DORCHESTER MINERALS, L.P. - Quarter Report: 2009 March (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 March 31,
2009
|
Commission
file number
000-50175
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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 May 6, 2009, 28,240,431 common units of partnership interest were
outstanding.
TABLE OF
CONTENTS
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3
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3
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ITEM
1.
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FINANCIAL INFORMATION
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5
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6
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7
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ITEM
2.
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ITEM
3.
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ITEM
4
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14
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ITEM
1.
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14
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ITEM
1A.
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14
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ITEM
2.
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14
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ITEM
3.
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14
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ITEM
4.
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14
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ITEM
5.
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14
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ITEM
6.
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2
DISCLOSURE
REGARDING FORWARD-LOOKING STATEMENTS
Statements
included in this report that are not historical facts (including any statements
concerning plans and objectives of management for future operations or economic
performance, or assumptions or forecasts related thereto), are forward-looking
statements. These statements can be identified by the use of forward-looking
terminology including “may,” “believe,” “will,” “expect,” “anticipate,”
“estimate,” “continue” or other similar words. These statements discuss future
expectations, contain projections of results of operations or of financial
condition or state other “forward-looking” information. In this report, the term
“Partnership,” as well as the terms “DMLP,” “us,” “our,” “we,” and “its” are
sometimes used as abbreviated references to Dorchester Minerals, L.P. itself or
Dorchester Minerals, L.P. and its related entities.
These
forward-looking statements are based upon management’s current plans,
expectations, estimates, assumptions and beliefs concerning future events
impacting us and, therefore, involve a number of risks and uncertainties. We
caution that forward-looking statements are not guarantees and that actual
results could differ materially from those expressed or implied in the
forward-looking statements for a number of important reasons. Examples of such
reasons include, but are not limited to, changes in the price or demand for oil
and natural gas, changes in the operations on or development of our properties,
changes in economic and industry conditions and changes in regulatory
requirements (including changes in environmental requirements) and our financial
position, business strategy and other plans and objectives for future
operations. These and other factors are set forth in our filings with the
Securities and Exchange Commission.
You
should read these statements carefully because they discuss our expectations
about our future performance, contain projections of our future operating
results or our future financial condition, or state other “forward-looking”
information. Before you invest, you should be aware that the occurrence of any
of the events described in this report could substantially harm our business,
results of operations and financial condition and that upon the occurrence of
any of these events, the trading price of our common units could decline, and
you could lose all or part of your investment.
See
attached financial statements on the following pages.
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DORCHESTER
MINERALS, L.P.
|
||||||||
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(A
Delaware Limited Partnership)
|
||||||||
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CONDENSED CONSOLIDATED BALANCE SHEETS
|
||||||||
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(In
Thousands)
|
||||||||
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March
31,
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December
31,
|
|||||||
|
2009
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2008
|
|||||||
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ASSETS
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(unaudited)
|
|||||||
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Current
assets:
|
||||||||
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Cash
and cash equivalents
|
$ | 12,039 | $ | 16,211 | ||||
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Trade
and other receivables
|
3,660 | 5,053 | ||||||
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Net
profits interests receivable - related party
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1,122 | 4,428 | ||||||
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Prepaid
expenses
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37 | - | ||||||
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Total
current assets
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16,858 | 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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291,897 | 291,818 | ||||||
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Less
accumulated full cost depletion
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181,560 | 178,272 | ||||||
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Total
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110,337 | 113,546 | ||||||
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Leasehold
improvements
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512 | 512 | ||||||
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Less
accumulated amortization
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219 | 207 | ||||||
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Total
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293 | 305 | ||||||
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Net
property and leasehold improvements
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110,630 | 113,851 | ||||||
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Total
assets
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$ | 127,507 | $ | 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
|
$ | 739 | $ | 733 | ||||
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Current
portion of deferred rent incentive
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39 | 39 | ||||||
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Total
current liabilities
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778 | 772 | ||||||
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Deferred
rent incentive less current portion
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198 | 208 | ||||||
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Total
liabilities
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976 | 980 | ||||||
