DORCHESTER MINERALS, L.P. - Quarter Report: 2009 September (Form 10-Q)
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
DC. 20549
FORM
10-Q
[X]
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF
THE SECURITIES EXCHANGE ACT OF 1934
Or
[ ]
TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d)
OF
THE SECURITIES EXCHANGE ACT OF 1934
For the
transition period from __________ to __________
|
For
the Quarterly Period Ended September 30,
2009
|
Commission
file number
000-50175
|
DORCHESTER
MINERALS, L.P.
(Exact
name of Registrant as specified in its charter)
|
Delaware
(State
or other jurisdiction of
Incorporation
or organization)
|
81-0551518
(I.R.S.
Employer Identification No.)
|
3838
Oak Lawn Avenue, Suite 300, Dallas, Texas 75219
(Address
of principal executive offices) (Zip Code)
Registrant's
telephone number, including area code: (214)
559-0300
None
Former
name, former address and former fiscal
year, if
changed since last report
Indicate
by check mark whether the Registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the Registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90 days. Yes x No
o
Indicate
by check mark whether the Registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (232.405 of this
chapter) during the preceding 12 months (or for such shorter period that the
Registrant was required to submit and post such files). Yes o No
o
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer or a smaller reporting company. See
the definitions of "large accelerated filer”, “accelerated filer” and “smaller
reporting company" in Rule 12b-2 of the Exchange Act. (Check one):
|
Large
accelerated filer o
|
Accelerated
filer x
|
Non-accelerated
filer o
|
Smaller
reporting company o
|
|
(Do
not check if a smaller reporting company)
|
Indicate by check mark whether the
registrant is a shell company (as defined in Rule 12b-2 of the Act.): Yes
o No x
As of
November 5, 2009, 29,840,431 common units of partnership interest were
outstanding.
TABLE OF
CONTENTS
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ITEM
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ITEM
3.
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ITEM
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ITEM
1.
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ITEM
1A.
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ITEM
2.
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ITEM
3.
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ITEM
4.
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ITEM
5.
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ITEM
6.
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2
ITEM 1. FINANCIAL
INFORMATION
See
attached financial statements on the following pages.
3
DORCHESTER
MINERALS, L.P.
(A
Delaware Limited Partnership)
(In
Thousands)
|
September
30,
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December
31,
|
|||||||
|
2009
|
2008
|
|||||||
|
ASSETS
|
(unaudited)
|
|||||||
|
Current
assets:
|
||||||||
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Cash
and cash equivalents
|
$ | 10,012 | $ | 16,211 | ||||
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Trade
and other receivables
|
4,674 | 5,053 | ||||||
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Net
profits interests receivable - related party
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1,245 | 4,428 | ||||||
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Prepaid
expenses
|
20 | - | ||||||
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Total
current assets
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15,951 | 25,692 | ||||||
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Other
non-current assets
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19 | 19 | ||||||
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Total
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19 | 19 | ||||||
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Property
and leasehold improvements - at cost:
|
||||||||
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Oil
and natural gas properties (full cost method)
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327,063 | 291,818 | ||||||
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Accumulated
full cost depletion
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(189,533 | ) | (178,272 | ) | ||||
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Total
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137,530 | 113,546 | ||||||
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Leasehold
improvements
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512 | 512 | ||||||
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Accumulated
amortization
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(243 | ) | (207 | ) | ||||
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Total
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269 | 305 | ||||||
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Net
property and leasehold improvements
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137,799 | 113,851 | ||||||
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Total
assets
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$ | 153,769 | $ | 139,562 | ||||
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LIABILITIES
AND PARTNERSHIP CAPITAL
|
||||||||
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Current
liabilities:
|
||||||||
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Accounts
payable and other current liabilities
|
$ | 1,420 | $ | 733 | ||||
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Current
portion of deferred rent incentive
|
39 | 39 | ||||||
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Total
current liabilities
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1,459 | 772 | ||||||
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Deferred
rent incentive less current portion
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178 | 208 | ||||||
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Total
liabilities
|
1,637 | 980 | ||||||
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Commitments
and contingencies
|
||||||||
|
Partnership
capital:
|
||||||||
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General
partner
|
5,285 | 5,971 | ||||||
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Unitholders
|
146,847 | 132,611 | ||||||
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Total
partnership capital
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152,132 | 138,582 | ||||||
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Total
liabilities and partnership capital
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$ | 153,769 | $ | 139,562 | ||||
The
accompanying condensed notes are an integral part of these consolidated
financial statements.
4
DORCHESTER
MINERALS, L.P.
(A
Delaware Limited Partnership)
(In
Thousands except Earnings per Unit)
(Unaudited)
|
Three
Months Ended
|
Nine
Months Ended
|
|||||||||||||||
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September
30,
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September
30,
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|||||||||||||||
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2009
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2008
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2009
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2008
|
|||||||||||||
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Operating
revenues:
|
||||||||||||||||
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Royalties
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$ | 8,450 | $ | 18,284 | $ | 23,481 | $ | 51,659 | ||||||||
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Net
profits interests
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1,668 | 6,040 | 5,043 | 22,609 | ||||||||||||
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Lease
bonus
|
531 | 154 | 620 | 411 | ||||||||||||
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Other
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57 | 9 | 70 | 68 | ||||||||||||
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Total
operating revenues
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10,706 | 24,487 | 29,214 | 74,747 | ||||||||||||
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Costs
and expenses:
|
||||||||||||||||
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Operating,
including production taxes
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1,017 | 1,491 | 2,600 | 4,027 | ||||||||||||
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Depletion
and amortization
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4,524 | 3,775 | 11,297 | 11,213 | ||||||||||||
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General
and administrative expenses
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771 | 744 | 2,623 | 2,615 | ||||||||||||
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Total
costs and expenses
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6,312 | 6,010 | 16,520 | 17,855 | ||||||||||||
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Operating
income
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4,394 | 18,477 | 12,694 | 56,892 | ||||||||||||
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Other
income, net
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21 | 113 | 218 | 274 | ||||||||||||
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Net
earnings
|
$ | 4,415 | $ | 18,590 | $ | 12,912 | $ | 57,166 | ||||||||
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Allocation
of net earnings:
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||||||||||||||||
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General
partner
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$ | 152 | $ | 593 | $ | 436 | $ | 1,718 | ||||||||
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Unitholders
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$ | 4,263 | $ | 17,997 | $ | 12,476 | $ | 55,448 | ||||||||
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Net
earnings per common unit (basic and diluted)
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$ | 0.14 | $ | 0.64 | $ | 0.43 | $ | 1.97 | ||||||||
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Weighted
average common units outstanding
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29,840 | 28,240 | 28,779 | 28,240 | ||||||||||||
The
accompanying condensed notes are an integral part of these consolidated
financial statements.
