the worldwide and domestic supplies of oil and natural gas;
the ability of the members of the Organization of Petroleum Exporting Countries and others to agree to and maintain oil prices and production controls;
● | the worldwide and domestic supplies of oil and natural gas; |
political instability or armed conflict in oil-producing regions;
● | the ability of the members of the Organization of Petroleum Exporting Countries and others to agree to and maintain oil prices and production controls; |
the price and level of foreign imports;
● | political instability or armed conflict in oil-producing regions; |
the level of consumer demand;
● | the price and level of foreign imports; |
the price and availability of alternative fuels;
● | the level of consumer demand; |
the availability of pipeline capacity;
● | the price and availability of alternative fuels; |
weather conditions;
● | the availability of pipeline capacity; |
domestic and foreign governmental regulations and taxes; and
● | weather conditions; |
the overall economic environment.
● | domestic and foreign governmental regulations and taxes; and |
● | the overall economic environment. |
experience declines in production due to depletion of their oil and natural gas reservoirs, with the rates of decline varying by property. Replacement of reserves to maintain production levels requires maintenance, development or exploration projects on existing properties, or the acquisition of additional properties.
pressure or irregularities in formations;
equipment failures or accidents;
● | pressure or irregularities in formations; |
unexpected drilling conditions;
● | equipment failures or accidents; |
shortages or delays in the delivery of equipment;
● | unexpected drilling conditions; |
adverse weather conditions; and
● | shortages or delays in the delivery of equipment; |
disputes with drill-site owners.
● | adverse weather conditions; and |
● | disputes with drill-site owners. |
to be converted into overriding royalty interests, net profits interests, or another type of interest that does not generate unrelated business taxable income. Third parties may be less likely to deal with us than with a purchaser to which such a condition would not apply. These restrictions could prevent us from pursuing or completing business opportunities that might benefit us and our unitholders, particularly unitholders who are not tax-exempt investors.
The vast majority
The vast majority
Oklahoma and Kansas, where properties that are subject to the NPIs are located, have the ability, directly or indirectly, to limit production from those properties, and such limitations or changes in those limitations could negatively impact us in the future.
Federal
issued final regulations requiring petroleum and natural gas operators meeting a certain emission threshold to report their greenhouse gas emissions to the EPA. The EPA has indicated that it will use data collected through the reporting rules to decide whether to promulgate future greenhouse gas emission limits. Although it is not possible at this time to predict whether or when Congress may act on climate change legislation, any laws or regulations that may be adopted to restrict or reduce emissions of GHGs could require the operating partnership and oil and natural gas operators that develop our properties to incur increased operating costs and could have an adverse effect on demand for the oil and natural gas produced from our properties.
challenge could result in an audit of our unitholders’ tax returns and adjustments to items on their tax returns that are unrelated to their ownership of our common units. In addition, our unitholders would bear the cost of any expenses incurred in connection with an examination of their personal tax returns.
ruling that requires a portion of the combined tax basis of all common units to be allocated to each of the common units owned by a unitholder upon a sale or disposition of less than all of the common units and may be challenged by the IRS. If such a challenge is successful, our unitholders may have to recognize more taxable income or less taxable loss with respect to common units disposed of and common units they continue to hold.
allocated to the partners that contributed the property, in proportion to their percentage interest in the contributed property, to take into account any Built-in Gain or Built-in Loss. This method of allocating Built-in Gain and Built-in Loss is not specifically permitted by United States Treasury regulations, and the IRS may challenge this method. Such a challenge, if successful, could cause our unitholders to recognize more taxable income or less taxable loss on an ongoing basis in respect of their common units.
should have been reported by such transferee. Alternatively, the IRS may contend that the transferor continues to be a partner for federal income tax purposes and that allocations of income, gain, loss or deduction by us should have been reported by such transferor. If the transferor is not treated as a partner for federal income tax purposes, any cash distributions received by such transferor with respect to the transferred units following the transfer would be fully taxable as ordinary income to the transferor.
The
could differ materially from those expressed or implied in the forward-looking statements for a number of important reasons, including those discussed under “Risk Factors”"Risk Factors" and elsewhere in this report.
Number of States Number of Counties/Parishes Gross Acres Net Acres (where applicable) State Alabama Arkansas California Colorado Florida Georgia Illinois Indiana Kansas Kentucky Louisiana Michigan Mississippi State Missouri Montana Nebraska New Mexico . New York North Dakota Oklahoma Pennsylvania . South Dakota Texas Utah Wyoming Consummated Leases Number Number of States Number of Counties Average Royalty Average Bonus, $/acre Total Lease Bonus—cash basis 2011. amounts attributable to pooling elections. Payments received for gas storage, shut-in and delay rental payments, coal royalty, surface use agreements, litigation judgments and settlement proceeds are reflected in our consolidated financial statements in various categories including, but not limited to, other operating revenues and other income. partnership. Cash received for revenue Cash paid for operating costs Cash paid for development costs Budgeted capital expenditures Net cash (paid) received Cumulative NPI Deficit 2011. The information designated as “Included in Financial Statements” and “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations” include cash payments made to us in January 2012 and their related production volumes. Natural Gas mcf Oil & Condensate bbl Indicated Gas Price, $/mcf Indicated Oil/Cond. Price, $/bbl All Proved Developed and Located in the United States Proved Reserves Natural Gas (mmcf)(1) Oil & Condensate (mbbls)(1) Future Net Revenues ($ in thousands)(1) Standardized Measure ($ in thousands)(1) Number of States Number of Counties/Parishes Gross Acres Net Acres Oklahoma Kansas Arkansas All Others Totals operating partnership participates as a working interest owner. Acquisition costs Development costs(1) Total Location Oklahoma Kansas All others Total ST Operator Well Name AR AR AR LA HA RA SUA; Collins LA 15 HZ 2-Alt MT ND ND ND ND ND OK TX TX TX TX TX TX TX TX TX TX both categories. County Well Name Conway Conway Conway Conway Conway Conway Conway Conway Faulkner Faulkner Faulkner Faulkner Faulkner Faulkner Faulkner Van Buren Van Buren Van Buren Van Buren Van Buren White White White White New Well Permits Wells Spud Wells with First Production Royalty Wells in Pay Status(1) New Well Permits Wells Spud Wells Completed Wells in Pay Status(1) Reserves Category 2010 2009 2008(2) Numbers in Thousands 2010 2009 2008 First Quarter Second Quarter Third Quarter Fourth Quarter First Quarter Second Quarter Third Quarter Fourth Quarter 2012. Total operating revenues Depreciation, depletion and amortization Net earnings Net earnings per unit (basic and diluted) Cash distributions(1) Cash distributions per unit(1) Total assets Total liabilities Partners’ capital estimates of uncollected revenues and unpaid expenses from Royalty Properties and NPIs operated by non-affiliated entities are particularly subjective due to the inability to gain accurate and timely information. Therefore, actual results could differ from those estimates. Please see “Item 1. Business—Customers and Pricing” and “Item 2. Properties—Royalty Properties” for additional discussion. Contractual Obligations Operating Lease Obligations Accrual Basis Sales Volumes: Royalty Properties Gas Sales (mmcf) Royalty Properties Oil Sales (mbbls) Net Profits Interests Gas Sales (mmcf) Net Profits Interests Oil Sales (mbbls) Accrual Basis Weighted Averages Sales Price: Royalty Properties Gas Sales ($/mcf) Royalty Properties Oil Sales ($/bbl) Net Profits Interests Gas Sales ($/mcf) Net Profits Interests Oil Sales ($/bbl) Accrual Basis Production Costs Deducted under the 2009 2009, and their subsequent development. Net Profits Interest volumes were 31 mbbls and 713 mmcf. See “Item 2 Properties – Net Profts Interest.” 2010, the Minerals NPI reaching payout in 2011, increased natural gas liquids payments and increased oil prices offset the lower 2011 natural gas prices. G&A decreased slightly in 2011 to $4,088,000. prices. EPA issued an volumes, such as production taxes, we anticipate that sufficient funds will be available at all times for payment of these expenses. Of the expenses that do not vary with oil and natural gas prices and sales volumes, most are reimbursements to our general partner for allocable general and administrative costs including home office rent, salaries, and employee benefit plans. Such reimbursements are generally limited to 5% of an amount primarily based on annual distributions to our limited partners. Historically, all such reimbursements have been substantially below the 5% limit established by the partnership agreement. Consequently, even during the 2008 economic downturn, our business risks were essentially limited to distribution amount decreases. See “Item 1. Business – Credit Facilities and Financing Plans.” See “Item 1A. Risk Factors – Risks Related to our Business – Cash distributions are affected by production and other costs, some of which are outside of our control.” See “Item 1A. Risk Factors – Risks Inherent In An Investment In Our Common Units – Cost reimbursement due our general partner may be substantial and reduce our cash available to distribute to our unitholders. " 2009. Year Record Date Payment Date January 25, 2010 February 4, 2010 April 29, 2010 May 10, 2010 August 2, 2010 August 12, 2010 October 25, 2010 November 4, 2010 Total distributions paid in 2010 January 24, 2011 February 3, 2011 4% of Net Cash Receipts from Royalty Properties 96% of Net Cash Receipts from Royalty Properties 1% of NPI Payments to our Partnership 99% of NPI Payments to our Partnership Total Distributions Operating Partnership Share (3.03% of Net Proceeds) Total General Partner Share % of Total Chief Executive Officer 23, 2012 /s/ William Casey McManemin /s/ H.C. Allen, Jr. /s/ James E. Raley /s/ Buford P. Berry /s/ Preston A. Peak /s/ C. W. Russell /s/ Ronald P. Trout /s/ Robert C. Vaughn 23, 2012 23, 2012 2010 Current assets: Cash and cash equivalents Trade and other receivables Net profits interests receivable—related party Total current assets Other non-current assets Property and leasehold improvements—at cost: Oil and natural gas properties (full cost method) Accumulated full cost depletion Total Leasehold improvements Accumulated amortization Total Net property and leasehold improvements Total assets Current liabilities: Accounts payable and other current liabilities Current portion of deferred rent incentive Total current liabilities Deferred rent incentive less current portion Total liabilities Commitments and contingencies (Note 4) Partnership capital: General partner Unitholders Total partnership capital Total liabilities and partnership capital Operating revenues: Royalties Net profits interests Lease bonus Other Total operating revenues Costs and expenses: Production taxes Operating expenses Depreciation, depletion and amortization General