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Commitments
and contingencies
|
||||||||
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Partnership
capital:
|
||||||||
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General
partner
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5,573 | 5,971 | ||||||
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Unitholders
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120,958 | 132,611 | ||||||
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Total
partnership capital
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126,531 | 138,582 | ||||||
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Total
liabilities and partnership capital
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$ | 127,507 | $ | 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)
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Three
Months Ended
|
||||||||
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March
31,
|
||||||||
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2009
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2008
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|||||||
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Operating
revenues:
|
||||||||
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Royalties
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$ | 7,025 | $ | 14,771 | ||||
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Net
profits interests
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1,782 | 6,365 | ||||||
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Lease
bonus
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9 | 117 | ||||||
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Other
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8 | 19 | ||||||
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Total
operating revenues
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8,824 | 21,272 | ||||||
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Costs
and expenses:
|
||||||||
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Operating,
including production taxes
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739 | 1,191 | ||||||
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Depletion
and amortization
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3,300 | 3,790 | ||||||
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General
and administrative expenses
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1,035 | 1,011 | ||||||
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Total
costs and expenses
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5,074 | 5,992 | ||||||
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Operating
income
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3,750 | 15,280 | ||||||
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Other
income, net
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27 | 130 | ||||||
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Net
earnings
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$ | 3,777 | $ | 15,410 | ||||
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Allocation
of net earnings:
|
||||||||
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General
partner
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$ | 123 | $ | 463 | ||||
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Unitholders
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$ | 3,654 | $ | 14,947 | ||||
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Net
earnings per common unit (basic and diluted)
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$ | 0.13 | $ | 0.53 | ||||
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Weighted
average common units outstanding
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28,240 | 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)
|
Year
Ended
|
||||||||
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March
31,
|
||||||||
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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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$ | 11,735 | $ | 17,203 | ||||
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Cash
flows used in investing activities:
|
||||||||
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Capital
expenditures
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(79 | ) | (50 | ) | ||||
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Cash
flows used in financing activities:
|
||||||||
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Distributions
paid to general partner and unitholders
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(15,828 | ) | (14,996 | ) | ||||
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(Decrease)
increase in cash and cash equivalents
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(4,172 | ) | 2,157 | |||||
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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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$ | 12,039 | $ | 17,158 | ||||
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.
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.
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. Distributions
to Holders of Common Units: Unitholder cash distributions per common unit
since 2005 have been:
|
Per
Unit Amount
|
||||||||||
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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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|||||
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Second
quarter
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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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Third
quarter
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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
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||||||
Distributions
were paid on 28,240,431 units. Fourth quarter distributions shown
above are paid in the first calendar quarter of the following
year. Our partnership agreement requires the next cash distribution
to be paid by August 15, 2009.
7
4. New
Accounting Pronouncements: In September 2006, the Financial
Accounting Standards Board (“FASB”) issued Statement of Accounting Standards
No. 157, Fair Value Measurements (“SFAS 157”). SFAS 157 defines fair value,
establishes a framework for measuring fair value, and expands disclosures about
fair value measurements. SFAS 157 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 SFAS 157, fair value measurements are disclosed by
level within that hierarchy. In February 2008, the FASB
issued FASB Staff Position 157-2, Effective Date of FASB Statement No.
157 which permits a one year deferral for the implementation of SFAS 157
with regard to nonfinancial assets and liabilities that are not recognized or
disclosed at fair value in the financial statements on a recurring
basis. We adopted SFAS 157 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.
In
December 2007, the FASB issued Statement of Financial Accounting Standards 141
(revised 2007), Business
Combinations (SFAS 141(R)). SFAS 141(R), 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)
recognizes and measures the goodwill acquired in the business combination or a
gain from a bargain purchase, and (d) 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 SFAS 141(R) as of
January 1, 2009. The adoption had no immediate impact on our consolidated
financial statements.