5
DORCHESTER
MINERALS, L.P.
(A
Delaware Limited Partnership)
(In
Thousands)
(Unaudited)
|
Nine
Months Ended
|
||||||||
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September
30,
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||||||||
|
2009
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2008
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|||||||
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Net
cash provided by operating activities
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$ | 28,692 | $ | 67,968 | ||||
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Cash
flows provided by (used in) investing activities:
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||||||||
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Adjustment
related to acquisition of natural gas properties
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967 | - | ||||||
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Capital
expenditures
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- | (50 | ) | |||||
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Total
cash flows provided by (used in) investing activities
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967 | (50 | ) | |||||
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Cash
flows used in financing activities:
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||||||||
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Distributions
paid to general partner and unitholders
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(35,858 | ) | (54,021 | ) | ||||
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(Decrease)
increase in cash and cash equivalents
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(6,199 | ) | 13,897 | |||||
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Cash
and cash equivalents at beginning of period
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16,211 | 15,001 | ||||||
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Cash
and cash equivalents at end of period
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$ | 10,012 | $ | 28,898 | ||||
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Non-cash
investing and financing activities:
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||||||||
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Value
of units issued for natural gas properties acquired
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$ | 36,496 | ||||||
The
accompanying condensed notes are an integral part of these consolidated
financial statements.
6
DORCHESTER
MINERALS, L.P.
(A
Delaware Limited Partnership)
(Unaudited)
1 Basis of
Presentation: Dorchester Minerals, L.P. is a publicly traded Delaware
limited partnership that was formed in December 2001, and commenced operations
on January 31, 2003. The consolidated financial statements include
the accounts of Dorchester Minerals, L.P., Dorchester Minerals Oklahoma LP,
Dorchester Minerals Oklahoma GP, Inc., Dorchester Minerals Acquisition LP, and
Dorchester Minerals Acquisition GP, Inc. All significant intercompany
balances and transactions have been eliminated in consolidation.
The
condensed consolidated financial statements reflect all adjustments (consisting
only of normal and recurring adjustments unless indicated otherwise) that are,
in the opinion of management, necessary for the fair presentation of our
financial position and operating results for the interim period. Interim period
results are not necessarily indicative of the results for the calendar year. See
“Management’s Discussion and Analysis of Financial Condition and Results of
Operations” for additional information. Per-unit information is calculated by
dividing the earnings 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
earnings or loss per unit do not differ. These interim financial
statements should be read in conjunction with the consolidated financial
statements and notes thereto included in the Partnership’s annual report on Form
10-K for the year ended December 31, 2008.
Fair Value of Financial
Instruments—The carrying amount of cash and cash equivalents, trade
receivables and payables approximates fair value because of the short maturity
of those instruments. These estimated fair values may not be representative of
actual values of the financial instruments that could have been realized as of
quarter close or that will be realized in the future.
2 Contingencies:
In January 2002, some individuals and an association called Rural Residents for
Natural Gas Rights sued Dorchester Hugoton, Ltd., along with several other
operators in Texas County, Oklahoma regarding the use of natural gas from the
wells in residences. Dorchester Minerals Operating LP, the operating
partnership, now owns and operates the properties formerly owned by Dorchester
Hugoton. These properties contribute a major portion of the Net Profits
Interests amounts paid to 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. At present, the
litigation awaits result of the appeal to the Oklahoma Supreme Court. An adverse
appellate decision could reduce amounts we receive from the Net Profits
Interests.
Gain - 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 oil and gas 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 will be recorded in the fourth
quarter 2009 financial statements.
The
Partnership and the operating partnership are involved in other legal and/or
administrative proceedings arising in the ordinary course of their businesses,
none of which have predictable outcomes and none of which are believed to have
any significant effect on consolidated financial position, cash flows, or
operating results.
3 Acquisition
for Units: On June 30, 2009, we acquired producing and
non-producing Barnett Shale mineral and royalty interests located in Tarrant
County, Texas for 1,600,000 common units of Dorchester Minerals, L.P. issued
pursuant to a shelf registration statement. Net assets acquired at
the date of acquisition
totaled $36,496,000. The Condensed Consolidated Balance Sheets
presented include $35,245,000 in property additions. After the
issuance, 3,400,000 units remain available under the shelf registration
statement.
7
4 Distributions
to Holders of Common Units: Unitholder cash distributions per common unit
since 2005 have been:
|
Per
Unit Amount
|
||||||||||
|
2009
|
2008
|
2007
|
2006
|
2005
|
||||||
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First
quarter
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$0.401205
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$0.572300
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$0.461146
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$0.729852
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$0.481242
|
|||||
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Second
quarter
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$0.271354
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$0.769206
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$0.473745
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$0.778120
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$0.514542
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|||||
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Third
quarter
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$0.286968
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$0.948472
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$0.560502
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$0.516082
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$0.577287
|
|||||
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Fourth
quarter
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$0.542081
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$0.514625
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$0.478596
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$0.805543
|
||||||
Distributions
beginning with the second quarter of 2009 were paid on 29,840,431 units;
previous distributions above were paid on 28,240,431 units. The third
quarter 2009 distribution was paid November 5, 2009. Fourth quarter
distributions shown above are paid in the first calendar quarter of the
following year. Our partnership agreement requires the next cash
distribution to be paid by February 15, 2010.
5 New
Accounting Pronouncements: The Financial Accounting Standards
Board (“FASB”) Accounting Standards Codification (“ASC”) 105-10-5, General Principles, Generally
Accepted Accounting Principles defines the new hierarchy for U.S. GAAP
and explains how the FASB will use its Accounting Standards Codification as the
sole source for all authoritative guidance. FASB ASC 105-10-5 replaces SFAS 162,
The Hierarchy of Generally
Accepted Accounting Principles, which was issued in May 2008. It was
effective for all reporting periods ending after September 15, 2009 and we have
revised all references to pre-codification GAAP in our financial
statements. It did not have a material impact on our consolidated
financial statements.