and administrative expenses Total costs and expenses Operating income Other income, net Net earnings Allocation of net earnings: General Partner Unitholders Net earnings per common unit (basic and diluted) Weighted average common units outstanding (000’s) 2009 Cash flows from operating activities: Net earnings Adjustments to reconcile net earnings to net cash provided by operating activities: Depreciation, depletion and amortization Write-off related to unsuccessful acquisition Amortization of deferred rent Changes in operating assets and liabilities: Trade and other receivables Net profits interests receivable – related party Accounts payable and other current liabilities Net cash provided by operating activities Cash flows from investing activities: Adjustment related to acquisition of natural gas properties Capital expenditures Net cash provided by (used in) investing activities Cash flows from financing activities: Distributions paid to partners Increase (decrease) in cash and cash equivalents Cash and cash equivalents at beginning of year Cash and cash equivalents at end of year Non-Cash investing and financing activities Value of units issued for natural gas properties acquired 2009 Year 2008 Balance at January 1, 2008 Net earnings Distributions ($2.804603 per Unit) Balance at December 31, 2008 2009 Net earnings Acquisition of assets for units Distributions ($1.501608 per Unit) Balance at December 31, 2009 2010 Net earnings Acquisition of assets for units Distributions ($1.65405 per Unit) Balance at December 31, 2010 accounts and do not believe we are exposed to any significant risk on cash and cash equivalents. Short term investments with a maturity of three months or less are considered to be cash equivalents and are carried at cost, which approximates fair value. Other income includes interest earned on short term investments of $200, $1,000, and $14,000 in 2011, 2010, and 2009. Leasehold improvements include $415,000 received in 2004 as an incentive in our office space lease and is offset in liabilities as deferred rent. Leasehold improvements are amortized over the shorter of their estimated useful lives or the related lease life of 10 years. For leases with renewal periods at the Partnership’s option, we have used the original lease term, excluding renewal option periods to determine useful life. Deferred rent incentive is being amortized to general and administrative expense over the same term as the leasehold improvements, which is 10 years. From/To Operating Partnership Net Profits Interests Payments Receivable or Accrued(1) Interest Income related to Net Profits Interests Payments General & Administrative Amounts Payable General & Administrative Amounts Accrued Total General & Administrative Amounts (1) formerly owned by Dorchester Hugoton. These properties contribute a Years Ended December 31, 2011 2012 2013 2014 2015 Total First Quarter Second Quarter Third Quarter Fourth Quarter 2009 Estimated quantity, beginning of year Purchase of minerals in place Revisions in previous estimates Production Estimated quantity, end of year Future estimated gross revenues Future estimated production costs Future estimated net revenues 10% annual discount for estimated timing of cash flows Standardized measure of discounted future estimated net cash flows Sales of oil and natural gas produced, net of production costs Purchase of reserves in place Net changes in prices and production costs Revisions of previous quantity estimates Accretion of discount Change in production rate and other Net change in standardized measure of discounted future estimated net cash flows Depletion of oil and natural gas properties (dollars per mcfe) Property acquisition costs Average oil price per barrel(2) Average natural gas price per mcf(2) Includes Royalty and NPI prices combined by volumetric Total operating revenues Net earnings Net earnings per Unit (basic and diluted) Weighted average common units outstanding2010,2011, a summary of our gross and net acres, where applicable, acres of mineral, royalty, overriding royalty and leasehold interests, and a compilation of the number of counties and parishes and states in which these interests are located. The majority of our net mineral acres are unleased. Acreage amounts may not add across due to overlapping ownership among categories. Mineral Royalty Overriding
Royalty Leasehold Total 25 17 17 8 25 465 190 137 34 574 2,308,024 616,541 208,755 36,527 3,119,528 377,707 — — — 377,707 Mineral Royalty Leasehold Total Number of States 25 18 17 8 25 Number of Counties/Parishes 465 190 137 34 574 Gross Acres 2,308,000 617,000 209,000 36,000 3,119,000 Net Acres (where applicable) 378,000 — — — 378,000 2010,2011, the combined summary of total gross and net (where applicable) acres, where applicable, of mineral, royalty, overriding royalty and leasehold interests in each of the states in which these interests are located. Gross Net 105,192 7,794 47,219 15,646 1,451 162 22,880 1,424 88,832 25,267 3,676 1,285 4,729 885 303 142 13,981 2,388 1,995 678 131,075 2,520 54,234 2,623 72,026 8,622 Gross Net 344 43 281,890 62,850 3,360 287 42,410 2,814 23,077 18,863 292,771 46,073 230,400 16,973 9,513 5,631 14,407 1,266 1,641,199 151,955 5,937 200 26,627 1,316 State State Gross Alabama 105,000 8,000 Missouri 1,000 < 500 Arkansas 47,000 16,000 Montana 282,000 63,000 California 1,000 < 500 Nebraska 3,000 < 500 Colorado 23,000 1,000 New Mexico 42,000 3,000 Florida 89,000 25,000 New York 23,000 19,000 Georgia 4,000 1,000 North Dakota 293,000 46,000 Illinois 5,000 1,000 Oklahoma 230,000 17,000 Indiana < 500 < 500 Pennsylvania 10,000 6,000 Kansas 14,000 2,000 South Dakota 14,000 1,000 Kentucky 2,000 1,000 Texas 1,641,000 152,000 Louisiana 131,000 3,000 Utah 6,000 < 500 Michigan 54,000 3,000 Wyoming 27,000 1,000 Mississippi 72,000 9,000 (1) < 500 means acreage owned did not round up to 1,000. $3,862,000$571,000 during 20102011 attributable to lease bonus on 9728 leases and six14 pooling elections in lands located in 3226 counties and parishes in eightseven states. These leases reflected bonus payments ranging up to $5,010/$2,500/acre and initial royalty terms ranging up to 26%.$22,000$167,000 during the fourth quarter of 20102011 attributable to lease bonus on nineeight leases and three pooling elections of our interests in lands located in fivenine counties and parishes in fourfive states. These leases reflected bonus payments ranging up to $2,000/$1,100/acre and initial royalty terms ranging up to 25%.20082009 through 2010. 2010 2009 2008 103 53 51 8 4 4 32 22 19 24.8 % 23.4 % 25.0 % $ 1,705 $ 565 $ 398 $ 3,862,000 $ 663,000 $ 441,000 Consummated Leases 2011 2010 2009 Number 42 103 53 Number of States 7 8 4 Number of Counties 26 32 22 Average Royalty 26 % 24.8 % 23.4 % Average Bonus, $/acre $ 472 $ 1,705 $ 565 Total Lease Bonus – cash basis $ 571,000 $ 3,862,000 $ 663,000 month’smonth's calculation of net profit.separate NPIs. FourThe Minerals NPI (one of the six) owns certain cost bearing interests that were either in existence at the time of our formation, or created in connectionsubsequent to our formation but associated with the combination in 2003, one immaterial Net Profits Interest was subsequently creatednonproducing mineral, royalty and is currently in deficit, and one wasleasehold interest properties acquired with the acquisition of Maecenasupon our formation. The Minerals LLP on March 31, 2010. Four of these NPIs have been inNPI recently achieved a continuouscumulative net profit status other than temporary deficits in that revenues have exceeded costs and cash payments have been made by the operating partnership to us each quarter. The purpose of such NPIs is to avoid the 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. The Net Profits Interest referred to as the Minerals NPI has continuously had costs that exceed revenues. As of December 31, 2010,its cumulative net revenue exceeding cumulative operating and actual and budgeted capital expenditures and development costs presented in the following table, which include amounts equivalent to an interest charge, exceededcosts. Through November 30, 2011, cumulative revenues of the Minerals NPI,net profit was approximately $1,347,000, resulting in a cumulative deficit. All cumulative deficits (which represent cumulative excessNPI payments of operating and development costs over revenue received) are borne 100% by our generalapproximately $1,306,000 to us during the fourth quarter of 2011. Our fourth quarter limited partner until the Minerals NPI recovers the deficit amount. Once in profit status, we will receive the Net Profits Interest payments attributable to these properties.distribution included this payment. Our consolidated financial statements do not reflect activity attributable to properties subject to NPIs that are in a deficit status.Consequently, net profits interest payments, production sales volumes and prices, and oil and natural gas reserves set forth in other portions of this annual report do not reflect amounts attributable to the Minerals NPI which includes alland include a portion of 2011 cash receipts and disbursements and accrued revenues and costs not yet received or paid. 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, consolidated financial statements reflect activity attributable to the Minerals NPI, and will continue to do so regardless of its net profit status on a cumulative or reporting period basis. As of December 31, 2011 each of the six NPIs has cumulative revenue that exceeds cumulative costs, such excess constituting net proceeds on which NPI payments are 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’s Fayetteville Shale working interest properties in Arkansas.20052006 and the calendar years 20062007 through 2010. Minerals NPI Cash Basis Results
Year Ended December 31,
(in Thousands) Inception
Through
2005 2006 2007 2008 2009 2010 Total $ 2,458 $ 2,487 $ 3,255 $ 6,016 $ 3,408 $ 7,901 $ 25,525 400 452 521 853 865 1,732 4,823 2,620 1,691 2,635 4,778 4,348 3,249 19,321 905 890 2,630 4,425 $ (562 ) $ 344 $ 99 $ (520 ) $ (2,695 ) $ 290 $ (3,044 ) $ (562 ) $ (218 ) $ (119 ) $ (639 ) $ (3,334 ) $ (3,044 ) Minerals NPI Cash Basis Results Year Ended December 31, (in Thousands) 2007 2008 2009 2010 2011 Total Cash received for revenue $ 4,945 $ 3,255 $ 6,016 $ 3,408 $ 7,901 $ 11,783 $ 37,308 Cash paid for operating costs 852 521 853 865 1,732 2,055 6,878 Cash paid for development costs 4,311 2,635 4,778 4,348 3,249 5,072 24,393 Budgeted capital expenditures 905 890 2,630 (78 ) 4,347 Net cash (paid) received $ (218 ) $ 99 $ (520 ) $ (2,695 ) $ 290 $ 4,734 $ 1,690 Cumulative NPI (Deficit) Profit $ (218 ) $ (119 ) $ (639 ) $ (3,334 ) $ (3,044 ) $ 1,690 Included in net profits interests revenue on financial statements $ 1,639 $ 1,639 Minerals NPI Cash Basis Production
Year ended December 31, Inception
through
2005 2006 2007 2008 2009 2010 Total 264,824 190,903 291,278 418,743 596,341 957,176 2,719,265 14,549 17,447 19,662 22,480 21,104 53,369 148,611 $ 7.26 $ 6.58 $ 8.55 $ 3.74 $ 4.13 $ 5.45 $ 61.05 $ 62.93 $ 100.98 $ 48.80 $ 71.52 $ 68.08 Minerals NPI Cash Basis Production Year ended December 31, Inception through 2006 2007 2008 2009 2010 Total Natural Gas mcf 455,727 291,278 418,743 596,341 957,176 1,305,895 4,025,160 Oil & Condensate bbl 31,996 19,662 22,480 21,104 53,369 73,792 222,403 Indicated Gas Price, $/mcf $ 6.58 $ 8.55 $ 3.74 $ 4.13 $ 3.58 $ 4.84 Indicated Oil/Cond. Price, $/bbl $ 62.93 $ 100.98 $ 48.80 $ 71.52 $ 88.43 $ 74.83 (1) Cash sales volumes above include 512,367 mcf of natural gas and 21,636 bbls of oil & condensate also included in our Results of Operations. Minerals NPI Reserves
