in unrelated business taxable income. Net profits interest payments are not considered unrelated business taxable income for tax purposes. One such Net Profits Interest was created for each of calendar years 2003 through 2006 by transferring various properties to the operating partnership subject to a Net Profits Interest. These interests were subsequently combined and we currently refer to them as the 2003-2006 NPI. As of September 30, 2007, cumulative operating and development costs presented in the following table, which include amounts equivalent to an interest charge, exceeded cumulative revenues of the 2003-2006 NPI, resulting in a cumulative deficit. All cumulative deficits (which represent cumulative excess of operating and development costs over revenue received) are borne 100% by our General Partner until the 2003-2006 NPI recovers the deficit amount. Once in profit status, we will receive the Net Profits Interest payment attributable to these properties. Our financial statements do not reflect activity attributable to properties subject to Net Profits Interests that are in a deficit status.  Consequently, Net Profits Interest payments, and production sales volumes and prices set forth in other portions of this quarterly report do not reflect amounts attributable to the 2003-2006 NPI.

The following table sets forth cash receipts and disbursements attributable to the 2003-2006 Net Profits Interest:

The development costs pertain to more properties than the properties producing revenue due to timing differences between operating partnership expenditures and oil and gas production and payments to the operating partnership.  Amounts in the above table reflect the operating partnership’s ownership of the subject properties.  Net Profits Interest payments to us, if any, will equal 96.97% of the cumulative net profits actually received by the operating partnership attributable to subject properties.  The above financial information attributable to the 2003-2006 NPI may not be indicative of future results of the 2003-2006 NPI and may not indicate when the deficit status may end and when Net Profits Interest payments may begin from the 2003-2006 NPI.

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 along with domestic and international political economic conditions.

Normally, our period-to-period changes in net earnings and cash flows from operating activities are principally determined by changes in oil and natural gas sales volumes and prices. Our portion of oil and natural gas sales and weighted average prices were:

Oil sales volumes attributable to our Royalty Properties during the third quarter decreased 8.3% from 84 mbbls in 2006 to 77 mbbls in 2007. Oil sales volumes attributable to our Royalty Properties during the first nine months decreased 9.1% from 253 mbbls in 2006 to 230 mbbls in 2007. Natural gas sales volumes attributable to our Royalty Properties during the third quarter decreased 12.4% from 1,018 mmcf in 2006 to 892 mmcf in 2007. Natural gas sales volumes attributable to our Royalty Properties during the first nine months decreased 13.6% from 2,997 in 2006 to 2,588 mmcf in 2007. The decreases in oil and natural gas sales volumes were primarily attributable to wells completed in the T-Patch Field in early 2006.  As previously reported, these wells have exhibited significant production declines after initially producing at anomalously high rates.

Oil sales volumes attributable to our Net Profits Interests during the third quarter and first nine months of 2007 were virtually unchanged when compared to the same periods of 2006.  Natural gas sales volumes attributable to our Net Profits Interests during the third quarter and first nine months of 2007 decreased from the same periods of 2006.  Third quarter sales of 1,049 mmcf during 2007 were 7.0% less than 1,128 mmcf during 2006.  First nine month sales of 3,100 mmcf during 2007 were 8.7% less than 3,394 mmcf during 2006.  Both natural gas sales volume decreases were a result of natural reservoir decline, while nine month decreases also resulted from scheduled equipment and facility maintenance and January weather-related production disruptions.  Production sales volumes and prices from the 2003-2006 NPI are excluded from the above table.  See “Overview” above.

Weighted average oil sales prices attributable to our interest in Royalty Properties increased 15.2% from $62.83/bbl during the third quarter of 2006 to $72.41/bbl during the third quarter of 2007 and virtually unchanged from the first nine months of 2006 to the same period of 2007.  Third quarter weighted average natural gas sales prices from Royalty Properties decreased 8.0% from $6.09/mcf during 2006 to $5.60/mcf during 2007.  The nine months ended September 30 weighted average Royalty Properties natural gas sales prices increased 1.2% from $6.54/mcf during 2006 to $6.62/mcf during 2007.  Both oil and natural gas price changes resulted from changing market conditions.