FASB ASC
805-10, Business
Combinations, among other things, establishes principles and requirements
for how the acquirer in a business combination (a) recognizes and measures in
its financial statements the identifiable assets acquired, the liabilities
assumed, and any noncontrolling interest in the acquired business, (b) changes
the accounting for contingent consideration, in process research and
development, and restructuring costs, (c) expenses acquisition-related costs as
incurred, (d) recognizes and measures the goodwill acquired in the business
combination or a gain from a bargain purchase, and (e) determines what
information to disclose to enable users of the financial statements to evaluate
the nature and financial effects of the business combination. We
adopted FASB ASC 805-10 as of January 1, 2009 with no material impact on our
consolidated financial statements.
FASB ASC
820-10, Fair Value
Measurements and Disclosures, defines fair value, establishes a framework
for measuring fair value, and expands disclosures about fair value
measurements. It also emphasizes that fair value is a market-based
measurement, not an entity-specific measurement, and sets out a fair value
hierarchy with the highest priority being quoted prices in active
markets. Under FASB ASC 820-10, fair value measurements are disclosed
by level within that hierarchy. We adopted ASC 820-10 for the fiscal
year beginning January 1, 2008 with no material impact on our consolidated
financial statements. We adopted the delayed portion for nonfinancial
assets and nonfinancial liabilities that are recognized or disclosed at fair
value in the financial statements on a nonrecurring basis beginning January 1,
2009 with no material impact on our consolidated financial
statements.
FASB ASC
825-10-65, Interim Disclosures
about Fair Value of Financial Instruments requires disclosures about fair
value of financial instruments for interim reporting periods and amends FASB ASC
270-10 Interim
Reporting to require those disclosures in summarized financial
information at interim reporting periods. It was effective for all reporting
periods after June 15, 2009 and did not have a material impact on our
consolidated financial statements.
FASB ASC
855-10, Subsequent
Events, incorporates the accounting and disclosure requirements for
subsequent events into U.S. generally accepted accounting principles. FASB ASC
855-10 introduces new terminology, defines a date through which management must
evaluate subsequent events, and lists the circumstances under which an entity
must recognize and disclose events or transactions occurring after the
balance-sheet date. We adopted FASB ASC 855-10 as of June 30, 2009, which was
the required effective date.
6 Subsequent
Events: We evaluated subsequent events through November 5, 2009,
which represents the date the financial statements were issued. 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.
8
|
ITEM
2. MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
|
Overview
We own
producing and nonproducing mineral, royalty, overriding royalty, net profits and
leasehold interests. We refer to these interests as the Royalty Properties. We
currently own Royalty Properties in 574 counties and parishes in 25
states.
Dorchester
Minerals Operating LP, a Delaware limited partnership owned directly and
indirectly by our general partner, holds working interest properties and a minor
portion of mineral and royalty interest properties. We refer to Dorchester
Minerals Operating LP as the “operating partnership” or “DMOLP.” We directly and
indirectly own a 96.97% net profits overriding royalty interest (referred to as
Net Profits Interests, or NPIs) in property groups made up of four NPIs created
when we commenced operations in 2003 and one immaterial deficit NPI subsequently
created. We currently receive monthly payments equaling 96.97% of the preceding
month’s net profits actually realized by the operating partnership from three of
the property groups. The purpose of such Net Profits Interests 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. One such Net Profits Interest, referred to as the Minerals
NPI, has continuously had costs that exceed revenues. As of September
30, 2009, cumulative operating and development costs presented in the following
table, which include amounts equivalent to an interest charge, exceeded
cumulative revenues of the Minerals NPI, resulting in a cumulative deficit. All
cumulative deficits (which represent cumulative excess of operating and
development costs over revenue received) are borne 100% by our general partner
until the Minerals NPI recovers the deficit amount. Once in profit status, we
will receive the Net Profits Interest payments attributable to these properties.
Our consolidated financial statements do not reflect activity attributable to
properties subject to Net Profits Interests that are in a deficit
status. Consequently, Net Profits Interest
payments and production sales volumes and prices set forth in other portions of
this quarterly report do not reflect amounts attributable to the Minerals NPI,
which includes all of the operating partnership’s Fayetteville Shale working
interest properties in Arkansas.
The
following table sets forth receipts and disbursements attributable to the
Minerals NPI:
|
Minerals
NPI Results
(in
Thousands)
|
|||||||||||||
|
Cumulative
Total
at
12/31/08
|
Nine
Months
Ended
9/30/09
|
Cumulative
Total
at 9/30/09
|
|||||||||||
|
Cash
received for revenue
|
$ | 14,216 | $ | 2,518 | $ | 16,734 | |||||||
|
Cash
paid for operating costs
|
2,226 | 610 | 2,836 | ||||||||||
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Cash
paid for development costs
|
11,724 | 3,377 | 15,101 | ||||||||||
|
Budgeted
capital expenditures
|
905 | 481 | 1,386 | ||||||||||
|
Net
|
$ | (639 | ) | $ | (1,950 | ) | $ | (2,589 | ) | ||||
The
development costs pertain to more properties than the properties producing
revenue due to timing differences between operating partnership expenditures and
oil and natural gas production and payments to the operating
partnership. The amounts reflect the operating partnership’s
ownership of the subject properties. Net Profits Interest payments to
us, if any, will equal 96.97% of the cumulative net profits actually received by
the operating partnership attributable to subject properties. The
above financial information attributable to the 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 Net Profits Interest payments may begin from the
Minerals NPI.
Commodity
Price Risks
Our
profitability is affected by volatility in prevailing oil and natural gas
prices. Oil and natural gas prices have been subject to significant volatility
in recent years in response to changes in the supply and demand for oil and
natural gas in the market along with domestic and international political
economic conditions.