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 573 counties and parishes in 25
states.
Dorchester
Minerals Operating LP, a Delaware limited partnership owned directly and
indirectly by our general partner, holds working 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 March 31,
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.
8
The following table sets forth
receipts and disbursements attributable to the Minerals NPI:
|
Minerals
NPI Results
(in
Thousands)
|
||||||||||||
|
Cumulative
Total
at
12/31/08
|
Three
Months
Ended
3/31/09
|
Cumulative
Total
at
3/31/09
|
||||||||||
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Cash
received for revenue
|
$ | 14,216 | $ | 777 | $ | 14,993 | ||||||
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Cash
paid for operating costs
|
2,226 | 184 | 2,410 | |||||||||
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Cash
paid for development costs
|
11,724 | 782 | 12,506 | |||||||||
|
Budgeted
capital expenditures
|
905 | 26 | 931 | |||||||||
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Net
|
$ | (639 | ) | $ | (215 | ) | $ | (854 | ) | |||
|
Cumulative
NPI deficit
|
$ | (639 | ) | $ | (854 | ) | $ | (854 | ) | |||
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 budgeted capital expenditures
of $931,000 at March 31, 2009. The amounts also reflect the operating
partnership’s ownership of the subject properties. Net Profits
Interest payments to us, if any, will equal 96.97% of the cumulative net profits
actually received by the operating partnership attributable to subject
properties. The above financial information attributable to the
Minerals NPI may not be indicative of future results of the Minerals NPI and may
not indicate when the deficit status may end and when Net Profits Interest
payments may begin from the Minerals NPI.
Commodity
Price Risks
Our
profitability is affected by volatility in prevailing oil and natural gas
prices. Oil and natural gas prices have been subject to significant volatility
in recent years in response to changes in the supply and demand for oil and
natural gas in the market along with domestic and international political
economic conditions.
Results
of Operations
Three
Months Ended March 31, 2009 as compared to Three Months Ended March 31,
2008
Normally,
our period-to-period changes in net earnings and cash flows from operating
activities are principally determined by changes in oil and natural gas sales
volumes and prices. Our portion of oil and natural gas sales and weighted
average prices were:
|
Three
Months Ended
|
|||||||||
|
March
31,
|
|||||||||
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Accrual
basis sales volumes:
|
2009
|
2008
|
|||||||
|
Royalty
properties gas sales (mmcf)
|
1,037 | 992 | |||||||
|
Royalty
properties oil sales (mbbls)
|
74 | 72 | |||||||
|
Net
profits interests gas sales (mmcf)
|
887 | 987 | |||||||
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Net
profits interests oil sales (mbbls)
|
3 | 4 | |||||||
|
Accrual
basis weighted average sales price:
|
|||||||||
|
Royalty
properties gas sales ($/mcf)
|
$ | 4.05 | $ | 7.96 | |||||
|
Royalty
properties oil sales ($/bbl)
|
$ | 38.45 | $ | 94.88 | |||||
|
Net
profits interests gas sales ($/mcf)
|
$ | 3.32 | $ | 8.04 | |||||
|
Net
profits interests oil sales ($/bbl)
|
$ | 28.63 | $ | 80.10 | |||||
|
Accrual
basis production costs deducted
|
|||||||||
|
under the net profits interests
($/mcfe)
(1)
|
$ | 1.45 | $ | 1.99 | |||||
|
|
(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 first quarter were
essentially unchanged from the first quarter of 2008. Natural gas sales volumes
attributable to our Royalty Properties during the first quarter increased 4.5%
from 992 mmcf in 2008 to 1,037 mmcf in 2009. The increase in natural gas sales
volume was primarily attributable to results from new drilling activity in
the second half of 2008.