Third quarter weighted average oil sales prices from the Net Profits Interests’ properties increased 7.2% from $63.25/bbl in 2006 to $67.82/bbl in 2007.  The first nine months’ Net Profits Interests’ oil sales prices increased 3.4% from $55.04/bbl in 2006 to $56.89/bbl in 2007.  Weighted average natural gas sales prices attributable to the Net Profits Interests decreased during the third quarter of 2007 compared to the same period of 2006 and increased from the first nine months of 2006 to the same period of 2007.  Third quarter natural gas sales prices of $5.78/mcf in 2007 were 1.5% less than $5.87/mcf in 2006.  The nine months ended September 30, 2007 natural gas prices increased 6.6% to $6.78/mcf from $6.36/mcf in the same period of 2006.  Changing market conditions resulted in increased oil prices.  Natural gas sales price increases during the nine month period resulted from changing market conditions plus abnormal natural gas liquid payments accrued during the first six months of 2007.

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 contract terms for such sales and may be affected by transportation costs, location differentials, and quality and gravity adjustments. While the relationship between our cash receipts and the timing of the production of oil and gas may be described generally, actual cash receipts may be materially impacted by purchasers’ release of suspended funds and by purchasers’ prior period adjustments.

Cash receipts attributable to our Net Profits Interests during the 2007 third quarter totaled $6,161,000. These receipts generally reflect oil and gas sales from the properties underlying the Net Profits Interests during May through July 2007.  The weighted average indicated prices for oil and gas sales during the 2007 third quarter attributable to the Net Profits Interests were $59.13/bbl and $7.53/mcf, respectively.

Cash receipts attributable to our Royalty Properties during the 2007 third quarter totaled $10,588,000. These receipts generally reflect oil sales during June through August 2007 and gas sales during May through July 2007.  The weighted average indicated prices for oil and gas sales during the 2007 third quarter attributable to the Royalty Properties were $66.25/bbl and $6.98/mcf, respectively.

Our third quarter net operating revenues decreased 12.9% from $16,897,000 during 2006 to $14,716,000 during 2007.  Net operating revenues for the first nine months of 2007 decreased 20.7% from $59,304,000 during 2006 to $47,043,000 during 2007. The quarterly decrease resulted from decreases in both gas and oil sales volumes and decreases in gas sales prices.  The nine month decrease resulted primarily from changes in production volumes and decreased lease bonus revenues.  First quarter 2006 net operating revenues included a non-refundable lease bonus payment of $616,000 related to our Arkansas lease transactions and the second quarter of 2006 net operating revenues included $5,535,000 additional Arkansas lease bonus payment.

Costs and expenses decreased 18.4% from $6,835,000 during the third quarter of 2006 to $5,576,000 during the third quarter of 2007, while nine month ended September 30 costs and expenses decreased 14.2% from $19,779,000 during 2006 to $16,971,000 during 2007.  Such decreases primarily resulted from decreased ad valorem tax rates and depletion, offset by increased general and administrative expenses.

Depletion and amortization decreased 17.2% during the third quarter ended September 30, 2007 and 18.5% during the nine months ended September 30, 2007 when compared to the same periods of 2006.  The decreases from $4,787,000 and $14,308,000 during the third quarter and nine months ended September 30, 2006 respectively, to $3,963,000 and $11,657,000 during the same periods of 2007 respectively, resulted from a lower depletable base due to effects of previous depletion and upward revisions in oil and gas reserve estimates at 2006 year end.

We received cash payments in the amount of $617,000 from various sources during the third quarter of 2007 including lease bonuses attributable to 39 consummated leases and pooling elections located in 13 counties and parishes in six states. The consummated leases reflected royalty terms ranging up to 40% and lease bonuses ranging up to $500/acre.

We received division orders for, or otherwise identified, 123 new wells completed on our Royalty Properties and Net Profit Interests located in 48 counties and parishes in 11 states during the third quarter of 2007. The operating partnership elected to participate in two wells to be drilled on our Net Profits Interests located in two counties in two 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.