9
Results
of Operations
Three
and Nine Months Ended September 30, 2009 as compared to Three and Nine Months
Ended September 30, 2008
Normally,
our period-to-period changes in net earnings and cash flows from operating
activities are principally determined by changes in oil and natural gas sales
volumes and prices. Our portion of oil and natural gas sales and weighted
average prices were:
|
Three
Months Ended
|
Nine
Months Ended
|
|||||||||||||||||||
|
September
30,
|
June
30,
|
September
30,
|
||||||||||||||||||
|
Accrual
basis sales volumes:
|
2009
|
2008
|
2009
|
2009
|
2008
|
|||||||||||||||
|
Royalty
properties gas sales (mmcf)
|
1,148 | 1,000 | 1,019 | 3,204 | 2,864 | |||||||||||||||
|
Royalty
properties oil sales (mbbls)
|
71 | 77 | 80 | 225 | 229 | |||||||||||||||
|
Net
profits interests gas sales (mmcf)
|
915 | 961 | 903 | 2,705 | 2,922 | |||||||||||||||
|
Net
profits interests oil sales (mbbls)
|
3 | 2 | 3 | 9 | 9 | |||||||||||||||
|
Accrual
basis weighted average sales price:
|
||||||||||||||||||||
|
Royalty
properties gas sales ($/mcf)
|
$ | 3.39 | $ | 9.41 | $ | 3.47 | $ | 3.63 | $ | 9.31 | ||||||||||
|
Royalty
properties oil sales ($/bbl)
|
$ | 63.94 | $ | 115.62 | $ | 55.90 | $ | 52.74 | $ | 109.33 | ||||||||||
|
Net
profits interests gas sales ($/mcf)
|
$ | 3.04 | $ | 7.76 | $ | 2.95 | $ | 3.10 | $ | 9.23 | ||||||||||
|
Net
profits interests oil sales ($/bbl)
|
$ | 58.76 | N/A | $ | 55.70 | $ | 47.27 | $ | 118.47 | |||||||||||
|
Accrual
basis production costs deducted
|
||||||||||||||||||||
|
Under
the net profits interests ($/mcfe)
(1)
|
$ | 1.45 | $ | 1.90 | $ | 1.41 | $ | 1.44 | $ | 1.94 | ||||||||||
|
(1)
|
Provided
to assist in determination of revenues; applies only to Net Profits
Interest sales volumes and
prices.
|
Oil sales
volumes attributable to our Royalty Properties during the third quarter were
down 7.8% from 77 mbbls during the third quarter of 2008 to 71 mbbls in the same
period of 2009 due to normal production volume variations. Oil sales volumes
attributable to our Royalty Properties during the first nine months were down
slightly at 225 mbbls in 2009 compared to 229 mbbls in 2008. Natural gas sales
volumes attributable to our Royalty Properties during the third quarter
increased 14.8% from 1,000 mmcf in 2008 to 1,148 mmcf in 2009. Natural gas sales
volumes attributable to our Royalty Properties during the first nine months
increased 11.9% from 2,864 in 2008 to 3,204 mmcf in 2009. The increase in
natural gas sales volumes was primarily attributable to the acquisition of
properties in the Barnett Shale during the second quarter of 2009.
Oil sales
volumes attributable to our Net Profits Interests during the third quarter and
first nine months of 2009 were virtually unchanged when compared to the same
periods of 2008. Natural gas sales volumes attributable to our Net
Profits Interests during the third quarter and first nine months of 2009
decreased from the same periods of 2008. Third quarter sales volumes
of 915 mmcf during 2009 were 4.8% less than 961 mmcf during
2008. First nine month sales volumes of 2,705 mmcf during 2009 were
7.4% less than 2,922 mmcf during 2008. Both natural gas sales volume
decreases were a result of natural reservoir decline. Production
sales volumes and prices from the Minerals NPI are excluded from the above
table. See “Overview” above.
The
weighted average oil sales prices attributable to our interest in Royalty
Properties decreased 44.7% from $115.62/bbl during the third quarter of 2008 to
$63.94/bbl during the third quarter of 2009 and decreased 51.8% from $109.33/bbl
during the first nine months of 2008 to $52.74/bbl during the same period of
2009. Third quarter weighted average natural gas sales prices from
Royalty Properties decreased 64.0% from $9.41/mcf during 2008 to $3.39/mcf
during 2009. The nine months ended September 30 weighted average
Royalty Properties natural gas sales prices decreased 61.0% from $9.31/mcf
during 2008 to $3.63/mcf during 2009. Both oil and natural gas price
changes resulted from changing market conditions.
Third
quarter weighted average oil sales prices from the Net Profits Interests
properties decreased significantly from 2008 to $58.76/bbl in
2009. The third quarter of 2008 included a purchaser correction that
significantly distorted the price due to small volumes; thus, we have not shown
an average price in order to avoid confusion. The first nine months
Net Profits Interests’ oil sales prices decreased 60.1% from $118.47/bbl in 2008
to $47.27/bbl in 2009. Changing market conditions resulted in
decreased oil prices. Weighted average natural gas sales prices
attributable to the Net Profits Interests decreased during the third quarter of
2009 and first nine months of 2009 compared to the same periods of
2008. Third quarter natural gas sales prices of $3.04/mcf in 2009
were 60.8% less than $7.76/mcf in 2008. The nine months ended
September 30, 2009 natural gas prices decreased 66.4% to $3.10/mcf from
$9.23/mcf in the same period of 2008. Natural gas sales price
decreases during the three- and nine- month periods resulted from changing
market conditions and, to a lesser degree, a natural gas liquids payment
received in 2008 that related to prior year production. The natural
gas liquids payment is based on an Oklahoma Guymon-Hugoton field 1994 gas
delivery agreement that is in effect through 2015. Under the terms of
the
10
Our third
quarter net operating revenues decreased 56.3% from $24,487,000 during 2008 to
$10,706,000 during 2009. Net operating revenues for the first nine
months of 2009 decreased 60.9% from $74,747,000 during 2008 to $29,214,000
during 2009. Both the quarterly and nine-month decrease resulted from decreased
gas and oil sales prices combined with a 2007 natural gas liquid payment
received during the second quarter 2008.
Costs and
expenses increased 5.0% from $6,010,000 during the third quarter of 2008 to
$6,312,000 during the third quarter of 2009, while nine months ended September
30 costs and expenses decreased 7.5% from $17,855,000 during 2008 to $16,520,000
during 2009. The third quarter increase primarily resulted from
increased depletion related to the Barnett Shale acquisition at the end of the
second quarter partially offset by decreased production tax on lower operating
revenues. The decrease in the nine-month period primarily resulted
from decreased production tax.