Year ended December 31, 2004 2005 2006 2007 2008 2009 2010 273 313 532 1,442 1,993 3,016 4,260 7 32 46 34 65 65 178 $ 1,352 $ 3,399 $ 4,309 $ 10,523 $ 9,341 $ 8,950 $ 30,353 $ 1,033 $ 2,655 $ 3,405 $ 7,253 $ 6,533 $ 6,451 $ 14,025 Year ended December 31, 2004 2005 2006 2007 2008 2009 2010 2011 Proved Reserves 273 313 532 1,442 1,993 3,016 4,260 6,072 7 32 46 34 65 65 178 230 $ 1,352 $ 3,399 $ 4,309 $ 10,523 $ 9,341 $ 8,950 $ 30,353 $ 43,089 $ 1,033 $ 2,655 $ 3,405 $ 7,253 $ 6,533 $ 6,451 $ 14,025 $ 29,210 (1)(3) Based on 12-month unweighted arithmetic average of the first day-of-the-month price of oil and natural gas in 2009 forward, otherwise based on year-end pricing of oil and natural gas will equal 96.97% of the cumulative net profits actually received by the operating partnership attributable to the subject properties. The above production sales volumes, indicated prices, oil and natural gas reserves, and financial information attributable to the Minerals NPI may not be indicative of future results of the Minerals NPI and may not indicate when the deficit status may end and when NPI payments may begin from the Minerals NPI.The Minerals NPI includes numerous opportunities for the operating partnership to participate as a working interest owner in drilling activity on lands in which we owned a mineral or royalty interest as of the date such Minerals NPI was created. Most of these opportunities are evidenced by a contractual option, but not the obligation, to participate in activity located in defined lands and leases, although some arise by non-contractual means or by operation of law. With regard to the opportunities evidenced by a contractual option, the operating partnership’s decision to exercise these options and participate as a working interest owner is made on a well-by-well basis and only in the event a third party proposes to drill a well subject to the contractual option. With regard to the opportunities to participate as a working interest owner that arise non-contractually or by operation of law, we obtain or are provided those opportunities due to the actions of persons that we do not control. Thus, we are unable to project when wells may be drilled, whether the operating partnership may elect to participate, or otherwise end up participating, in such drilling or the magnitude of the corresponding investment, either individually or in the aggregate, with respect to the Minerals NPI. In the event the operating partnershipdoes elect to participate pursuant to these options, or otherwise ends up so participating per force of certain non-contractual relationships or by operation of law, the Minerals NPI deficit balance is likely to increase. Regardless of the operating partnership’s future voluntary or involuntary participation, we believe initial net profits interest payments made upon the Minerals NPI’s first reaching profit status, if any, will be insignificant due to our expectation that the operating partnership will continue to incur development expenditures for at least the next five years. See the discussion under “Drilling Activity” below for additional information on some of these working interest participation options and possibilities.2010,2011, information concerning properties owned by the operating partnership and subject to the NPIs, including the Minerals NPI properties. Acreage amounts listed under “Leasehold” reflect gross acres leased by the operating partnership and the working interest share (net acres) in those properties. Acreage amounts listed under “Mineral” reflect gross acres in which the operating partnership owns a mineral interest and the undivided mineral interest (net acres) in those properties. The operating partnership’spartnership's interest in these properties may be unleased, leased by others or a combination thereof. Acreage amounts may not add across due to overlapping ownership among categories. In addition to amounts listed below, the operating partnership owns interests limited to certain wellbores located on lands in which we own mineral, royalty or leasehold interests. The acreage amounts associated with the wellbore interests are included in Royalty Properties Acreage Summary and not in the table below. Mineral Royalty Leasehold Total 12 2 6 12 60 2 13 66 49,188 640 110,673 160,501 7,260 — 84,272 91,532 Mineral Royalty Leasehold Total Number of States 12 2 7 13 Number of Counties/Parishes 60 2 13 65 Gross Acres 49,000 1,000 98,000 148,000 Net Acres 6,000 82,000 88,000 Mineral/Royalty Leasehold Total Gross Net Gross Net Gross Net 11,200 955 80,181 74,056 91,381 75,011 640 20 7,035 7,035 7,675 7,055 679 308 19,787 2,637 20,466 2,945 37,309 5,977 3,670 544 40,979 6,521 49,828 7,260 110,673 84,272 160,501 91,532 Mineral/Royalty Leasehold Total Gross Gross Gross Net Oklahoma 12,000 1,000 80,000 74,000 92,000 75,000 Kansas 1,000 < 500 7,000 7,000 7,000 7,000 Arkansas 1,000 < 500 8,000 1,000 9,000 1,000 All Others 37,000 5,000 3,000 < 500 40,000 5,000 Totals 50,000 6,000 98,000 82,000 148,000 88,000 (1) < 500 means acreage owned did not round up to 1,000. of Arkansas in which we have the right to participate. Years ended December 31, 2010 2009 2008 (in thousands) $ — $ — $ — 3,268 4,377 5,315 $ 3,268 $ 4,377 $ 5,315 Years ended December 31, 2011 2010 2009 (in thousands) Acquisition costs $ — $ — $ — 5,658 3,268 4,377 Total $ 5,658 $ 3,268 $ 4,377 (1) The years ended December 31, 2008, 2009, 2010 and 20102011 include $4,793,000, $4,348,000, $3,249,000 and $3,249,000,$4,362,000, respectively, attributable to NPIs not yet inbefore reaching pay status.2010,2011, the combined number of producing wells on the properties subject to the NPIs, including the Minerals NPI. Gross wells refer to wells in which a working interest is owned. Net wells are determined by multiplying gross wells by the working interest in those wells. Productive
Wells/Units(1) Gross Net 201 120.3 20 20.0 323 15.3 544 155.6 Location Gross Net 199 120.2 20 20.0 345 16.3 564 156.5 (1) Multiple well units operated by someone other than the operating partnership and in which we own NPIs are included as one gross well. Weor otherwise identified 348356 new wells completed on our Royalty Properties in 109 states, during 2010. Fifty-sevenand 66 new wells were completed on our NPI propertiesProperties in 2010. We identified eight4 states. Included in these totals are 14 wells that were completed in prior years,one state in which we own both a royalty interest and an additional 20 wells werea net profits interest. Wells with such overlapping interests are counted in various stages of drilling or completion operations at year-end. Selected new wells and the royalty interests owned by us and the working and net revenue interests owned by the operating partnership are summarized below.This table does not include wells drilled in the Fayetteville Shale trend as they are detailed in a subsequent discussion and table. DMLP
NRI(2) DMOLP Test Rates per day County/
Parish WI(1) NRI(2) Gas,
mcf Oil,
bbls Logan Highland Oil & Gas Gregory #4 3.125 % 3.125 % 1,355 Logan SEECO Johns #2-4H3 3.084 % 3.084 % 11,289 Logan Highland Oil & Gas Morris #2 3.125 % 3.125 % 1,359 De Soto Comstock Oil & Gas 2.734 % 2,033 Richland Continental Resources Carda #3-28H 6.250 % 5.938 % 91 226 Dunn ConocoPhillips Intervale 41-35H 3.728 % 257 823 Mountrail Fidelity Expl & Prod Deadwood Canyon Ranch 11-33H 0.999 % 707 777 Mountrail Fidelity Expl & Prod Deadwood Canyon Ranch 44-32H 1.038 % 706 904 Mountrail Fidelity Expl & Prod Deadwood Canyon Ranch 44-34H 2.011 % 636 997 Williams Brigham Oil & Gas Owan-Nehring 27-34 1H 0.306 % 1,787 2,215 Caddo St. Mary Land & Expl. Reiss Trust #1-16 1.319 % 1.319 % 8,496 Crockett Walter Oil & Gas Corp. Elliott, M #2H 3.301 % 3.301 % 1,265 Dawson Fasken Oil and Ranch Jacksonville College “9” #1 6.250 % 73 147 Hidalgo Shell Expl & Prod Woods Christian #48 2.734 % 1,518 San Jacinto Famcor Oil, Inc. Vann #3 2.500 % 1,700 Starr RAM Operating Garza Hitchcock #19 2.653 % 2,187 Starr Cactus Rose, LLC Guerra #2 7.041 % 197 Tarrant Chesapeake Operating Duck Lake #8H 17.063 % 3,971 Tarrant Chesapeake Operating Duck Lake #10H 17.063 % 3,456 Tarrant Chesapeake Operating Duck Lake #11H 17.063 % 3,507 Wood Energy Prod Corp. SASI Ranch #2 SX 3.223 % 115 421 (1)WI means the working interest owned by the operating partnership and subject to the Net Profits Interest.(2)NRI means the net revenue interest attributable to our royalty interest or to the operating partnership’s royalty and working interest, which is subject to the Net Profits Interest.— – 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. TwoThree hundred eighty-ninefifty-nine wells have beenwere permitted on the lands as of December 31, 2010,2011, 218 of which the operating partnership hasowns an interest in 182.interest. In total, 254343 wells had beenwere spud, 219 had been315 were completed as producers, and 2021 were in various stages of drilling or completion operations. Wells that have been proposedoperations or waiting on a pipeline, and seven wells were abandoned. Leases covering approximately 10,722/5,310 gross/net acres expired on June 27, 2011. We are currently determining the best course of action with regards to be drilledleasing or participating with the unleased acreage. Approximately 8,933/4,448 gross/net acres are held by the operator but for which permits have not yet been issued by the Arkansas Oil & Gas Commission are not reflected in this number. Available test results for wells completed in 2010, along with ownership interests owned by us and interests owned by the operating partnership subject to the Minerals NPI, are summarized in the following table.production. DMLP
NRI(2) DMOLP Gas Test Rates
Mcf per day Operator WI(1) NRI(2) SEECO Bryant 9-15 #5-32H30 4.793 % 4.722 % 3.579 % 5,385 SEECO Criswell 8-14 #2-29H 1.563 % 1.250 % 0.938 % 4,627 Chesapeake Operating Georgia Brown 8-16 #1-36H 5.859 % 5.100 % 3.830 % 2,725 Chesapeake Operating Govan 7-15 #1-6H 2.263 % 4.237 % 3.187 % 4,015 SEECO Howell 7-16 #1-1H 2.354 % 4.394 % 3.295 % 3,878 Chesapeake Operating Merideth 7-16 #2-2H 0.781 % 7,257 SEECO Polk 9-15 #5-30H 5.930 % 5.561 % 4.245 % 3,334 SEECO William Gray 7-15 #1-18H 0.781 % 6,487 SEECO Krisell Trust 7-14 #1-3H 2.340 % 4.758 % 3.576 % 6,451 Chesapeake Operating Lagasse Investments Inc. 8-12 #1-8H 7.617 % 5.000 % 3.750 % 1,559 Chesapeake Operating Lagasse Investments Inc. 8-12 #2-8H 7.617 % 1,823 Chesapeake Operating Lagasse Investments Inc. 8-12 #3-8H 7.617 % 2,096 Chesapeake Operating Lane 8-12 #1-8H 7.617 % 5.000 % 3.750 % 1,018 Chesapeake Operating Lane 8-12 #2-8H 7.617 % 5.000 % 3.750 % 1,842 SEECO Ralph Taylor 8-12 #1-20H 2.461 % 4.844 % 3.633 % 1,879 SEECO Alice Mobbs 10-13 #1-19H 1.552 % 1.242 % 0.931 % 6,950 SEECO Betty Graddy Trust 10-12 #7-15H16 1.479 % 2.366 % 1.775 % 4,267 SEECO David Brown 9-13 #3-13H24 0.918 % 1.486 % 1.119 % 5,242 SEECO Hillis 10-16 #5-27H 6.250 % 6.250 % 1,853 XTO Energy Roe Reynolds 9-12 #1-27H22 3.105 % 3.312 % 2.484 % 2,015 SEECO Riley 9-6 #1-22H 3.125 % 5.000 % 3.750 % 1,716 SEECO Riley 9-6 #3-22H15 2.649 % 4.238 % 3.179 % 4,359 SEECO Riley 9-6 #4-22H15 2.508 % 4.014 % 3.010 % 4,352 SEECO Riley 9-6 #5-22H15 2.676 % 4.282 % 3.212 % 3,413 (1)WI means the working interest owned by the operating partnership and subject to the Minerals NPI.(2)NRI means the net revenue interest attributable to our royalty interest or to the operating partnership’s royalty and working interest, which is subject to the Minerals NPI.20102011 for wells in which we have a royalty or Net Profits Interest. This includes wells subject to the Minerals NPI and wells for which is currently in deficit status. 2004
through
2007 2008 2009 Q1
2010 Q2
2010 Q3
2010 Q4
2010 Total
to
