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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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The following discussion contains forward-looking statements. For a description of limitations inherent in forward-looking statements, see page 1 of this Form 10-Q.
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 574 counties and parishes in 25 states.
We own net profits overriding royalty interests (referred to as the Net Profits Interests, or “NPIs”) in various properties owned by Dorchester Minerals Operating LP, a Delaware limited partnership owned directly and indirectly by our general partner. We refer to Dorchester Minerals Operating LP as the “operating partnership” or “DMOLP.” We receive monthly payments equaling 96.97% of the net profits actually realized by the operating partnership from these properties in the preceding month. In the event costs exceed revenues on a cash basis in a given month for properties subject to a Net Profits Interest, no payment is made and any deficit is accumulated and carried over and reflected in the following month's calculation of net profit.
The Minerals NPI (one of the six) owns certain cost bearing interests that were either in existence at the time of our formation, or created subsequent to our formation but associated with nonproducing mineral, royalty and leasehold interest properties acquired upon our formation. The Minerals NPI achieved a cumulative net profit status on September 30, 2011 as a result of its cumulative net revenue exceeding cumulative operating and actual and budgeted capital expenditures and development costs. Subsequent Minerals NPI amounts and payments distributed are:
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Distribution
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NPI Period Ended
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NPI
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Amount
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Period
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Nov. 30, 2011
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$1,347,000
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$1,306,000
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4th Qtr. 2011
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Feb. 29, 2012
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$709,000
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$688,000
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1st Qtr. 2012
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May 31, 2012
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$354,000
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$343,000
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2nd Qtr. 2012
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Aug. 31, 2012
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$395,000
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$383,000
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3rd Qtr. 2012
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Nov. 30, 2012
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$769,000
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$746,000
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4th Qtr. 2012
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Feb. 28, 2013
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$729,000
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$707,000
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1st Qtr. 2013
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Prior to the Minerals NPI achieving a cumulative payout status, activity attributable to the Minerals NPI was not reflected in our consolidated financial statements in accordance with generally accepted accounting principles. Effective third quarter 2011, our consolidated financial statements reflect activity attributable to the Minerals NPI, and include cash receipts and disbursements and accrued revenues and costs not yet received or paid by the NPI. Our financial statements will now continue to reflect such information regardless of its net profit status on a cumulative or reporting period basis.
As of March 31, 2013 each of the six NPIs have previously had cumulative revenue that exceeded cumulative costs, such excess constituting net proceeds on which NPI payments were determined. In the event an NPI has a deficit of cumulative revenue versus cumulative costs, the deficit will be borne solely by the operating partnership. The Minerals NPI and one minor NPI are in deficit status as of March 31, 2013.
Commodity Price Risks
Our profitability is affected by oil and natural gas market prices. Oil and natural gas prices have fluctuated significantly 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 and economic conditions.
Results of Operations
Three Months Ended March 31, 2013 as compared to Three Months Ended March 31, 2012
Normally, our period-to-period changes in net income 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:
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Three Months Ended
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March 31,
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Accrual basis sales volumes:
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2013
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2012
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Royalty properties gas sales (mmcf)
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1,277 |
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1,597 |
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Royalty properties oil sales (mbbls)
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87 |
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87 |
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NPI gas sales (mmcf)
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1,067 |
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1,118 |
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NPI oil sales (mbbls)
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21 |
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15 |
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Accrual basis weighted average sales price:
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Royalty properties gas sales ($/mcf)
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$ |
3.10 |
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$ |
2.51 |
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Royalty properties oil sales ($/bbl)
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$ |
87.72 |
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$ |
99.49 |
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NPI gas sales ($/mcf)
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$ |
3.35 |
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$ |
2.35 |
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NPI oil sales ($/bbl)
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$ |
88.89 |
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$ |
97.57 |
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Accrual basis production costs deducted under the NPIs ($/mcfe) (1)
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$ |
3.32 |
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$ |
3.01 |
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(1)
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Provided to assist in determination of revenues; applies only to NPI sales volumes and prices.