Depletion
and amortization increased 19.8% during the third quarter ended September 30,
2009 and 0.7% during the nine months ended September 30, 2009 when
compared to the same periods of 2008. The increases from $3,775,000
and $11,213,000 during the third quarter and nine months ended
September 30, 2008, respectively, to $4,524,000 and $11,297,000 during
the same periods of 2009 respectively, resulted primarily from a higher
depletable base due to the June 30, 2009 acquisition of properties in the
Barnett Shale.
Third
quarter net earnings allocable to common units decreased 76.3% from $17,997,000
during 2008 to $4,263,000 during 2009. First nine months common unit
net earnings decreased 77.5% from $55,448,000 during 2008 to $12,476,000 during
2009. Both decreases are primarily the result of decreased oil and
natural gas sales prices.
Net cash
provided by operating activities decreased 67.3% from $28,082,000 during the
third quarter of 2008 to $9,181,000 during the third quarter of 2009 and
decreased 57.8% from $67,968,000 for the first nine months during 2008 to
$28,692,000 during the same period of 2009. Decreases in both periods
are primarily due to decreased oil and natural gas sales prices.
In an
effort to provide the reader with information concerning prices of oil and
natural gas sales that correspond to our quarterly distributions, management
calculates the weighted average price by dividing gross revenues received by the
net volumes of the corresponding product without regard to the timing of the
production to which such sales may be attributable. This “indicated
price” does not necessarily reflect the contract terms for such sales and may be
affected by transportation costs, location differentials, and quality and
gravity adjustments. While the relationship between our cash receipts and the
timing of the production of oil and natural gas may be described generally,
actual cash receipts may be materially impacted by purchasers’ release of
suspended funds and by purchasers’ prior period adjustments.
Cash
receipts attributable to our Royalty Properties during the 2009 third quarter
totaled approximately $7,800,000. These receipts generally reflect oil sales
during June through August 2009 and natural gas sales during May through July
2009. The weighted average indicated prices for oil and natural gas
sales during the 2009 third quarter attributable to the Royalty Properties were
$62.52/bbl and $3.46/mcf, respectively.
Cash
receipts attributable to our Net Profits Interests during the 2009 third quarter
totaled approximately $1,600,000. These receipts reflect oil and natural gas
sales from the properties underlying the Net Profits Interests generally during
May through July 2009. The weighted average indicated prices received
during the 2009 third quarter for oil and natural gas sales were $55.30/bbl and
$3.07/mcf, respectively.
We
received cash payments of approximately $560,000 from various sources during the
third quarter of 2009 including lease bonuses attributable to 25 consummated
leases and pooling elections located in five counties and parishes in three
states. The consummated leases reflected royalty terms ranging up to 25% and
lease bonuses ranging up to $1,200/acre.
We
received division orders for, or otherwise identified, 71 new wells completed on
our Royalty Properties and Net Profits Interests located in 38 counties and
parishes in seven states during the third quarter of 2009. The operating
partnership elected to participate in ten wells to be drilled on our Net Profits
Interests located in three counties in Arkansas. Selected new wells and the
royalty interests owned by us and the working and net revenue interests owned by
the operating partnership are summarized in the tables below.
11
This
table does not include wells drilled in the Fayetteville Shale trend as they are
detailed in a subsequent discussion and table.
|
County
|
DMLP
|
DMOLP
|
Test Rates per day
|
||||||||
|
State
|
/Parish
|
Operator
|
Well Name
|
NRI(2)
|
WI(1)
|
NRI(2)
|
Gas, mcf
|
Oil, bbls
|
|||
|
ND
|
Dunn
|
Marathon
Oil Co.
|
Borth
41-14 H
|
0.916%
|
--
|
--
|
207
|
451
|
|||
|
ND
|
Dunn
|
Marathon
Oil Co.
|
Gehrer
21-14 H
|
0.916%
|
--
|
--
|
1,640
|
396
|
|||
|
OK
|
Garvin
|
Cimarex
Energy Co.
|
Cole
1-5
|
1.363%
|
--
|
--
|
292
|
484
|
|||
|
OK
|
Garvin
|
Cimarex
Energy Co.
|
Howard
D 4-17 ENT
|
1.563%
|
--
|
--
|
215
|
181
|
|||
|
TX
|
Hidalgo
|
Dewbre
Petroelum
|
E.E.
Guerra 20
|
0.521%
|
--
|
--
|
7,205
|
--
|
|||
|
TX
|
Shelby
|
Devon
Energy Corp.
|
Oliver
Gas Unit 4
|
0.360%
|
--
|
--
|
19,623
|
--
|
|||
|
TX
|
Upton
|
Hunt
Oil Co.
|
V.T.
Amacker 105 15H
|
0.977%
|
--
|
--
|
3,191
|
--
|
|||
|
(1)
|
WI
means the working interest owned by the operating partnership and subject
to a 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 a Net Profits Interest.
|
FAYETTEVILLE
SHALE TREND OF NORTHERN ARKANSAS – We own varying undivided perpetual mineral
interests totaling 23,336/11,464 gross/net acres located in Cleburne, Conway,
Faulkner, Franklin, Johnson, Pope, Van Buren, and White counties, Arkansas in an
area commonly referred to as the “Fayetteville Shale” trend of the Arkoma
Basin. One hundred eighty-two wells have been permitted on the lands
as of September 30, 2009. Wells that have been proposed to
be drilled by the operator but for which permits have not yet been issued by the
Arkansas Oil & Gas Commission are not reflected in this
number. Available test results for new wells producing in the third
quarter, 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.