Date 47 66 69 23 19 31 34 289 41 62 70 23 15 26 17 254 27 53 49 13 33 18 26 219 6 30 54 10 14 20 25 159 2004 through 2008 2009 2010 Q1 2011 Q2 2011 Q3 2011 Q4 2011 Total to Date 113 68 110 23 17 17 11 359 Wells Spud 103 70 88 21 28 26 7 343 81 49 88 29 18 17 33 315 36 55 70 22 17 16 9 225 (1) Excludes permits that expire undrilled (2) Completion date is defined as the day the well commences production. (3) Wells in Pay Status means wells for which revenue was initially received during the indicated period.period2010,2011, include reserves attributable to our royalty interest in 195267 wells totaling 4.055.82 bcf. Proved reserves attributable to working interests owned by the operating partnership totaled 3.745.46 bcf in 127178 wells. These estimates only include wells for which test rates have been obtained.$2,609,000$3,933,000 in 20102011 from 159228 wells. Net cash receipts for the Minerals NPI properties attributable to interests in these lands totaled $2,458,000$3,638,000 in 20102011 from 85146 wells. Fourth quarter net cash receipts for the Royalty Properties and the Minerals NPI properties totaled $706,000$994,000 from 158228 wells and $578,000$1,389,000 from 83144 wells, respectively.— – We own varying undivided perpetual mineral interests totaling 70,390/8,905 gross/net acres located in Burke, Divide, Dunn, McKenzie, Mountrail and Williams Counties, North Dakota. Operators active in this area include Brigham Oil & Gas, Continental Resources, EOG Resources, Hess Corporation, Marathon Oil Company, and Whiting Oil & Gas. There have been a total of 62One hundred eighty four wells were permitted on these lands as of December 31, 20102011, with 97136 completed as producers. In virtually allmost cases we have elected not to lease our lands and not to pay our share of well costs, thus becomingbecome a non-consenting mineral owner.owner—who is not obligated to pay well costs. According to North Dakota law, non-consenting mineral owners receive the average royalty rate from the date of first production and back-in for their full working interest after the operator has recovered 150% of drilling and completion costs. Once 150% payout occurs, the working interest will be owned by the operating partnership andwill then own the working interest; subject to the Minerals NPI.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 December 31, 2010, six2011, 11 of these wells had achieved 150% payout.20102011 for wells in which we haveown a royalty or Net Profits Interest. This includes wells subject to the Minerals NPI, which is currently in a deficit status. 2004
through
2007 2008 2009 Q1
2010 Q2
2010 Q3
2010 Q4
2010 Total
to
Date 17 45 22 6 18 6 18 132 14 26 31 7 16 12 9 115 9 22 32 9 6 12 7 97 0 3 1 1 0 1 0 6 2009 2010 Q1 2011 Q2 2011 Q3 2011 Q4 2011 Total to Date New Well Permits 61 23 57 11 16 13 3 184 Wells Spud 39 30 43 18 14 19 15 178 Wells Completed 31 31 37 8 10 13 6 136 3 1 4 0 1 1 1 11 (1)in Pay Statusreaching 150% Payout means wells for which revenue was initially receivedthe 150% penalty has been recovered during the indicated period.period.— – 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 thesethose net acres are located in eastern Allegany and western Steuben Counties, New York, York—an area whichthat some industry press reports suggest may be prospective for gas production from unconventional reservoirs, including the Marcellus Shale. The New York State Department of Environmental Conservation has restricted permitting in the Marcellus shale pending acompleted its regulatory review of high-volume hydraulic fracturing practices. Developmentpractices; however, development of these natural gas resources will be limited until thisremaining regulatory issue has beenissues 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.— – We own producing and nonproducing mineral and royalty interests located in Tarrant County, Texas. The properties consist of varying undivided mineral and overriding royalty interests in six tracts totaling approximately 1,820 acres located in what isTarrant County, Texas in an area commonly referred to as the Core Area of the Barnett Shale Trend. All of the mineral interests were leased in 2003 to a predecessor of Chesapeake Energy Corporation, the current operator of and majority working interest owner in the properties. Approximately 577 acres of the subject lands are pooled into six units totaling 1,800 acres; approximately 1,129 acres are developed on a lease basis and the remaining lands are leased but not pooled or drilled upon. As of December 31, 2010, 402011, 43 wells were drilled, from11 padsites located on or adjacent to the properties, of which 3242 wells were completed for production and eight wereone was drilled but not yet completed or connected to a pipeline. PermitsNo new permits to drill four additional wells on the properties hadhave been issued by regulatory agencies.Granite Wash, Texas Panhandle— Nine wells were brought on production during 2011, with an average reported test rate of 3.4 mmcfd. We own varying undivided perpetual mineral interests totaling 16,336/2,559 gross/net acresranging from 17.1% to 20.0% NRI in Hemphill, Roberts and Wheeler Counties, Texas. Operators active in this area include Apache Corporation, Chesapeake Operating, Forest Oil, Linn Energy, Newfield Exploration, and QEP Resources. In 2010, we leased 680 net acres to two parties in two transactions for 25% royalty and total bonus consideration of $2,892,560. As of December 31, 2010, two horizontal well permits had been granted on the leased lands.these wells.Partnership’sPartnership's proved developed and total proved reserves at December 31, 2010.2011. The reserves are based on the reports of two independent petroleum engineering consulting firms: Calhoun, Blair & Associates and LaRoche Petroleum Consultants, Ltd. As described above, the Partnership does not have information that would be available to a company with oil and natural gas operations because detailed information is not generally available to owners of royalty interests. The Partnership’s engineering managerVice President of Operations (“VP”) gathers production information and provides such information to our two independent engineering consulting firms who extrapolate from such information estimates of the reserves attributable to the Royalty Properties and NPIs based on their expertise in the oil and natural gas fields where the Royalty Properties and NPIs are situated, as well as publicly available information. Ensuring compliance with generally accepted petroleum engineering and evaluation methods and procedures is the responsibility of the Partnership’s engineering manager.VP. Our engineering managerVP has a bachelor’s degree in Petroleum Engineering from the University of Alberta, and has worked in the upstream oil and natural gas business in various capacities since 1996. The engineering managerVP reports directly to the chief executive officer.Chief Executive Officer (“CEO”). Our chief executive officerCEO ensures compliance with SEC guidance. HeOur CEO received his Bachelor of Science degree in Petroleum Engineering from Texas A&M University in 1984, and has been a Registered Professional Engineer in Texas since 1988. Calhoun Blair & Associates is registered with the Engineering Board of the State of Texas, and has been engaged in the business of oil and natural gas property evaluation since 1998. LaRoche Petroleum Consultants, Ltd. is registered with the Engineering Board of the State of Texas. The LaRoche Firmfirm has been engaged in the business of oil and natural gas property evaluation since its formation in 1979. Other than those filedour filings with the SEC, ourwe have not filed the estimated proved reserves have not been filed with, or included them in any reports to, any federal agency. Copies of the reports prepared by Calhoun, Blair & Associates and LaRoche Petroleum Consultants, Ltd. are attached hereto as Exhibits 99.1 and 99.2.Summary of Oil and Gas Reserves as of Fiscal Year-End All Proved Developed and located
in the United States Royalty Properties Net Profits Interests(1) Total Oil
(mbbls) Natural
Gas
(mmcf) Oil
(mbbls) Natural
Gas
(mmcf) Oil
(mbbls) Natural
Gas
(mmcf) 3,290 36,931 43 24,748 3,333 61,679 3,237 34,923 40 25,357 3,277 60,280 3,514 32,028 56 28,949 3,570 60,977 Summary of Oil and Gas Reserves as of Fiscal Year-End All Proved Developed and located in the United States Royalty Properties Total Year 2011 3,310 38,940 256 28,023 3,566 66,963 2010 3,290 36,931 43 24,748 3,333 61,679 2009 3,237 34,923 40 25,357 3,277 60,280 (1) Reserves reflect 96.97% of the corresponding amounts assigned to the operating partnership’s interests in the properties underlying the Net Profits Interests. (2)Based on year-end oil and natural gas pricesthe estimatedthose quantities of crude oil natural gas, and natural gas, liquids which, geologicalby analysis of geoscience and engineering data, demonstratecan be estimated with reasonable certainty to be recoverable in futureyearseconomically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and operating conditions, i.e., 12 month unweighted arithmetic averagegovernmental regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the first day ofestimation. The project to extract the month prices and costs as ofhydrocarbons must have commenced or the dateoperator must be reasonably certain that it will commence the estimate is made. Previously, year-end pricing and costs were used.project within a reasonable time. Please see “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations—Operations – Results of OperationsOperations” for average sales prices.Production by Significant Field MCF BOE 3,656 609 3,945 658 4,240 707 Production by Significant Field Oil bbls Gas mcf boe 2011 — 3,444,000 574,000 2010 — 3,656,000 609,000 2009 — 3,945,000 658,000 ITEM 3.LEGAL PROCEEDINGSmajorsignificant portion of the NPI amounts paid to us. On April 9, 2007, plaintiffs, for immaterial costs, dismissed with prejudice all claims against the operating partnership regarding such residential gas use. On October 4, 2004, the plaintiffs filed severed claims against the operating partnership regarding royalty underpayments, which the Texas County District Court subsequently dismissed with a grant of time to replead. On January 27, 2006, one of the original plaintiffs again sued the operating partnership for underpayment of royalty, seeking class action certification. On October 1, 2007, the Texas County District Court granted the operating partnership’s motion for summary judgment finding no royalty underpayments. Subsequently, the District Court denied the plaintiff’s motion for reconsideration, and the plaintiff filed an appeal. On March 31, 2010, the appeal decision reversed and remanded to the Texas County District Court to resolve material issues of fact. On June 30, 2011, the District Court issued a revised partial summary judgment in favor of the operating partnership. A hearing regarding the requested class action certification is set for late July, 2011. No court hearing has been scheduled on the merits.claim of underpayment of royalty remains pending. An adverse decision could reduce amounts we receive from the NPIs.ITEM 4.[REMOVED AND RESERVED]ITEM 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES The information below reflects inter-dealer prices without retail mark-up, mark-down or commission and may not necessarily represent actual transactions. 2010 2009 High Low High Low $ 23.86 $ 20.50 $ 20.40 $ 14.37 $ 28.15 $ 21.04 $ 23.03 $ 16.05 $ 27.30 $ 23.66 $ 25.78 $ 21.06 $ 29.42 $ 25.00 $ 23.85 $ 20.01 2011 2010 High Low High Low $ 29.25 $ 25.90 $ 23.86 $ 20.50 $ 30.09 $ 25.18 $ 28.15 $ 21.04 $ 28.29 $ 20.81 $ 27.30 $ 23.66 $ 25.76 $ 21.76 $ 29.42 $ 25.00 2010,2011, there were 14,77716,436 common unitholders. Per Unit Amount 2010 2009 2008 2007 $ 0.449222 $ 0.401205 $ 0.572300 $ 0.461146 $ 0.412207 $ 0.271354 $ 0.769206 $ 0.473745 $ 0.471081 $ 0.286968 $ 0.948472 $ 0.560502 $ 0.354074 $ 0.321540 $ 0.542081 $ 0.514625 Per Unit Amount 2011 2010 2009 2008 $ 0.426745 $ 0.449222 $ 0.401205 $ 0.572300 $ 0.417027 $ 0.412207 $ 0.271354 $ 0.769206 $ 0.455546 $ 0.471081 $ 0.286968 $ 0.948472 $ 0.448553 $ 0.354074 $ 0.321540 $ 0.542081 2011.“Fourth"Fourth Quarter 20102011 Distribution Indicated Price”Price" discussion contained in “Item 7.—Management’s -- Management's Discussion and Analysis of Financial Condition and Results of Operations—Operations -- Liquidity and Capital Resources—Resources -- Distributions” for production periods and cash receipts and weighted average prices corresponding to the fourth quarter 20102011 distribution.20052006 through December 31, 2010.2011. The graph assumes that at the beginning of the period, $100 was invested in each of (1) our common units, (2) the NASDAQ Index, and (3) the peer group, and that all distributions or dividends were reinvested. We do not believe that any published industry or line-of-business index accurately reflects our business. Accordingly, we have created a special peer group index consisting of companies whose royalty trust units are publicly traded on the New York Stock Exchange. Our peer group index includes the units of the following companies: Cross Timbers Royalty Trust, Mesa Royalty Trust, Sabine Royalty Trust, Permian Basin Royalty Trust, Hugoton Royalty Trust and the San Juan Basin Royalty Trust.