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Natural gas sales volumes attributable to our Royalty Properties during the first quarter decreased 20.0% from 1,597 mmcf in 2012 to 1,277 mmcf in 2013. The decrease in natural gas sales volumes was primarily attributable to decreased activity in the Fayetteville Shale and Barnett Shale. Oil sales volumes attributable to our Royalty Properties during the first quarter of 2013 were the same as the first quarter of 2012 at 87 mbbls.
Natural gas sales volumes attributable to our NPIs during the first quarter of 2013 also decreased from the same period of 2012. First quarter gas sales volumes of 1,067 mmcf during 2013 were 4.6% lower than 1,118 mmcf during 2012 principally due to natural reservoir declines and decreased activity in the Fayetteville Shale. Oil sales volumes attributable to our NPIs during the first quarter of 2013 were 21 mbbls, an increase of 40% from 15 mbbls during the same period of 2012 attributable to activity in the Permian Basin and Bakken Trend.
Weighted average natural gas sales prices from Royalty Properties increased 23.5% from $2.51/mcf during the first quarter of 2012 to $3.10/mcf during the first quarter of 2013. The weighted average oil sales prices attributable to our interest in Royalty Properties decreased 11.8% from $99.49/bbl during the first quarter of 2012 to $87.72/bbl during the first quarter of 2013. Both oil and natural gas price changes resulted from changing market prices.
First quarter weighted average oil sales prices from the NPIs decreased 8.9% from $97.57/bbl in 2012 to $88.89/bbl in 2013. First quarter weighted average natural gas sales prices attributable to the NPIs increased 42.6% from $2.35/mcf during 2012 to $3.35/mcf in 2013. Both changes during the three-month period resulted from changing market prices.
Our first quarter net operating revenues decreased 1.6% from $13,433,000 during 2012 to $13,218,000 during 2013. Net operating revenues decreased because of reduced lease bonus income, lower natural gas sales volume, and lower oil prices. These factors were partially offset by increased natural gas prices.
Costs and expenses of $5,570,000 during the first quarter of 2013 were down 9.4% from $6,147,000 during the same period of 2012. The first quarter 2013 decreases in depletion and amortization costs offset increased production tax compared to 2012 first quarter. General and administrative expenses of $899,000 were up 12.0% compared to $803,000 in 2012 related primarily to non-recurring Bakken Trend costs.
Depletion and amortization costs were $3,386,000 during the first quarter of 2013 compared to $4,312,000 during the same period of 2012 due to the effects of upward reserve revisions at 2012 year-end partially offset by lower sales volumes during 2013.
Net income allocable to common units was up 5.1% from $7,014,000 during the first quarter of 2012 to $7,374,000 during the first quarter of 2013 due to lower costs and expenses, partially offset by lower lease bonus income as discussed above.
Net cash provided by operating activities decreased 16.6% from $17,547,000 during the first quarter of 2012 to $14,635,000 during the first quarter of 2013. The decrease in net cash provided by operating activities was attributable to reduced lease bonus income, lower natural gas sales volume, and lower oil prices. These factors were partially offset by increased natural gas prices.
In an effort to provide the reader with information concerning prices of oil and natural 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 natural 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 Royalty Properties during the 2013 first quarter totaled approximately $10,800,000. These receipts generally reflect oil sales during December 2012 through February 2013 and natural gas sales during November 2012 through January 2013. The weighted average indicated prices for oil and natural gas sales during the 2013 first quarter attributable to the Royalty Properties were $84.99/bbl and $3.19/mcf, respectively.