|
DMLP
|
DMOLP
|
Gas
Test Rates
|
|||||||
|
County
|
Operator
|
Well Name
|
NRI(2)
|
WI(1)
|
NRI(2)
|
mcf per day
|
|||
|
Conway
|
Chesapeake
|
Collinsworth
7-16 #1-10H3
|
2.312%
|
4.553%
|
3.414%
|
4,815
|
|||
|
Conway
|
SEECO
|
Green
Bay Packaging 9-15 #3-19H
|
0.056%
|
0.000%
|
0.000%
|
4,221
|
|||
|
Conway
|
SEECO
|
Green
Bay Packaging 9-15 #4-19H
|
0.056%
|
0.000%
|
0.000%
|
4,242
|
|||
|
Conway
|
SEECO
|
Polk
9-15 #4-30H
|
5.930%
|
5.561%
|
4.220%
|
2,434
|
|||
|
Faulkner
|
Chesapeake
|
Glover
8-13 #1-25H
|
3.222%
|
7.185%
|
5.648%
|
1,433
|
|||
|
Faulkner
|
Chesapeake
|
Glover
8-13 #2-25H
|
2.990%
|
4.807%
|
3.614%
|
2,439
|
|||
|
Van
Buren
|
Chesapeake
|
Collister
12-13 #2-32H
|
1.561%
|
1.274%
|
0.956%
|
228
|
|||
|
Van
Buren
|
Chesapeake
|
Collister
12-13 #3-32H
|
1.561%
|
1.274%
|
0.956%
|
469
|
|||
|
Van
Buren
|
Petrohawk
|
Green
Bay 11-14 #1-20H
|
0.703%
|
0.000%
|
0.000%
|
723
|
|||
|
Van
Buren
|
Petrohawk
|
Trahan
11-14 #1-30H
|
0.039%
|
0.000%
|
0.000%
|
4,144
|
|||
|
Van
Buren
|
SEECO
|
Handy
10-12 #3-18H19
|
0.395%
|
0.944%
|
0.708%
|
4,180
|
|||
|
Van
Buren
|
SEECO
|
Handy
10-12 #4-18H
|
2.971%
|
6.344%
|
4.758%
|
2,876
|
|||
|
Van
Buren
|
SEECO
|
Handy
10-12 #5-18H
|
2.972%
|
6.347%
|
4.760%
|
3,679
|
|||
|
Van
Buren
|
SEECO
|
Handy
10-12 #6-18H
|
2.972%
|
6.347%
|
4.760%
|
3,422
|
|||
|
Van
Buren
|
SEECO
|
Howard
Family Trust 10-12 #2-9H16
|
2.594%
|
4.576%
|
3.432%
|
5,184
|
|||
|
(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.
|
12
Set forth
below are totals and a summary of permitting, drilling and completion activity
through September 30, 2009 for wells in which we have a royalty interest or
Net Profits Interest. This includes wells subject to the Minerals
NPI, which is currently in a deficit status.
|
Total
to
date
(2)
|
Year
2006
|
Year
2007
|
Q1 2008 | Q2 2008 | Q3 2008 | Q4 2008 | Q1 2009 | Q2 2009 | Q3 2009 | |||||||||||||||||||||||||||||||
|
New
Well Permits
|
180 | 11 | 35 | 16 | 21 | 12 | 21 | 19 | 20 | 22 | ||||||||||||||||||||||||||||||
|
Wells
Spud
|
145 | 9 | 33 | 12 | 17 | 20 | 13 | 21 | 15 | 4 | ||||||||||||||||||||||||||||||
|
Wells
Completed
|
126 | 5 | 23 | 10 | 17 | 12 | 17 | 13 | 14 | 14 | ||||||||||||||||||||||||||||||
|
Wells
in Pay Status (1)
|
85 | 0 | 14 | 4 | 7 | 14 | 7 | 14 | 10 | 14 | ||||||||||||||||||||||||||||||
|
(1)
|
Wells
in pay status means wells for which revenue was initially received during
the indicated period.
|
|
(2)
|
Includes
activity since 2004.
|
Net cash
receipts for the Royalty Properties attributable to interests in these lands
totaled $306,000 in the third quarter from 72 wells. Net cash
receipts for the Minerals NPI Properties attributable to interests in these
lands totaled approximately $280,000 in the third quarter from 44
wells.
BARNETT
SHALE –- 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 in what is 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 September 30, 2009, 34 wells were drilled from 11 padsites
located on or adjacent to the properties, of which 27 wells were completed for
production and seven were drilled but not yet completed or connected to a
pipeline. Permits to drill two additional wells on the properties had
been issued by regulatory agencies.
HORIZONTAL
BAKKEN, WILLISTON BASIN – We own varying undivided perpetual mineral interests
totaling 70,390/7,602 gross/net acres located in Burke, Divide, Dunn, McKenzie,
Mountrail and Williams Counties, North Dakota. Operators active in
this area include Continental Resources, EOG Resources, Hess Corporation and
Marathon Oil Company. Seventy-nine wells have been permitted on these
lands as of September 30, 2009. In all cases we have elected not to
lease our lands and not to pay our share of well costs thus becoming a
non-consenting mineral owner. According to North Dakota law,
non-consenting 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 and will
be subject to the Minerals NPI. Non-consenting owners are not entitled to well
data other than public information available from the North Dakota Industrial
Commission.
Set forth
below are totals and a summary of permitting, drilling and completion activity
through September 30, 2009 for wells in which we have a royalty interest or
Net Profits Interest.
|
Total
to
Date(2)
|
Year
2006
|
Year
2007
|
Q1
2008
|
Q2
2008
|
Q3
2008
|
Q4
2008
|
Q1
2009
|
Q2
2009
|
Q3
2009
|
||||||||||
|
New
Well Permits
|
82
|
0
|
16
|
10
|
17
|
16
|
14
|
0
|
6
|
0
|
|||||||||
|
Wells
Spud
|
69
|
0
|
12
|
2
|
10
|
11
|
10
|
11
|
4
|
7
|
|||||||||
|
Wells
Completed
|
54
|
0
|
7
|
5
|
5
|
11
|
6
|
12
|
5
|
1
|
|||||||||
|
WI
Wells in Pay Status(1)
|
3
|
0
|
0
|
0
|
2
|
1
|
0
|
0
|
0
|
0
|
|
|
(1)
|
Wells
in pay status means wells for which revenue was initially received during
the indicated period.
|
|
|
(2)
|
Includes
activity since 2004.
|
APPALACHIAN
BASIN — We own varying undivided perpetual mineral interests in approximately
31,000/22,000 gross/net acres in 19 counties in southern New York and northern
Pennsylvania. Approximately 75% of these net acres are located in
eastern Allegany and western Steuben Counties in New York, an area which some
industry press reports suggest may be prospective for gas production from
unconventional reservoirs including the Marcellus Shale. We are
monitoring industry activity and encouraging dialogue with industry participants
to determine the proper course of action regarding our interests.