ITEM 6.SELECTED CONSOLIDATED FINANCIAL DATA Fiscal Year Ended December 31,
(in thousands, except per unit data) 2010 2009 2008 2007 2006 $ 61,094 $ 43,631 $ 89,925 $ 65,365 $ 74,927 17,988 15,599 14,739 15,567 18,470 34,883 21,681 66,783 43,048 50,210 1.11 0.72 2.30 1.48 1.72 52,198 44,728 81,648 57,401 82,295 1.65 1.50 2.80 1.97 2.83 153,111 152,768 139,562 154,251 168,429 710 737 980 804 629 152,401 152,031 138,582 153,447 167,800 2011 2010 2009 2008 2007 $ 69,489 $ 61,094 $ 43,631 $ 89,925 $ 65,365 Depreciation, depletion and amortization 18,348 17,988 15,599 14,739 15,567 42,215 34,883 21,681 66,783 43,048 Net income per unit (basic and diluted) 1.33 1.11 0.72 2.30 1.48 52,505 52,198 44,728 81,648 57,401 1.65 1.65 1.50 2.80 1.97 142,769 153,111 152,768 139,562 154,251 658 710 737 980 804 142,111 152,401 152,031 138,582 153,447 (1) Because of depletion (which is usually higher in the early years of production), a portion of every distribution of revenues from properties represents a return of a limited partner’spartner's original investment. Until a limited partner receives cash distributions equal to his original investment, in certain circumstances, 100% of such distributions may be deemed to be a return of capital. Cash distributions by year exclude the fourth quarter distribution declared in January of the following year, but include the prior year fourth quarter distribution declared in January of the current year.ITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS201020102011 were strong despite continued poordeclining natural gas prices and reduced drilling activity in mostmany of our producing areas. Significant results include the following:Net income of $34.9 million;Distributions of $50.5 million to our limited partners;Net income of $42.2 million; Identified 360 new wells located on our Royalty and Net Profits Interest Properties in 11 states;Distributions of $50.7 million to our limited partners; Consummated 103 leases of our mineral interest in undeveloped properties located in 32 counties and parishes in eight states, andIdentification of 408 new wells located on our Royalty and Net Profits Interest Properties in 9 states; Consummated the acquisition of complementary mineral, royalty, and net profits interest properties in exchange for our limited partnership units.Consummation of 42 leases of our mineral interest in undeveloped properties located in 26 counties and parishes in seven states, and Minerals NPI reaches payout resulting in an increase in oil reserves of 223 mbbls and gas reserves of 5,888 mmcf. maycould 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 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.income. 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.Effective December 31, 2009, theThe 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. Total Payments due by Period Less than 1 year 1-3 years 3-5 years More than 5 years $ 1,052,000 $ 237,000 $ 489,000 $ 326,000 — Payments due by Period Contractual Obligations Total Less than 1 year 1-3 years 3-5 years More than 5 years Operating Lease Obligations $ 815,000 $ 240,000 $ 510,000 $ 65,000 earningsincome and cash flows from operating activities are principally determined by changes in oil and natural gas sales volumes and prices, and to a lesser extent, by capital expenditures deducted under the NPI calculation. Our portion of oil and natural gas sales volumes and weighted average sales prices are shown in the following table. Years Ended December 31, 2010 2009 2008 4,987 4,457 4,003 322 294 301 3,351 3,593 3,877 10 11 12 $ 4.21 $ 3.71 $ 8.25 $ 74.77 $ 57.35 $ 96.02 $ 5.07 $ 3.91 $ 8.58 $ 69.40 $ 51.83 $ 98.76
Net Profits Interests ($/mcfe)(1) $ 1.76 $ 1.50 $ 1.89 Years Ended December 31, Accrual Basis Sales Volumes: 2011 2010 2009 6,212 4,987 4,457 327 322 294 3,838 3,351 3,593 40 10 11 Accrual Basis Weighted Averages Sales Price: $ 3.77 $ 4.21 $ 3.71 $ 91.55 $ 74.77 $ 57.35 $ 4.81 $ 5.07 $ 3.91 $ 88.27 $ 69.40 $ 51.83 $ 1.81 $ 1.76 $ 1.50 (1) Provided to assist in determination of revenues; applies only to Net Profits Interests sales volumes prices. 2009 and 2008decreased 2.3%increased 9.5% from 301 mbbls during 2008 to 294 mbbls during 2009 because of natural declines but increased 9.5% to 322 mbbls during 2010, and then increased 1.6% to 327 mbbls during 2011. The increases were partially due to the acquisition of Maecenas Minerals LLP on March 31, 2010 and toas well as activity in the Bakken Shale Trend of North Dakota. Royalty Properties’ gas sales volumes increased 11.3%11.9% from 4,003 mmcf during 2008 to 4,457 mmcf during 2009 and then increased 11.9% to 4,987 mmcf during 2010.2010, and then increased 24.6% to 6,212 mmcf during 2011. The increaseincreases in natural gas volumes in 2009 was2010 and 2011 were primarily due to the acquisition of royalty and overriding royalty interests in the Barnett Shale Trend effective June 30. In 2010, natural gas volumes increased due to the acquisition of Maecenas Minerals LLP effective March 31, 2010, and the acquisition of Barnett Shale properties acquiredeffective June 30, 2009.8.3%9.1% from 12 mbbls during 2008 to 11 mbbls during 2009 and subsequently decreased 9.1% to 10 mbbls during 2010.2010; and, subsequently increased 300% to 40 mbbls during 2011, due to including the Minerals NPI. NPI properties’ gas sales volumes decreased 7.3%6.7% from 3,877 mmcf during 2008 to 3,593 mmcf during 2009 and subsequently decreased 6.7% to 3,351 mmcf during 2010; and, subsequently increased 14.5% to 3,838 mmcf in 20102011, principally as a result of natural reservoir depletiondue to including the Minerals NPI. Minerals NPI oil sales volumes and gas sales volumes included in the Guymon-Hugoton field in Oklahoma.decreased 40.3%increased 30.4% from $96.02 per bbl in 2008 to $57.35 per bbl in 2009 and subsequently increased 30.4% to $74.77 per bbl in 2010.2010 and subsequently increased 22.4% to $91.55 per bbl in 2011. Royalty Properties’ weighted average gas sales prices decreased 55.0%increased 13.5% from $8.25 per mcf during 2008 to $3.71 per mcf during 2009 and then increased 13.5% to $4.21 per mcf during 2010.2010 and then decreased 10.5% to $3.77 per mcf during 2011. All such fluctuations resulted from changing market conditions.decreased 54.4%increased 29.7% from $8.58 per mcf during 2008 to $3.91 per mcf during 2009 and then increased 29.7% to $5.07 per mcf during 2010 and then decreased 5.1% to $4.81 per mcf in 2010.2011. NPI properties’ weighted average oil sales prices decreased 47.5%increased 33.9% from $98.76 per bbl during 2008 to $51.83 per bbl during 2009 followed by an increase of 33.9% to $69.40 per bbl during 2010 and subsequently increased 27.2% to $88.27 per bbl in 2010.2011. All such fluctuations resulted from changing market conditions. Additionally, 20092010 natural gas prices include a natural gas liquids payment accrual of $0.51/$0.77/mcf related to 20092010 production compared to $0.59/$0.51/mcf in 2008. Similarly, an additional amount of approximately $2.4 million for 2010 production is anticipated to be received during the first quarter of 2011.2009. The accrued 2011 natural gas liquids payment of $0.77/$0.93/mcf is included in the $5.07/$4.81/mcf average gas sales price for 2010.2011. The natural gas liquids payments are 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. 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.Our operating revenues decreased 51.5% from $89,925,000 during 2008 to $43,631,000 Generally, we receive payment in 2009 primarily as a resultthe first quarter of decreased oil and natural gas prices. the following year.duringin 2010 primarily as a result ofand subsequently increased 13.7% to $69,489,000 in 2011. Increased oil and natural gas prices during 2010 along with increased natural gas volumes from property acquisitions effective March 31, 2010. costs decreased 6.3% from $3,965,000 in 2008 to $3,715,000 in 2009 due to reduced capital expenditures reimbursed. G&A costs increased 11.1% from $3,715,000 in 2009 to $4,128,000 in 2010 due to increased costs related to, among other things, regulatory reporting changes, increased number of unitholder accounts requiring K-1s and professional fees related to revenue audits.and amortization increased 5.8% from $14,739,000 in 2008 to $15,599,000 in 2009 primarily as a result of the acquisition of new properties along with low natural gas pricing impacting depletable reserves. Changes in reserve calculations during 2009 did not increase depletion materially. During 2010, depletiondepreciation and amortization increased 15.3% from $15,599,000 in 2009 to $17,988,000 in 2010 primarily as a result of the acquisition of new properties partially offset by a lower depletion rate due to upward revisions in oil and natural gas reserve estimates. During 2011, depletion and amortization increased 2.0% to $18,348,000, primarily as a result of increased production partially offset by a lower depletion rate due to upward revisions in oil and natural gas reserve estimates and inclusion of the Minerals NPI reserves. Cash flow from operations and cash distributions to unitholders are not affected by depletion, depreciation and amortization.decreased 54.9%increased 41.1% from $82,908,000 during 2008 to $37,396,000 during 2009 to $52,763,000 during 2010 primarily due to decreasedincreased oil and natural gas prices. Net cash provided by operating activities increased 41.1%5.2% to $52,763,000$55,496,000 during 20102011 primarily due to increased oil prices and increased oil and natural gas prices and increasedproduction, partially offset by reduced natural gas production due to the acquisition of new properties effective March 31, 2010.ClimateIn response to climate change concerns, many foreign countries are adopting climate change legislation and regulations have been adopted by many foreign countries and some states in the United States. However, legislation and regulations have not been enacted at the federal level, althoughregulations. Although the United States Congress has considered adopting climate change legislation.legislation, it has yet to enact such legislation and/or regulations at the federal level. Several states have adopted or are considering adopting climate change legislation. Further, the EPA hasEnvironmental Protection Agency (“EPA”) issued greenhouse gas monitoring and reporting regulations that went into effect January 1, 2010, and2010. Those regulations require that require reporting by regulated facilities report by March 2011, and annually thereafter. The EPA has issued final regulations requiring petroleum and natural gas operators meeting a certain emission threshold to report their greenhouse gas emissions to the EPA. BeyondIn addition to the measuring and reporting requirements, the“Endangerment Finding”"Endangerment Finding" under Section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of future generations. The EPAgenerations and has indicated that it will use data collected through the reporting rules to decide whether to promulgate future greenhouse gas emission limits. The current state of development of many state and federal climate change regulatory initiatives makes it difficult to predict with certainty the future impact on us, including accurately estimating the related compliance costs that the operating partnership and oil and natural gas operators that develop our properties may incur.his ownan independent tax advisor regarding the requirements for filing state income, franchise and Texas margin tax returns.“acquisition indebtedness”"acquisition indebtedness" (as defined in Section 514 of the Internal Revenue Code of 1986, as amended).”" See “Notes"Notes to Consolidated Financial Statements – Note 3 – Related Party Transactions.”2009, and $16,211,000 for 2008.20092010 through December 20102011 were as follows: Quarter Per Unit
Amount $ in Thousands Limited
Partners General
Partner 2009 4th $ 0.321540 $ 9,595 $ 339 2010 1st 0.449222 13,780 424 2010 2nd 0.412207 12,645 443 2010 3rd 0.471081 14,450 522 $ 50,470 $ 1,728 2010 4th $ 0.354074 $ 10,861 $ 388 $ in Thousands Year Quarter Record Date Payment Date Per Unit Amount Limited Partners General Partner 2010 4th January 24, 2011 February 3, 2011 $ 0.354074 $ 10,861 $ 388 2011 1st April 25, 2011 May 5, 2011 0.426745 13,091 413 2011 2nd July 25, 2011 August 4, 2011 0.417027 12,793 469 2011 3rd October 24, 2011 November 3, 2011 0.455546 13,974 516 Total distributions paid in 2011 $ 50,719 $ 1,786 2011 4th January 23, 2012 February 2, 2012 $ 0.448553 $ 13,759 $ 474 $11,985,000$10,458,000 during October 20092010 through September 2010,2011, which payments reflected 96.97% of total net proceeds of $12,360,000$10,785,000 realized from September 20092010 through August 2010.2011. Net proceeds realized by the operating partnership during September through November 20102011 were reflected in NPI payments made during October through December 2010.2011. These payments were included in the fourth quarter distribution paid in early 20112012 and are excluded from this 20102011 analysis.20092010 through September 20102011 were $40,213,000,$42,047,000, of which $38,605,000$40,365,000 (96%) was distributed to the limited partners and $1,608,000$1,682,000 (4%) was distributed to the general partner. Proceeds received by us from the Royalty Properties during the period October through December 20102011 became part of the fourth quarter distribution paid in early 2011,2012, which is excluded from this 20102011 analysis.20092010 through September 20102011 demonstrates the method. $ In Thousands Limited