This table does not include wells drilled in the Fayetteville Shale Trend as they are detailed in a subsequent discussion and table.

FAYETTEVILLE SHALE TREND OF NORTHERN ARKANSAS- We own varying undivided perpetual mineral interests totaling 23,336/11,464 gross/net acres located in Cleburne, Conway, Faulkner, Franklin, Johnson, Pope, Van Buren, and White counties, Arkansas in an area commonly referred to as the “Fayetteville Shale” trend of the Arkoma Basin.  Forty wells have been permitted on the lands as of October 26, 2007.  Wells which have been proposed to be drilled by the operator but for which permits have not yet been issued by the Arkansas Oil & Gas Commission are not reflected in this number.  Wells and permitted locations and the royalty interests owned by us as well as the working and net revenue interests owned by the operating partnership are summarized in the following table.

Third quarter net earnings allocable to common units decreased 8.9% from $10,082,000 during 2006 to $9,181,000 during 2007.  First nine months common unit net earnings decreased 23.6% from $39,007,000 during 2006 to $29,784,000 during 2007.  The 2007 decrease from the third quarter 2006 net earnings is primarily the result of decreased oil and gas sales volumes and decreased gas sales prices.  The 2007 decrease from the first nine months of 2006 net earnings is primarily a result of decreased 2007 lease bonus revenues compared to 2006 which included $6,151,000 attributable to Arkansas transactions and decreased natural gas and oil sales volumes.

Net cash provided by operating activities increased 7.9% from $15,451,000 during the third quarter of 2006 to $16,675,000 during the third quarter of 2007 primarily due to abnormal natural gas liquid payments. Net cash provided by operating activities for the first nine months decreased 25.6% from $59,962,000 during 2006 to $44,583,000 during 2007.  The principal reasons for such decrease are timing of cash receipts, higher 2006 lease bonus revenues primarily related to Arkansas transactions and changes in production volumes.  See discussion above on net operating revenues for more details.

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).

During 2007, depending upon rig availability, the operating partnership anticipates drilling one well in the Oklahoma Council Grove formation.  The operating partnership does not otherwise currently anticipate drilling additional wells as a working interest owner/operator in the Oklahoma or Kansas properties.  Successful activities by others or other developments could prompt a reevaluation of this position.  Present drilling and completion costs are estimated at $350,000 - $500,000 per well.  Such activities by the operating partnership could influence the amount we receive from the Net Profits Interests.

The operating partnership anticipates continuing fracture treating in its Oklahoma properties 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. 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 Profits 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. Infill drilling could require considerable capital expenditures. The outcome and the cost of such activities are unpredictable and could influence the amount we receive from the Net Profits Interests. The operating partnership believes it now has sufficient field compression and permits for vacuum operation for the foreseeable future.

Cash and cash equivalents totaled $17,427,000 at September 30, 2007 and $13,927,000 at December 31, 2006.

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. Oil and gas properties are evaluated using the full cost ceiling test at the end of each quarter and when events indicate possible impairment.

The discounted present value of our proved oil and natural gas reserves is a major component of the ceiling calculation and requires many subjective judgments. Estimates of reserves are forecasts based on engineering and geological analyses. Different reserve engineers may reach different conclusions as to estimated quantities of natural gas 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.

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.

Essentially all of our assets and sources of income are from the Royalties and the Net Profits Interests, 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.

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.

As of the end of the period covered by this report, our principal executive officer and principal financial officer carried out an evaluation of the effectiveness of our disclosure controls and procedures. Based on their evaluation, they have concluded that our disclosure controls and procedures effectively ensure that the information required to be disclosed in the reports we file with the Securities and Exchange Commission is recorded, processed, summarized and reported, within the time periods specified by the Securities and Exchange Commission.

There were no changes in our internal controls (as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934) during the quarter ended September 30, 2007 that have materially affected, or are reasonably likely to materially affect, our internal controls subsequent to the date of their evaluation of our disclosure controls and procedures.