13
Liquidity
and Capital Resources
Capital
Resources
Our
primary sources of capital are our cash flow from the Net Profits Interests and
the Royalty Properties. Our only cash requirements are the distributions to our
unitholders, the payment of oil and natural gas production and property taxes
not otherwise deducted from gross production revenues and general and
administrative expenses incurred on our behalf and allocated in accordance with
our partnership agreement. Since the distributions to our unitholders are, by
definition, determined after the payment of all expenses actually paid by us,
the only cash requirements that may create liquidity concerns for us are the
payments of expenses. Since most of these expenses vary directly with oil and
natural gas sales prices and volumes, we anticipate that sufficient funds will
be available at all times for payment of these expenses. See Note 4 of the Notes
to the Condensed Consolidated Financial Statements for the amounts and dates of
cash distributions to unitholders.
We are
not directly liable for the payment of any exploration, development or
production costs. We do not have any transactions, arrangements or other
relationships that could materially affect our liquidity or the availability of
capital resources. We have not guaranteed the debt of any other party, nor do we
have any other arrangements or relationships with other entities that could
potentially result in unconsolidated debt.
Pursuant
to the terms of our partnership agreement, we cannot incur indebtedness, other
than trade payables, (i) in excess of $50,000 in the aggregate at any given time
or (ii) which would constitute “acquisition indebtedness” (as defined in Section
514 of the Internal Revenue Code of 1986, as amended).
Expenses
and Capital Expenditures
The
operating partnership plans to continue its efforts to increase production in
Oklahoma with techniques that may include fracture treating, deepening,
recompleting, and drilling. Costs of such techniques vary widely and
are not predictable as each effort requires specific engineering. The
operating partnership owns and operates the wells, pipelines and natural gas
compression and dehydration facilities located in Kansas and Oklahoma. The
operating partnership anticipates gradual increases in expenses as repairs to
these facilities become more frequent and anticipates gradual increases in field
operating expenses as reservoir pressure declines. The operating partnership
believes it now has sufficient field compression and permits for vacuum
operation for the foreseeable future. The operating partnership does not
anticipate incurring significant expense to replace these facilities at this
time. These capital and operating costs influence the Net Profits
Interests payments we receive from the operating partnership and are included in
the accrual basis production costs $/mcfe in the table under “Results of
Operations.”
Liquidity
and Working Capital
Cash and
cash equivalents totaled $10,012,000 at September 30, 2009 and $16,211,000
at December 31, 2008.
Critical
Accounting Policies
We
utilize the full cost method of accounting for costs related to our oil and
natural gas properties. Under this method, all such costs are capitalized and
amortized on an aggregate basis over the estimated lives of the properties using
the units-of-production method. These capitalized costs are subject to a ceiling
test, however, which limits such pooled costs to the aggregate of the present
value of future net revenues attributable to proved oil and natural gas reserves
discounted at 10% plus the lower of cost or market value of unproved properties.
Oil and natural gas properties are evaluated using the full cost ceiling test at
the end of each quarter and when events indicate possible
impairment.
The
discounted present value of our proved oil and natural gas reserves is a major
component of the ceiling calculation and requires many subjective judgments.
Estimates of reserves are forecasts based on engineering and geological
analyses. Different reserve engineers may reach different conclusions as to
estimated quantities of natural gas reserves based on the same information. Our
reserve estimates are prepared by independent consultants. The passage of time
provides more qualitative information regarding reserve estimates, and revisions
are made to prior estimates based on updated information. However, there can be
no assurance that significant revisions will not be necessary in the future.
Significant downward revisions could result in an impairment representing a
non-cash charge to earnings. In addition to the impact on calculation of the
ceiling test, estimates of proved reserves are also a major component of the
calculation of depletion.
14
While the
quantities of proved reserves require substantial judgment, the associated
prices of oil and natural gas reserves that are included in the discounted
present value of our reserves are objectively determined. The ceiling test
calculation requires use of prices and costs in effect as of the last day of the
accounting period, which are generally held constant for the life of the
properties. As a result, the present value is not necessarily an indication of
the fair value of the reserves. Oil and natural gas prices have historically
been volatile and the prevailing prices at any given time may not reflect our
Partnership’s or the industry’s forecast of future prices.
The
preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. For example, estimates of uncollected revenues and
unpaid expenses from royalties and net profits interests in properties operated
by non-affiliated entities are particularly subjective due to our inability to
gain accurate and timely information. Therefore, actual results could differ
from those estimates.
The
following information provides quantitative and qualitative information about
our potential exposures to market risk. The term “market risk” refers to the
risk of loss arising from adverse changes in oil and natural gas prices,
interest rates and currency exchange rates. The disclosures are not meant to be
precise indicators of expected future losses but, rather, indicators of possible
losses.
Market
Risk Related to Oil and Natural Gas Prices
Essentially
all of our assets and sources of income are from Royalty Properties and the Net
Profits Interests, which generally entitle us to receive a share of the proceeds
based on oil and natural gas production from those properties. Consequently, we
are subject to market risk from fluctuations in oil and natural gas prices.
Pricing for oil and natural gas production has been volatile and unpredictable
for several years. We do not anticipate entering into financial hedging
activities intended to reduce our exposure to oil and natural gas price
fluctuations.
Absence
of Interest Rate and Currency Exchange Rate Risk
We do not
anticipate having a credit facility or incurring any debt, other than trade
debt. Therefore, we do not expect interest rate risk to be material to us. We do
not anticipate engaging in transactions in foreign currencies that could expose
us to foreign currency related market risk.
Evaluation
of Disclosure Controls and Procedures
As of the
end of the period covered by this report, our principal executive officer and
principal financial officer carried out an evaluation of the effectiveness of
our disclosure controls and procedures. Based on their evaluation, they have
concluded that our disclosure controls and procedures were
effective.
Changes
in Internal Controls
There
were no changes in our internal controls (as defined in Rule 13a-15(f) of the
Securities Exchange Act of 1934) during the quarter ended September 30, 2009
that have materially affected, or are reasonably likely to materially affect,
our internal controls over financial reporting.
15
PART
II
See Note
2 – Contingencies in Notes to the Condensed Consolidated Financial
Statements.