Partners General
Partner $ — $ 1,608 38,605 — — 120 11,865 — $ 50,470 $ 1,728 — 374 — $ 2,102 96 % 4 % $ — $ 1,682 40,365 104 10,354 $ 50,719 $ 1,786 327 $ 2,113 96% 4% 20092010 through September 2010,2011, our Partnership’sPartnership's quarterly distribution payments to limited partners were based on all of its available cash. Our Partnership’sPartnership's only significant cash reserves that influenced quarterly payments were $1,378,000$1,245,000 for ad valorem taxes. Additionally, certain production costs under the NPI calculation and a small portion of management expense reimbursements include amounts for which funds were set aside monthly to enable payment when due. Examples are contributions to SEP-IRA accounts and payroll taxes. These amounts generally are not held for periods over one year.20102011 Distribution Indicated PricePartnership’sPartnership's 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 prior period adjustments.Partnership’sPartnership's Royalty Properties during the 20102011 fourth quarter totaled approximately $10.4$12.3 million. These receipts generally reflect oil sales during September through November 20102011 and natural gas sales during August through October 2010.2011. The weighted average indicated prices for oil and natural gas sales during the 20102011 fourth quarter attributable to the Royalty Properties were $75.14/$87.19/bbl and $3.97/$3.69/mcf.Partnership’sPartnership's NPIs during the 20102011 fourth quarter totaled approximately $2.1$3.2 million and include Net Profits Interest payments from the Minerals NPI of approximately $1.3 million. These receipts generally reflect oil and natural gas sales from the properties underlying the NPIs during August through October 2010.2011. The weighted average indicated prices for oil and natural gas sales during the 20102011 fourth quarter attributable to the NPIs were $66.82/$86.77/bbl and $3.74/$3.78/mcf.2010,2011, the limitation was in excess of the reimbursement amounts actually paid or accrued.ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK“market risk”"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.ITEM 8.CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATAITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSUREITEM 9A.CONTROLS AND PROCEDURES2010.2011. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of December 31, 2010,2011, our disclosure controls and procedures were effective, in that they ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is (1) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. external financial reporting in accordance with generally accepted accounting principles within the guidelines of the Committee of Sponsoring Organizations of the Treadway Commission framework. Based on the results of this evaluation, management has determined that the Partnership’s internal control over financial reporting was effective as of December 31, 2010.2011. The independent registered public accounting firm of Grant Thornton LLP, as auditors of the Partnership’s financial statements included in the Annual Report, has issued an attestation report on the Partnership’s internal control over financial reporting.2010,2011, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.ITEM 9B.OTHER INFORMATIONITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE20112012 Proxy Statement, which will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2010.2011.ITEM 11.EXECUTIVE COMPENSATION20112012 Proxy Statement, which will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2010.2011.ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS20112012 Proxy Statement, which will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2010.2011.ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE20112012 Proxy Statement, which will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2010.2011.ITEM 14.PRINCIPAL ACCOUNTING FEES AND SERVICES20112012 Proxy Statement, which will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2010.ITEM 15.EXHIBITS AND FINANCIAL STATEMENT SCHEDULES(a)Financial Statements and Schedules (a) Financial Statements and Schedules (1) See the Index to Consolidated Financial Statements on page F-1. (2) No schedules are required. (3) Exhibits.NumberDescription3.1Certificate 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)3.2Amended and Restated Agreement of Limited Partnership of Dorchester Minerals, L.P. (incorporated by reference to Exhibit 3.2 to Dorchester Minerals’ Annual Report on Form 10-K for the year ended December 31, 2002)3.3Certificate of Limited Partnership of Dorchester Minerals Management LP (incorporated by reference to Exhibit 3.4 to Dorchester Minerals’ Registration Statement on Form S-4, Registration Number 333-88282)3.4Amended and Restated Agreement of Limited Partnership of Dorchester Minerals Management LP (incorporated by reference to Exhibit 3.4 to Dorchester Minerals’ Annual Report on Form 10-K for the year ended December 31, 2002)3.5Certificate of Formation of Dorchester Minerals Management GP LLC (incorporated by reference to Exhibit 3.7 to Dorchester Minerals’ Registration Statement on Form S-4, Registration Number 333-88282)3.6Amended and Restated Limited Liability Company Agreement of Dorchester Minerals Management GP LLC (incorporated by reference to Exhibit 3.6 to Dorchester Minerals’ Annual Report on Form 10-K for the year ended December 31, 2002)3.7Certificate of Formation of Dorchester Minerals Operating GP LLC (incorporated by reference to Exhibit 3.10 to Dorchester Minerals’ Registration Statement on Form S-4, Registration Number 333-88282)3.8Limited Liability Company Agreement of Dorchester Minerals Operating GP LLC (incorporated by reference to Exhibit 3.11 to Dorchester Minerals’ Registration Statement on Form S-4, Registration Number 333-88282)3.9Certificate of Limited Partnership of Dorchester Minerals Operating LP (incorporated by reference to Exhibit 3.12 to Dorchester Minerals’ Registration Statement on Form S-4, Registration Number 333-88282)3.10Amended and Restated Agreement of Limited Partnership of Dorchester Minerals Operating LP (incorporated by reference to Exhibit 3.10 to Dorchester Minerals’ Annual Report on Form 10-K for the year ended December 31, 2002)3.11Certificate of Limited Partnership of Dorchester Minerals Oklahoma LP (incorporated by reference to Exhibit 3.11 to Dorchester Minerals’ Annual Report on Form 10-K for the year ended December 31, 2002)3.12Agreement of Limited Partnership of Dorchester Minerals Oklahoma LP (incorporated by reference to Exhibit 3.12 to Dorchester Minerals’ Annual Report on Form 10-K for the year ended December 31, 2002)3.13Certificate of Incorporation of Dorchester Minerals Oklahoma GP, Inc. (incorporated by reference to Exhibit 3.13 to Dorchester Minerals’ Annual Report on Form 10-K for the year ended December 31, 2002)NumberDescription3.14Bylaws of Dorchester Minerals Oklahoma GP, Inc. (incorporated by reference to Exhibit 3.14 to Dorchester Minerals’ Annual Report on Form 10-K for the year ended December 31, 2002)10.1Amended and Restated Business Opportunities Agreement dated as of December 13, 2001 by and between the Registrant, the General Partner, Dorchester Minerals Management GP LLC, SAM Partners, Ltd., Vaughn Petroleum, Ltd., Smith Allen Oil & Gas, Inc., P.A. Peak, Inc., James E. Raley, Inc., and certain other parties (incorporated by reference to Exhibit 10.1 to Dorchester Minerals’ Annual Report on Form 10-K for the year ended December 31, 2002)10.2Transfer Restriction Agreement (incorporated by reference to Exhibit 10.2 to Dorchester Minerals’ Annual Report on Form 10-K for the year ended December 31, 2002)10.3Registration Rights Agreement (incorporated by reference to Exhibit 10.3 to Dorchester Minerals’ Annual Report on Form 10-K for the year ended December 31, 2002)10.4Lock-Up Agreement by William Casey McManemin (incorporated by reference to Exhibit 10.4 to Dorchester Minerals’ Annual Report on Form 10-K for the year ended December 31, 2002)10.5Form of Indemnity Agreement (incorporated by reference to Exhibit 10.1 to Dorchester Minerals’ Quarterly Report on Form 10-Q for the quarter ended June 30, 2004)10.6Contribution and Exchange Agreement by and among Dorchester Minerals, L.P., Tiggator, Inc., TRB Minerals, LP and West Fork Partners dated May 15, 2009 (incorporated by reference to Exhibit 10.1 to Dorchester Minerals’ Current Report on Form 8-K dated June 30, 2009)10.7Amendment No. 1 dated June 26, 2009 to Contribution and Exchange Agreement by and among Dorchester Minerals, L.P., Tiggator, Inc., TRB Minerals, LP and West Fork Partners dated May 15, 2009 (incorporated by reference to Exhibit 10.2 to Dorchester Minerals’ Quarterly Report on Form 10-Q for the quarter ended June 30, 2009)10.8Lock-up Agreement by Tiggator, Inc. dated June 30, 2009 (incorporated by reference to Exhibit 10.2 to Dorchester Minerals’ Current Report on Form 8-K dated June 30, 2009)10.9Lock-up Agreement by TRB Minerals, LP dated June 30, 2009 (incorporated by reference to Exhibit 10.2 to Dorchester Minerals’ Current Report on Form 8-K dated June 30, 2009)10.10Lock-up Agreement by West Fork Partners, LP dated June 30, 2009 (incorporated by reference to Exhibit 10.2 to Dorchester Minerals’ Current Report on Form 8-K dated June 30, 2009)10.11Contribution and Exchange Agreement dated March 31, 2010 by and among Dorchester Minerals, L.P., Dodge Jones Foundation, The Legett Foundation, Kickapoo Springs Foundation, The Karakin Foundation, Still Water Foundation, Xettam Minerals, L.P., 2MW Limited Partnership, Julia Jones Matthews, TrusteeJulia Jones Matthews Living Trust, and John A. Matthews, Jr. (incorporatedexhibits required by referenceItem 601 of Regulation S-K to Exhibit 10.1be filed as part of this report is set forth in the Index to Dorchester Minerals’ ReportExhibits beginning on Form 8-K ( filed on April 6, 2010).21.1*Subsidiaries of the Registrant23.1*Consent of Grant Thornton LLP23.2*Consent of Calhoun, Blair & Associates23.3*Consent of LaRoche Petroleum Consultants, Ltd.31.1*Certification of Chief Executive Officer of our Partnership pursuant to Rule 13a-14(a) of the Securities Exchange Act of 193431.2*Certification of Chief Financial Officer of our Partnership pursuant to Rule 13a-14(a) of the Securities Exchange Act of 193432.1*Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Sec. 135099.1*Report of Calhoun, Blair & Associates99.2*Report of LaRoche Petroleum Consultants, Ltd.*Filed herewith“bbl”"bbl" means a standard barrel of 42 U.S. gallons and represents the basic unit for measuring the production of crude oil, natural gas liquids and condensate.“"bcf” means one billion cubic feet under prescribed conditions of pressure and temperature and represents a unit for measuring the production of natural gas.Depletion”boe” means one barrel of oil equivalent, converting natural gas to oil at the ratio of 6 Mcf of natural gas to 1 Bbl of oil.“"Division order”order"means a document to protect lessees and purchasers of production, in which all parties who may have a claim to the proceeds of the sale of production agree upon how the proceeds are to be divided.“"Enhanced recovery”recovery"means the process or combination of processes applied to a formation to extract hydrocarbons in addition to those that would be produced utilizing the natural energy existing in that formation. Examples of enhanced recovery include water flooding and carbon dioxide (CO2) injection.“"Estimated future net revenues”revenues" (also referred to as “estimated"estimated future net cash flow”flow") means the result of applying current prices of oil and natural gas to estimated future production from oil and natural gas proved reserves, reduced by estimated future expenditures, based on current costs to be incurred in developing and producing the proved reserves, excluding overhead.“Formation”"Formation"means a distinct geologic interval, sometimes referred to as the strata, which has characteristics (such as permeability, porosity and hydrocarbon saturations) that distinguish it from surrounding intervals.“"Gross acre”acre" means the number of surface acres in which a working interest is owned.“"Gross well”well"means a well in which a working interest is owned.“"Lease bonus”bonus"means the initial cash payment made to a lessor by a lessee in consideration for the execution and conveyance of the lease.“Leasehold”"Leasehold"means an acre in which a working interest is owned.“Lessee”"Lessee" means the owner of a lease of a mineral interest in a tract of land.“Lessor”"Lessor"means the owner of the mineral interest who grants a lease of his interest in a tract of land to a third party, referred to as the lessee.“"Mineral interest”interest"means the interest in the minerals beneath the surface of a tract of land. A mineral interest may be severed from the ownership of the surface of the tract. Ownership of a mineral interest generally involves four incidents of ownership: (1) the right to use the surface; (2) the right to incur costs and retain profits, also called the right to develop; (3) the right to transfer all or a portion of the mineral interest; and (4) the right to retain lease benefits, including bonuses and delay rentals.