Cash receipts attributable to our NPIs during the 2013 first quarter totaled approximately $4,900,000. These receipts reflect oil and natural gas sales from the properties underlying the NPIs generally during November 2012 through January 2013. The weighted average indicated prices received during the 2013 first quarter for oil and natural gas sales were $85.26/bbl and $6.41/mcf, respectively. The natural gas weighted average indicated price for the quarter was increased by $3.12/mcf due to the receipt of a natural gas liquids payment of $2,900,000 for 2012 production. The natural gas liquids payment is based on an Oklahoma Guymon-Hugoton field 1994 gas delivery agreement that is in effect through 2015. Under the terms of the agreement, when the market price of natural gas liquids increases sufficiently disproportionately to natural gas market prices, the operating partnership receives a portion of that increase in an annual payment based on calendar year data. In the event the evaluation at the end of the annual contract period shows the payment to be determinable and collectable, the revenue is accrued.
We received cash payments of approximately $50,000 from various sources during the first quarter of 2013, of which some are attributable to nine consummated leases and pooling elections located in five counties and parishes in four states. The consummated leases reflected royalty terms ranging up to 25% and lease bonuses ranging up to $1,250/acre.
We received division orders for, or otherwise identified, 133 new wells completed on our Royalty Properties and NPIs located in 38 counties and parishes in eight states during the first quarter of 2013. The operating partnership elected to participate during the quarter in 16 wells to be drilled on our NPI properties located in seven counties in three states.
Additional information concerning selected properties is summarized below:
APPALACHIAN BASIN —. We own varying undivided perpetual mineral interests in approximately 31,000/24,000 gross/net acres in 19 counties in southern New York and northern Pennsylvania. Approximately 75% of those net acres are located in eastern Allegany and western Steuben Counties, New York—an area that some industry press reports suggest may be prospective for gas production from unconventional reservoirs, including the Marcellus Shale. However, development of these natural gas resources will be limited until remaining regulatory issues related to high-volume hydraulic fracturing are resolved. We continue to monitor industry activity and encourage dialogue with industry participants to determine the proper course of action regarding our interests in this area. During the second quarter of 2012, the Partnership leased 506 net acres in Lycoming County, Pennsylvania in multiple transactions for amounts ranging from $3,000 to $4,000 per acre and 20% royalty escalating to 25% in certain circumstances.
FAYETTEVILLE SHALE TREND OF NORTHERN ARKANSAS –- We own varying undivided perpetual mineral interests in approximately 23,000/11,000 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. Permits for 457 wells had been issued on these lands as of March 31, 2013, of which the operating partnership owns an interest in 247. In total, 423 wells were spud of which 390 were completed as producers, including wells for which we may not yet have received division orders or first payment.
HORIZONTAL BAKKEN, WILLISTON BASIN –- We own varying undivided perpetual mineral interests in approximately 70,000/9,000 gross/net acres located in Burke, Divide, Dunn, McKenzie, Mountrail and Williams Counties, North Dakota. Permits for 362 wells had been issued on these lands as of March 31, 2013. In total, 328 wells were spud, of which 268 were completed as producers including wells for which we may not yet have received division orders or first payment. In most instances we elected to become a non-consenting mineral owner—who, according to North Dakota law, is not obligated to pay well costs, receives a royalty equal to the weighted average of all leases in the unit or 16% (at the operator’s option) from the date of first production, and backs-in for its full working interest after the operator has recovered 150% of drilling and completion costs from the net cash flow. The back-in working interest, if any, is owned by the operating partnership subject to the Minerals NPI burden. Non-consenting mineral owners are not entitled to well data other than public information available from the North Dakota Industrial Commission. As of March 31, 2013, 22 of these wells had achieved 150% payout.
Market dynamics in the Bakken Trend have evolved resulting in higher lease bonus and royalty offers for unleased mineral interests. We are exploring our options and anticipate circulating a Request For Proposals (RFP) to industry participants seeking expressions of interest to acquire a lease on our interests in this area, to combine our interests with others or to pursue alternative transaction structures. We may engage the services of an investment bank or other agent to represent us with respect to a RFP or in a transaction. We can not project if, when or with whom we may elect to lease or otherwise transact all or any part of our interests as a result of this process.