There
have been no material changes from the risk factors disclosed in
Item 1A. Risk Factors of our Annual Report on Form 10-K
for the year ended December 31, 2008 and our Quarterly Report on Form 10-Q
for the quarter ended June 30, 2009 other than the following:
Several
proposals are before the U.S. Congress that, if implemented, would either
prohibit the practice of hydraulic fracturing or subject the process to
regulation. Hydraulic fracturing involves the injection of water,
sand and chemicals under pressure into rock formations to stimulate
production. The use of hydraulic fracturing is necessary to produce
commercial quantities of natural gas and oil from many
reservoirs. Although it is not possible at this time to predict the
final outcome of the legislation, any new federal restrictions on hydraulic
fracturing could significantly increase operating, capital and compliance
costs. Such cost increases could delay or restrict development by
operators of our oil and gas properties.
ITEM
2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE
OF PROCEEDS
None.
None.
ITEM
5. OTHER INFORMATION
None.
See the
attached Index to Exhibits.
16
SIGNATURES
Pursuant
to the requirements of the Securities Exchange Act of 1934, the Registrant has
duly caused this report to be signed on its behalf by the undersigned thereunto
duly authorized.
|
DORCHESTER
MINERALS, L.P.
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By:
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Dorchester
Minerals Management LP
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its
General Partner
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By:
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Dorchester
Minerals Management GP LLC
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its
General Partner
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By:
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/s/
William Casey McManemin
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William
Casey McManemin
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Date:
November 5, 2009
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Chief
Executive Officer
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By:
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/s/
H.C. Allen, Jr.
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H.C.
Allen, Jr.
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Date:
November 5, 2009
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Chief
Financial Officer
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17
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Number
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Description
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3.1
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Certificate
of Limited Partnership of Dorchester Minerals, L.P. (incorporated by
reference to Exhibit 3.1 to Dorchester Minerals’ Registration Statement on
Form S-4, Registration Number 333-88282)
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3.2
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Amended
and Restated Agreement of Limited Partnership of Dorchester Minerals, L.P.
(incorporated by reference to Exhibit 3.2 to Dorchester Minerals’ Report
on Form 10-K filed for the year ended December 31,
2002)
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3.3
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Certificate
of Limited Partnership of Dorchester Minerals Management LP (incorporated
by reference to Exhibit 3.4 to Dorchester Minerals’ Registration Statement
on Form S-4, Registration Number 333-88282)
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3.4
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Amended
and Restated Agreement of Limited Partnership of Dorchester Minerals
Management LP (incorporated by reference to Exhibit 3.4 to Dorchester
Minerals’ Report on Form 10-K for the year ended December 31,
2002)
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3.5
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Certificate
of Formation of Dorchester Minerals Management GP LLC (incorporated by
reference to Exhibit 3.7 to Dorchester Minerals’ Registration Statement on
Form S-4, Registration Number 333-88282)
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3.6
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Amended
and Restated Limited Liability Company Agreement of Dorchester Minerals
Management GP LLC (incorporated by reference to Exhibit 3.6 to Dorchester
Minerals’ Report on Form 10-K for the year ended December 31,
2002)
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3.7
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Certificate
of Formation of Dorchester Minerals Operating GP LLC (incorporated by
reference to Exhibit 3.10 to Dorchester Minerals’ Registration Statement
on Form S-4, Registration Number 333-88282)
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3.8
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Limited
Liability Company Agreement of Dorchester Minerals Operating GP LLC
(incorporated by reference to Exhibit 3.11 to Dorchester Minerals’
Registration Statement on Form S-4, Registration Number
333-88282)
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3.9
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Certificate
of Limited Partnership of Dorchester Minerals Operating LP (incorporated
by reference to Exhibit 3.12 to Dorchester Minerals’ Registration
Statement on Form S-4, Registration Number 333-88282)
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3.10
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Amended
and Restated Agreement of Limited Partnership of Dorchester Minerals
Operating LP. (incorporated by reference to Exhibit 3.10 to Dorchester
Minerals’ Report on Form 10-K for the year ended December 31,
2002)
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3.11
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Certificate
of Limited Partnership of Dorchester Minerals Oklahoma LP (incorporated by
reference to Exhibit 3.11 to Dorchester Minerals’ Report on Form 10-K for
the year ended December 31, 2002)
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3.12
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Agreement
of Limited Partnership of Dorchester Minerals Oklahoma LP (incorporated by
reference to Exhibit 3.12 to Dorchester Minerals’ Report on Form 10-K for
the year ended December 31, 2002)
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3.13
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Certificate
of Incorporation of Dorchester Minerals Oklahoma GP, Inc. (incorporated by
reference to Exhibit 3.13 to Dorchester Minerals’ Report on Form 10-K for
the year ended December 31, 2002)
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3.14
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Bylaws
of Dorchester Minerals Oklahoma GP, Inc. (incorporated by reference to
Exhibit 3.14 to Dorchester Minerals’ Report on Form 10-K for the year
ended December 31, 2002)
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3.15
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Certificate
of Limited Partnership of Dorchester Minerals Acquisition LP (incorporated
by reference to Exhibit 3.15 to Dorchester Minerals’ Report on Form 10-K
for the year ended December 31, 2004)
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3.16
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Agreement
of Limited Partnership of Dorchester Minerals Acquisition LP (incorporated
by reference to Exhibit 3.16 to Dorchester Minerals’ Report on Form 10-Q
for the quarter ended September 30, 2004)
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3.17
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Certificate
of Incorporation of Dorchester Minerals Acquisition GP, Inc. (incorporated
by reference to Exhibit 3.17 to Dorchester Minerals’ Report on Form 10-Q
for the quarter ended September 30, 2004)
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3.18
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Bylaws
of Dorchester Minerals Acquisition GP, Inc. (incorporated by reference to
Exhibit 3.18 to Dorchester Minerals’ Report on Form 10-Q for the quarter
ended September 30, 2004)
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31.1*
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Certification
of Chief Executive Officer of the Partnership pursuant to Rule 13a-14(a)
of the Securities Exchange Act of 1934
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31.2*
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Certification
of Chief Financial Officer of the Partnership pursuant to Rule 13a-14(a)
of the Securities Exchange Act of 1934
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32.1*
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Certification
of Chief Executive Officer of the Partnership pursuant to 18 U.S.C. Sec.
1350
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32.2*
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Certification
of Chief Financial Officer of the Partnership pursuant to 18 U.S.C. Sec.
1350 (contained within Exhibit 32.1
hereto)
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* Filed
herewith
18