“"mcf”means one thousand cubic feet under prescribed conditions of pressure and temperature and represents the basic unit for measuring the production of natural gas.mbbls”mcfe” means one thousand cubic feet of natural gas equivalent, converting oil or condensate to natural gas at the ratio of 1 Bbl of oil or condensate to 6 Mcf of natural gas. This conversion ratio, which is typically used in the oil and gas industry, represents the approximate energy equivalent of a barrel of oil or condensate to an Mcf of natural gas. The sales price of one barrel of oil or condensate has been much higher than the sales price of six Mcf of natural gas over the last several years, so a six to one conversion ratio does not represent the economic equivalency of six Mcf of natural gas to one barrel of oil or condensate“"mmcf”means one million cubic feet under prescribed conditions of pressure and temperature and represents the basic unit for measuring the production of natural gas.“"Net acre”acre" means the product determined by multiplying gross acres by the interest in such acres.“"Net well”well" means the product determined by multiplying gross oil and natural gas wells by the interest in such wells.“"Net profits interest”interest" means a non-operating interest that creates a share in gross production from another (operating or non-operating) interest in oil and natural gas properties. The share is determined by net profits from the sale of production and customarily provides for the deduction of capital and operating costs from the proceeds of the sale of production. The owner of a net profits interest is customarily liable for the payment of capital and operating costs only to the extent that revenue is sufficient to pay such costs but not otherwise.“Operator”"Operator" means the individual or company responsible for the exploration, development, and production of an oil or natural gas well or lease.“"Overriding royalty interest”interest" means a royalty interest created or reserved from another (operating or non-operating) interest in oil and natural gas properties. Its term extends for the same term as the interest from which it is created.“Proved "Proved developed reserves”reserves" means reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.“"Proved reserves”reserves" or “Proved oil and natural gas reserves”means those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and governmental regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.“"Proved undeveloped reserves”reserves" means proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.“Royalty”"Royalty" means an interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof) but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage.“"Severance tax”tax" means an amount of tax, surcharge or levy recovered by governmental agencies from the gross proceeds of oil and natural gas sales. Severance tax may be determined as a percentage of proceeds or as a specific amount per volumetric unit of sales. Severance tax is usually withheld from the gross proceeds of oil and natural gas sales by the first purchaser (e.g., pipeline or refinery) of production.“"Standardized measure of discounted future net cash flows”flows" (also referred to as “standardized measure”"standardized measure") means the pretax present value of estimated future net revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.“"Undeveloped acreage”acreage" means lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.“Unitization”"Unitization" means the process of combining mineral interests or leases thereof in separate tracts of land into a single entity for administrative, operating or ownership purposes. Unitization is sometimes called “pooling”"pooling" or “communitization”"communitization" and may be voluntary or involuntary.“"Working interest”interest" (also referred to as an “operating interest”"operating interest") means a real property interest entitling the owner to receive a specified percentage of the proceeds of the sale of oil and natural gas production or a percentage of the production but requiring the owner of the working interest to bear the cost to explore for, develop and produce such oil and natural gas. A working interest owner who owns a portion of the working interest may participate either as operator or by voting his percentage interest to approve or disapprove the appointment of an operator and certain activities in connection with the development and operation of a property.Registrantregistrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.DORCHESTER MINERALS, L.P. By: By: its general partnerBy: its general partnerBy: /s/ William Casey McManemin By: /s/ William Casey McManemin William Casey McManemin24, 2011 24, 201123, 2012 24, 201123, 2012 24, 201123, 2012 Buford P. BerryManagerDate: February 24, 2011 24, 201123, 2012 C. W. RussellManagerDate: February 24, 2011 24, 201123, 2012 24, 201123, 2012
DORCHESTER MINERALS, L.P.F-2 F-4 2009 F-5 2009 and 20082009F-6 2009 and 20082009F-7 F-8 2010,2011, based on criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.2010,2011, based on criteria established inInternal Control—Integrated Framework issued by COSO.20102011 and 20092010 and the related consolidated income statements, of operations, cash flows, and changes in partnership capital for each of the three years in the period ended December 31, 2010,2011, and our report dated February 24, 201123, 2012 expressed an unqualified opinion on those financial statements.24, 201120102011 and 2009,2010, and the related income statements, of operations, cash flows, and changes in partnership capital for each of the three years in the period ended December 31, 2010.2011. These financial statements are the responsibility of the Partnership’sPartnership's management. Our responsibility is to express an opinion on these financial statements based on our audits.20102011 and 2009,2010, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010,2011, in conformity with accounting principles generally accepted in the United States of America.Partnership’sPartnership's internal control over financial reporting as of December 31, 2010,2011, based on criteria established inInternal Control–Control__Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated February 24, 201123, 2012 expressed an unqualified opinion.24, 201120102011 and 2009 2010 2009 ASSETS $ 11,253 $ 10,124 5,548 5,419 3,651 3,703 20,452 19,246 19 19 344,194 327,069 (211,761 ) (193,822 ) 132,433 133,247 512 512 (305 ) (256 ) 207 256 132,640 133,503 $ 153,111 $ 152,768 LIABILITIES AND PARTNERSHIP CAPITAL $ 542 $ 529 39 39 581 568 129 169 710 737 4,669 5,240 147,732 146,791 152,401 152,031 $ 153,111 $ 152,768 2011 2010 ASSETS Current assets: $ 14,238 $ 11,253 6,602 5,548 7,616 3,651 28,456 20,452 19 19 Property and leasehold improvements—at cost: 344,196 344,194 (230,060) (211,761) 114,136 132,433 512 512 (354) (305) 158 207 $ 142,769 $ 153,111 LIABILITIES AND PARTNERSHIP CAPITAL Current liabilities: $ 529 $ 542 39 39 568 581 90 129 658 710 Commitments and contingencies (Note 4) Partnership capital: 4,242 4,669 137,869 147,732 142,111 152,401 $ 142,769 $ 153,111 OF OPERATIONS2009 and 2008 (Dollars2009 2010 2009 2008 $ 45,095 $ 33,412 $ 61,973 12,046 9,449 27,441 3,819 688 441 134 82 70 61,094 43,631 89,925 1,729 1,202 2,792 2,442 2,160 1,980 17,988 15,599 14,739 4,128 3,715 3,965 26,287 22,676 23,476 34,807 20,955 66,449 76 726 334 $ 34,883 $ 21,681 $ 66,783 $ 1,157 $ 698 $ 1,999 $ 33,726 $ 20,983 $ 64,784 $ 1.11 $ 0.72 $ 2.30 30,469 29,044 28,240 2011 2010 2009 Operating revenues: $ 53,345 $ 45,095 $ 33,412 15,525 12,046 9,449 517 3,819 688 102 134 82 69,489 61,094 43,631 Costs and expenses: 2,430 1,729 1,202 2,445 2,442 2,160 18,348 17,988 15,599 4,088 4,128 3,715 27,311 26,287 22,676 42,178 34,807 20,955 37 76 726 $ 42,215 $ 34,883 $ 21,681 Allocation of net income: $ 1,359 $ 1,157 $ 698 $ 40,856 $ 33,726 $ 20,983 $ 1.33 $ 1.11 $ 0.72 30,675 30,469 29,044 2009 and 2008 2010 2009 2008 $ 34,883 $ 21,681 $ 66,783 17,988 15,599 14,739 — — 62 (40 ) (39 ) (40 ) (129 ) (366 ) 2,000 52 725 (852 ) 9 (204 ) 216 52,763 37,396 82,908 683 1,251 — (119 ) (6 ) (50 ) 564 1,245 (50 ) (52,198 ) (44,728 ) (81,648 ) 1,129 (6,087 ) 1,210 10,124 16,211 15,001 $ 11,253 $ 10,124 $ 16,211 $ 17,685 $ 36,496 — 2011 2010 2009 Cash flows from operating activities: $ 42,215 $ 34,883 $ 21,681 Adjustments to reconcile net income to net cash provided by operating activities: 18,348 17,988 15,599 (39 ) (40 ) (39 ) Changes in operating assets and liabilities: (1,054 ) (129 ) (366 ) (3,965 ) 52 725 (9 ) 9 (204 ) 55,496 52,763 37,396 Cash flows from investing activities: 683 1,251 (6 ) (119 ) (6 ) (6 ) 564 1,245 Cash flows from financing activities: (52,505 ) (52,198 ) (44,728 ) 2,985 1,129 (6,087 ) 11,253 10,124 16,211 $ 14,238 $ 11,253 $ 10,124 Non-Cash investing and financing activities $ 17,685 $ 36,496 2009 and 2008 General
Partner Unitholders Total Unitholder
Units $ 6,417 $ 147,030 $ 153,447 28,240,431 1,999 64,784 66,783 (2,445 ) (79,203 ) (81,648 ) 5,971 132,611 138,582 28,240,431 698 20,983 21,681 — 36,496 36,496 1,600,000 (1,429 ) (43,299 ) (44,728 ) 5,240 146,791 152,031 29,840,431 1,157 33,726 34,883 — 17,685 17,685 835,000 (1,728 ) (50,470 ) (52,198 ) $ 4,669 $ 147,732 $ 152,401 30,675,431 Year Unitholders Total Unitholder Units 2009 $ 5,971 $ 132,611 $ 138,582 28,240,431 698 20,983 21,681 36,496 36,496 1,600,000 (1,429 ) (43,299 ) (44,728 ) 5,240 146,791 152,031 29,840,431 2010 1,157 33,726 34,883 17,685 17,685 835,000 (1,728 ) (50,470 ) (52,198 ) 4,669 147,732 152,401 30,675,431 2011 1,359 40,856 42,215 (1,786 ) (50,719 ) (52,505 ) $ 4,242 $ 137,869 $ 142,111 30,675,431 2009 and 200820091.1. General and Summary of Significant Accounting Policies Operations—Operations — In these Notes, 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. Our Partnership is a Dallas, Texas based owner of producing and nonproducing natural gas and crude oil royalty, net profits, and leasehold interests in 574 counties and 25 states. We are a publicly traded Delaware limited partnership that was formed in December 2001, and commenced operations on January 31, 2003.Presentation—Presentation — Per-unit information is calculated by dividing the earningsincome or loss applicable to holders of our Partnership’s common units by the weighted average number of units outstanding. The Partnership has no potentially dilutive securities and, consequently, basic and dilutive earningsincome per unit do not differ.Consolidation—Consolidation — The consolidated financial statements include the accounts of Dorchester Minerals, L.P., Dorchester Minerals Oklahoma, LP, Dorchester Minerals Oklahoma GP, Inc, newly acquired Maecenas Minerals LLP, and newly formed subsidiary Dorchester-Maecenas GP LLC. Dorchester Minerals Acquisition LP and Dorchester Minerals Acquisition GP, Inc. were merged into Dorchester Minerals Oklahoma, LP and Dorchester Minerals Oklahoma GP, Inc. effective December 31, 2009. All significant intercompany balances and transactions have been eliminated in consolidation.Estimates—Estimates — 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 consolidated 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 our inability to gain accurate and timely information. Therefore, actual results could differ from those estimates. See “Item 1. Business—Business — Customers and Pricing” and “Item 2. “Properties—“Properties — Royalty Properties” for additional discussion.maycould reach different conclusions as to estimated quantities of oil and natural gas reserves based on the same information. 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.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. See the discussion underPropertyOil and EquipmentNatural Gas Properties.isrelationships are with major financial institutions. Cash balances in these accounts may, at times, exceed federally insured limits. We have not experienced any losses in such cashDORCHESTER MINERALS, L.P.(A Delaware Limited Partnership)NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)December 31, 2010, 2009 and 2008$329,000 in 2010, 2009, and 2008, respectively.necessary.Propertynecessary based upon our history of collection and Equipment—review of current receivables.recorded for the years 2011, 2010, 2009, and 2008.2009.Beginning December 31, 2009, theThe 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 (previously year-end 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. Changes in determining the price to use in reserve report calculations did not materially increase our depletion expense.2009 or 2008.expense.DORCHESTER MINERALS, L.P.(A Delaware Limited Partnership)NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)December 31,expense for the years 2011, 2010 2009 and 20082009.Obligations—Obligations — Based on the nature of our property ownership, we have no material obligation required to be recorded.Recognition—Recognition — The pricing of oil and natural gas sales from the Royalty Properties is primarily determined by supply and demand in the marketplace and can fluctuate considerably. As a royalty owner, we have extremely limited involvement and operational control over the volumes and method of sale of oil and natural gas produced and sold from the Royalty Properties.Taxes—Taxes — Weare treated as a partnership for income tax purposes and, as a result, our income or loss is includibleincludable in the tax returns of the individual unitholders. Unitholders should consult tax advisors concerning their own tax situations. Depletion of oil and natural gas properties is an expense allowable to each individual partner, and the depletion expense as reported on the consolidated financial statements will not be indicative of the depletion expense an individual partner or unitholder may be able to deduct for income tax purposes.his ownan independent tax advisor regarding the requirements for filing state income, franchise and Texas margin tax returns.DORCHESTER MINERALS, L.P.