Liquidity and Capital Resources
Capital Resources
Our primary sources of capital are our cash flow from the NPIs 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 sales prices and 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 Consolidated 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
Depending upon gas prices, the operating partnership plans to continue its efforts to increase production in Oklahoma with techniques that may include fracture treating, deepening, recompleting, and drilling. Costs vary widely and are not predictable as each effort requires specific engineering. Such activities by the operating partnership could influence the amount we receive from the NPIs as reflected in the accrual-basis production costs $/mcfe in the table under “Results of Operations.”
The operating partnership owns and operates the wells, pipelines and natural gas compression and dehydration facilities located in Kansas and Oklahoma. 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 NPI payments we receive from the operating partnership.
In 1998, Oklahoma regulations removed production quantity restrictions in the Guymon-Hugoton field and did not address efforts by third parties to 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 NPIs. The operating partnership believes it now has sufficient field compression and permits for vacuum operation for the foreseeable future.
Liquidity and Working Capital
Cash and cash equivalents totaled $14,639,000 at March 31, 2013 and $13,792,000 at December 31, 2012.
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. The full cost ceiling is evaluated 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 or crude oil 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 significant revisions will not be necessary in the future. Significant downward revisions could result in an impairment representing a non-cash charge to income. In addition to the impact on the calculation of the ceiling test, estimates of proved reserves are also a major component of the calculation of depletion.
While the quantities of proved reserves require substantial judgment, the associated prices of oil and natural gas reserves that are included in the discounted present value of our reserves are objectively determined. The ceiling test calculation requires use of the unweighted arithmetic average of the first day of the month price during the 12-month period ending on the balance sheet date and costs in effect as of the last day of the accounting period, which are generally held constant for the life of the properties. As a result, the present value is not necessarily an indication of the fair value of the reserves. Oil and natural gas prices have historically been volatile and the prevailing prices at any given time may not reflect our Partnership’s or the industry’s forecast of future prices.
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 Royalty Properties and NPI properties operated by non-affiliated entities are particularly subjective due to our 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 possible losses.
Market Risk Related to Oil and Natural Gas Prices
Essentially all of our assets and sources of income are from Royalty Properties and NPIs, 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 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 that 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 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 were effective.
Changes in Internal Controls
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 March 31, 2013 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.
PART II – OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
The Partnership and the operating partnership are involved in legal and/or administrative proceedings arising in the ordinary course of their businesses, none of which have predictable outcomes and none of which are believed to have any significant effect on consolidated financial position, cash flows, or operating results.
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.
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DORCHESTER MINERALS, L.P.
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By:
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Dorchester Minerals Management LP
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its General Partner
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By:
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Dorchester Minerals Management GP LLC
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its General Partner
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By:
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/s/ William Casey McManemin
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William Casey McManemin
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Date: May 9, 2013
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Chief Executive Officer
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By:
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/s/ H.C. Allen, Jr.
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H.C. Allen, Jr.
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Date: May 9, 2013
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Chief Financial Officer
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Number
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Description
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3.1
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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)
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3.2
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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)
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3.3
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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)
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3.4
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Amended and Restated Limited Partnership Agreement 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)
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3.5
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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)
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3.6
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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)
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3.7
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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)
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3.8
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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)
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3.9
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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)
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3.10
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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)
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31.1*
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Certification of Chief Executive Officer of the Partnership pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934
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31.2*
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Certification of Chief Financial Officer of the Partnership pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934
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32.1**
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Certification of Chief Executive Officer of the Partnership pursuant to 18 U.S.C. Sec. 1350
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32.2**
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Certification of Chief Financial Officer of the Partnership pursuant to 18 U.S.C. Sec. 1350 (contained within Exhibit 32.1 hereto)
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101.INS**
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XBRL Instance Document
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101.SCH**
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XBRL Taxonomy Extension Schema Document
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101.CAL**
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XBRL Taxonomy Extension Calculation Linkbase Document
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101.DEF**
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XBRL Taxonomy Extension Definition Document
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101.LAB**
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XBRL Taxonomy Extension Label Linkbase Document
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101.PRE**
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XBRL Taxonomy Extension Presentation Linkbase Document
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* Filed herewith
**Furnished herewith