9
Oil sales
volumes attributable to our Net Profits Interests during the first quarter of
2009 were virtually unchanged when compared to the same period of
2008. Natural gas sales volumes attributable to our Net Profits
Interests during the first quarter of 2009 decreased from the same period of
2008. First quarter sales of 887 mmcf during 2009 were 10.1% less
than 987 mmcf during 2008. Natural gas sales volume decreases were
primarily a result of severe cold weather freezing gas production facilities and
natural reservoir decline in the Guymon-Hugoton field in
Oklahoma. Production sales volumes and prices from the Minerals NPI
are excluded from the above table. See “Overview” above.
The
weighted average oil sales price attributable to our interest in Royalty
Properties decreased 59.5% from $94.88/bbl during the first quarter of 2008 to
$38.45/bbl during the first quarter of 2009. The first quarter
weighted average natural gas sales price from Royalty Properties decreased 49.1%
from $7.96/mcf during 2008 to $4.05/mcf during 2009. Both oil and
natural gas price changes resulted from changing market conditions.
The first
quarter weighted average oil sales price from the Net Profits Interests
properties decreased 64.3% from $80.10/bbl in 2008 to $28.63/bbl in
2009. The first quarter weighted average natural gas sales price from
the Net Profits Interests properties of $3.32/mcf in 2009 was 58.7% lower than
$8.04/mcf during the same period of 2008. Changing market conditions
resulted in decreased oil and natural gas sales prices.
Our first
quarter net operating revenues decreased 58.5% from $21,272,000 during 2008 to
$8,824,000 during 2009. The quarterly decrease primarily resulted from decreases
in oil and natural gas sales prices.
Costs and
expenses decreased 15.3% from $5,992,000 during the first quarter of 2008 to
$5,074,000 during the first quarter of 2009. The decrease resulted
from decreased production tax on lower operating revenues and reduced depletion
and amortization.
Depletion
and amortization decreased 12.9% during the first quarter of 2009 when compared
to the same period of 2008. The decrease from $3,790,000 in 2008 to
$3,300,000 in 2009 resulted from a lower depletable base due to effects of
previous depletion and upward revisions in oil and natural gas reserve estimates
at 2008 year end.
First
quarter net earnings allocable to common units decreased 75.6% from
$14,947,000 during 2008 to $3,654,000 during 2009. The 2009 decrease
from the first quarter 2008 net earnings is primarily the result of decreased
oil and natural gas sales prices.
Net cash
provided by operating activities decreased 31.8% from $17,203,000 during
the first quarter of 2008 to $11,735,000 during the first quarter of 2009
primarily due to decreased oil and natural gas sales prices partially offset by
a $2.1 million natural gas liquid payment attributable to 2008. The
natural gas liquids payment is based on an Oklahoma Guymon-Hugoton field 1994
gas delivery agreement that is in effect through 2015. Under the terms of
the agreement, when the market price of natural gas liquids increases
sufficiently disproportionately to natural gas market prices, the operating
partnership receives a portion of that increase in an annual payment. 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.
Only immaterial amounts were received prior to 2007.
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 first quarter
totaled approximately $8.1 million. These receipts generally reflect oil sales
during December 2008 through February 2009 and natural gas sales during November
2008 through January 2009. The weighted average indicated price for
oil and natural gas sales during the 2009 first quarter attributable to the
Royalty Properties was $38.49/bbl and $5.33/mcf, respectively.
Cash
receipts attributable to our Net Profits Interests during the 2009 first quarter
totaled approximately $5.1 million. These receipts reflect oil and natural gas
sales from the properties underlying the Net Profits Interests generally during
November 2008 through January 2009 and approximately $2.1 million attributable
to calendar year 2008 natural gas liquids. The weighted average indicated price
received during the 2009 first quarter for oil and natural gas sales was
$36.38/bbl and $6.89/mcf, respectively. The natural gas weighted
average indicated price for the quarter was increased by $2.41/mcf due to the
natural gas liquids payment.