(A Delaware Limited Partnership)NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)December 31, 2010, 2009 and 2008Subsequent Events—We are not aware of any subsequent events, which are not already recognized or disclosed, that would require recognition or disclosure in the financial statements.2.2. Acquisition for Units 3.3. Related Party Transactions In Thousands 2010 2009 2008 $ 3,651 $ 3,703 $ 4,428 $ 2 $ 3 $ 1 $ 121 $ 34 $ 146 $ 45 $ 33 $ 58 $ 2,473 $ 2,448 $ 2,690 In Thousands From/To Operating Partnership 2011 2010 2009 $ 7,616 $ 3,651 $ 3,703 $ 0 $ 2 $ 3 $ 103 $ 121 $ 34 $ 67 $ 45 $ 33 $ 2,616 $ 2,473 $ 2,448 (1)All Net Profits Interests income on the financial statements is from the operating partnership. 4.4. Commitments and Contingencies DORCHESTER MINERALS, L.P.(A Delaware Limited Partnership)NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)December 31, 2010, 2009 and 2008majorsignificant portion of the NPI amounts paid to us. On April 9, 2007, plaintiffs, for immaterial costs, dismissed with prejudice all claims against the operating partnership regarding such residential gas use. On October 4, 2004, the plaintiffs filed severed claims against the operating partnership regarding royalty underpayments, which the Texas County District Court subsequently dismissed with a grant of time to replead. On January 27, 2006, one of the original plaintiffs again sued the operating partnership for underpayment of royalty, seeking class action certification. On October 1, 2007, the Texas County District Court granted the operating partnership’s motion for summary judgment finding no royalty underpayments. Subsequently, the District Court denied the plaintiff’s motion for reconsideration, and the plaintiff filed an appeal. On March 31, 2010, the appeal decision reversed and remanded to the Texas County District Court to resolve material issues of fact. On June 30, 2011, the District Court issued a revised partial summary judgment in favor of the operating partnership. A hearing regarding the requested class action certification is set for late July, 2011. No court hearing has been scheduled on the merits.claim of underpayment of royalty remains pending. An adverse decision could reduce amounts we receive from the NPIs.Dorchester Minerals, L.P filed Cause No. 07-0250-15; Dorchester Minerals, LP v. H&S Production, Inc. in the 15th District Court of Grayson County, Texas in January, 2007. The suit involved claims under an oilgas lease between us as lessor and H&S as lessee. Our Motion for Summary Judgment, which included damages in the amount of $496,000, was granted by the trial court in May 2008. H&S appealed the Judgment. The Fifth District Court of Appeals affirmed the Judgment on liability and remanded on damages. The subsequent Motion for Rehearing filed by H&S was denied by the Fifth District Appeals Court. The matter was settled on October 22, 2009 with the Appeals Court ruling on liability continuing to stand, the dismissal with prejudice of the remanded action on damages, and receipt of a $500,000 payment from H&S to us. The deposit was recorded in the fourth quarter 2009 financial statements in other income.$217,000, and $200,000$217,000 for the years ended December 31, 2011, 2010 2009 and 2008,2009, respectively. The base rent escalated in November 2010. Minimum rental commitments under the terms of our operating lease are as follows: Minimum
Payments $ 237,000 240,000 249,000 261,000 65,000 $ 1,052,000 DORCHESTER MINERALS, L.P.(A Delaware Limited Partnership)NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)December 31, 2010, 2009 and 2008Years Ended December 31, 2012 $ 240,000 2013 249,000 2014 261,000 2015 65,000 Total $ 815,000 5.5. Distribution To Holders Of Common Units Per Unit Amount 2010 2009 2008 $ 0.449222 $ 0.401205 $ 0.572300 $ 0.412207 $ 0.271354 $ 0.769206 $ 0.471081 $ 0.286968 $ 0.948472 $ 0.354074 $ 0.321540 $ 0.542081 Per Unit Amount 2011 2010 2009 $ 0.426745 $ 0.449222 $ 0.401205 $ 0.417027 $ 0.412207 $ 0.271354 $ 0.455546 $ 0.471081 $ 0.286968 $ 0.448553 $ 0.354074 $ 0.321540 2011.2012.6.6. Unaudited Oil and Natural Gas Reserve and Standardized Measure Information 20102011 that would have a material effect on our estimated proved developed reserves.management’smanagement's opinion, should be examined with caution. The basis for these disclosures is petroleum engineers’ reserve studies which contain imprecise estimates of quantities and rates of production of reserves. Revision of prior year estimates can have a significant impact on the results. Also, exploration and production improvement costs in one year may significantly change previous estimates of proved reserves and their valuation. Values of unproved properties and anticipated future price and cost increases or decreases are not considered. Therefore, the standardized measure is not necessarily a best estimate of the fair value of oil and natural gas properties or of future net cash flows.STATEMENTS—STATEMENTS — (Continued)2009 and 2008Management’s Management's Discussion and Analysis of Financial Condition and Results of Operations” because of fuel, shrinkage and pipeline loss. The Standardized Measure of Discounted Future Net Cash Flows reflects adjustments for such fuel, shrinkage and pipeline loss. Summary of Changes in Proved Reserves Oil (mbbl) Natural Gas (mmcf) 2010 2009 2008(1) 2010 2009 2008(1) 3,277 3,570 3,566 60,280 60,977 61,255 158 — — 1,163 5,585 — 230 13 317 8,993 2,212 8,070 (332 ) (306 ) (313 ) (8,757 ) (8,494 ) (8,348 ) 3,333 3,277 3,570 61,679 60,280 60,977 (1)Based on end-of-year pricing of oil and natural gas. Oil (mbbls) Natural Gas (mmcf) 2011 2010 2009 2011 2010 2009 Estimated quantity, beginning of year 3,333 3,277 3,570 61,679 60,280 60,977 Purchase of minerals in place 158 1,163 5,585 Revisions in previous estimates 600 230 13 15,767 8,993 2,212 Production (367 ) (332 ) (306 ) (10,483 ) (8,757 ) (8,494 ) Estimated quantity, end of year 3,566 3,333 3,277 66,963 61,679 60,280 Thousands) 2010 2009 2008(1) $ 459,365 $ 333,161 $ 361,974 (28,433 ) (18,488 ) (17,381 ) 430,932 314,673 344,593 (211,323 ) (148,638 ) (155,109 ) $ 219,609 $ 166,035 $ 189,484 $ (52,970 ) $ (39,498 ) $ (84,642 ) 8,804 7,455 — 56,751 (8,396 ) (102,401 ) 27,895 4,751 22,935 16,604 18,948 31,637 (3,510 ) (6,709 ) 5,588 $ 53,574 $ (23,449 ) $ (126,883 ) $ 1.67 $ 1.51 $ 1.44 $ 17,127 $ 35,245 $ — $ 75.56 $ 56.37 $ $35.69 $ 4.16 $ 3.24 $ 4.92 2011 2010 2009 Future estimated gross revenues $ 537,389 $ 459,365 $ 333,161 Future estimated production costs (32,874 ) (28,433 ) (18,488 ) Future estimated net revenues 504,515 430,932 314,673 10% annual discount for estimated timing of cash flows (242,925 ) (211,323 ) (148,638 ) Standardized measure of discounted future estimated net cash flows $ 261,590 $ 219,609 $ 166,035 Sales of oil and natural gas produced, net of production costs $ (63,995 ) $ (52,970 ) $ (39,498 ) Purchase of reserves in place 8,804 7,455 Net changes in prices and production costs 13,340 56,751 (8,396 ) Revisions of previous quantity estimates 67,655 27,895 4,751 Accretion of discount 21,961 16,604 18,948 Change in production rate and other 3,020 (3,510 ) (6,709 ) Net change in standardized measure of discounted future estimated net cash flows $ 41,981 $ 53,574 $ (23,449 ) Depletion of oil and natural gas properties (dollars per mcfe) $ 1.44 $ 1.67 $ 1.51 Property acquisition costs $ — $ 17,127 $ 35,245 $ 92.31 $ 75.56 $ 56.37 $ 4.00 $ 4.16 $ 3.24 Based on end-of-year pricing of oil and natural gas.(2)proportionsDORCHESTER MINERALS, L.P.(A Delaware Limited Partnership)NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)December 31, 2010, 2009 and 20087.7. Unaudited Quarterly Financial Data 2010 Quarter Ended 2009 Quarter Ended March 31 June 30 Sept. 30 Dec. 31 March 31 June 30 Sept. 30 Dec. 31 $ 15,539 $ 14,256 $ 16,467 $ 14,832 $ 8,824 $ 9,684 $ 10,706 $ 14,417 $ 8,926 $ 7,932 $ 9,536 $ 8,489 $ 3,777 $ 4,720 $ 4,415 $ 8,769 $ 0.29 $ 0.25 $ 0.30 $ 0.27 $ 0.13 $ 0.16 $ 0.14 $ 0.29 29,849 30,675 30,675 30,675 28,240 28,258 29,840 29,840 F-15 2011 Quarter Ended 2010 Quarter Ended March 31 June 30 Sept. 30 Dec. 31 March 31 June 30 Sept. 30 Dec. 31 Total operating revenues $ 14,289 $ 16,434 $ 18,326 $ 20,440 $ 15,539 $ 14,256 $ 16,467 $ 14,832 Net income $ 7,740 $ 9,770 $ 11,506 $ 13,199 $ 8,926 $ 7,932 $ 9,536 $ 8,489 Net income per Unit (basic and diluted) $ 0.24 $ 0.31 $ 0.36 $ 0.42 $ 0.29 $ 0.25 $ 0.30 $ 0.27 Weighted average common units outstanding 30,675 30,675 30,675 30,675 29,849 30,675 30,675 30,675 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’ Annual Report on Form 10-K 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’ Annual 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’ Annual 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’ Annual 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’ Annual 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’ Annual 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’ Annual 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’ Annual Report on Form 10-K for the year ended December 31, 2002) 10.1 Amended and Restated Business Opportunities Agreement dated as of December 13, 2001 by and between the Registrant, the General Partner, Dorchester Minerals Management GP LLC, SAM Partners, Ltd., Vaughn Petroleum, Ltd., Smith Allen Oil & Gas, Inc., P.A. Peak, Inc., James E. Raley, Inc., and certain other parties (incorporated by reference to Exhibit 10.1 to Dorchester Minerals’ Annual Report on Form 10-K for the year ended December 31, 2002) 10.2 Transfer Restriction Agreement (incorporated by reference to Exhibit 10.2 to Dorchester Minerals’ Annual Report on Form 10-K for the year ended December 31, 2002) 10.3 Registration Rights Agreement (incorporated by reference to Exhibit 10.3 to Dorchester Minerals’ Annual Report on Form 10-K for the year ended December 31, 2002) 10.4 Lock-Up Agreement by William Casey McManemin (incorporated by reference to Exhibit 10.4 to Dorchester Minerals’ Annual Report on Form 10-K for the year ended December 31, 2002) 10.5 Form of Indemnity Agreement (incorporated by reference to Exhibit 10.1 to Dorchester Minerals’ Quarterly Report on Form 10-Q for the quarter ended June 30, 2004) 10.6 Contribution and Exchange Agreement by and among Dorchester Minerals, L.P., Tiggator, Inc., TRB Minerals, LP and West Fork Partners dated May 15, 2009 (incorporated by reference to Exhibit 10.1 to Dorchester Minerals’ Current Report on Form 8-K dated June 30, 2009) 10.7 Amendment No. 1 dated June 26, 2009 to Contribution and Exchange Agreement by and among Dorchester Minerals, L.P., Tiggator, Inc., TRB Minerals, LP and West Fork Partners dated May 15, 2009 (incorporated by reference to Exhibit 10.2 to Dorchester Minerals’ Quarterly Report on Form 10-Q for the quarter ended June 30, 2009) 10.8 Lock-up Agreement by Tiggator, Inc. dated June 30, 2009 (incorporated by reference to Exhibit 10.2 to Dorchester Minerals’ Current Report on Form 8-K dated June 30, 2009) Number Description 10.9 Lock-up Agreement by TRB Minerals, LP dated June 30, 2009 (incorporated by reference to Exhibit 10.2 to Dorchester Minerals’ Current Report on Form 8-K dated June 30, 2009) 10.10 Lock-up Agreement by West Fork Partners, LP dated June 30, 2009 (incorporated by reference to Exhibit 10.2 to Dorchester Minerals’ Current Report on Form 8-K dated June 30, 2009) 10.11 Contribution and Exchange Agreement dated March 31, 2010 by and among Dorchester Minerals, L.P., Dodge Jones Foundation, The Legett Foundation, Kickapoo Springs Foundation, The Karakin Foundation, Still Water Foundation, Xettam Minerals, L.P., 2MW Limited Partnership, Julia Jones Matthews, Trustee of the Julia Jones Matthews Living Trust, and John A. Matthews, Jr. (incorporated by reference to Exhibit 10.1 to Dorchester Minerals' Report on Form 8-K (filed on April 6, 2010). 21.1* Subsidiaries of the Registrant 23.1* Consent of Grant Thornton LLP 23.2* Consent of Calhoun, Blair & Associates 23.3* Consent of LaRoche Petroleum Consultants, Ltd. 31.1* Certification of Chief Executive Officer of our Partnership pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 31.2* Certification of Chief Financial Officer of our Partnership pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 32.1** Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Sec. 1350 99.1* Report of Calhoun, Blair & Associates 99.2* Report of LaRoche Petroleum Consultants, Ltd. 101.INS** XBRL Instance Document 101.SCH** XBRL Taxonomy Extension Schema Document 101.CAL** XBRL Taxonomy Extension Calculation Linkbase Document 101.DEF** XBRL Taxonomy Extension Definition Document 101.LAB** XBRL Taxonomy Extension Label Linkbase Document 101.PRE** XBRL Taxonomy Extension Presentation Linkbase Document * Filed herewith ** Furnished herewith