10
We
received cash payments in the amount of $38,000 from various sources during the
first quarter of 2009 including lease bonuses attributable to four consummated
leases and pooling elections located in four counties and parishes in two
states. The consummated leases reflected royalty terms ranging up to 30% and
lease bonuses ranging up to $150/acre.
We
received division orders for, or otherwise identified, 141 new wells completed
on our Royalty Properties and Net Profits Interests located in 54 counties and
parishes in nine states during the first quarter of 2009. The operating
partnership elected to participate in 17 wells to be drilled on our Net Profits
Interests located in six counties in two states. Selected new wells and the
royalty interests owned by us and the working and net revenue interests owned by
the operating partnership are summarized in the following table.
This
table does not include wells drilled in the Fayetteville Shale trend as they are
detailed in a subsequent discussion and table.
|
County
|
DMLP
|
DMOLP
|
Test Rates per day
|
||||||||
|
State
|
/Parish
|
Operator
|
Well Name
|
NRI(2)
|
WI(1)
|
NRI(2)
|
Gas, mcf
|
Oil, bbls
|
|||
|
LA
|
De
Soto
|
Comstock
Oil &Gas
|
HA
RA SUA; Robert Crews #3Alt
|
2.734%
|
--
|
--
|
2,350
|
--
|
|||
|
LA
|
De
Soto
|
Comstock
Oil &Gas
|
Lena
Crews #5 Alt
|
2.734%
|
--
|
--
|
1,700
|
--
|
|||
|
OK
|
Roger
Mills
|
Burlington
Resources
|
Troy
Miller #17-11
|
1.670%
|
--
|
--
|
2,803
|
5
|
|||
|
TX
|
Hidalgo
|
Chesapeake
Operating
|
Barton
Gas Unit #1
|
3.125%
|
--
|
--
|
4,920
|
--
|
|||
|
TX
|
Wheeler
|
Devon
Energy
|
Effie
Hayes #18-5H
|
3.125%
|
--
|
--
|
4,377
|
--
|
|||
|
(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 forty wells have been permitted on the lands as of
March 31, 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 first 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
|
|||
|
Cleburne
|
SEECO
|
Kessinger
Trust 8-12 #3-2H35
|
0.307%
|
0.436%
|
0.327%
|
3,007
|
|||
|
Conway
|
David
Arrington
|
Beverly
Crofford #1-14H
|
1.563%
|
1.322%
|
0.996%
|
--
|
|||
|
Conway
|
David
Arrington
|
Beverly
Crofford #2-14H
|
1.563%
|
1.322%
|
0.996%
|
--
|
|||
|
Conway
|
SEECO
|
Bryant
9-15 #4-32H31
|
0.635%
|
1.701%
|
1.275%
|
5,499
|
|||
|
Conway
|
SEECO
|
Deltic
Timber 9-16 #4-36H31
|
1.384%
|
2.400%
|
1.800%
|
4,625
|
|||
|
Conway
|
SEECO
|
Jerome
Carr 9-15 #4-31H
|
2.188%
|
3.796%
|
2.847%
|
3,911
|
|||
|
Van
Buren
|
Chesapeake
|
Bradley
11-13 #2-9H
|
1.563%
|
1.250%
|
0.938%
|
320
|
|||
|
Van
Buren
|
Petrohawk
|
Sequoyah
9-12 #3-15H
|
1.953%
|
2.813%
|
2.109%
|
569
|
|||
|
Van
Buren
|
SEECO
|
Linn
10-12 #3-8H16
|
2.621%
|
3.230%
|
2.484%
|
3,930
|
|||
|
Van
Buren
|
SEECO
|
Linn
10-12 #4-8H16
|
2.621%
|
3.230%
|
2.484%
|
3,407
|
|||
|
(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.
|
11
Set forth
below is a summary of all permitting, drilling and completion activity through
March 31, 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.
|
2004
|
2005
|
2006
|
2007
|
Q1
2008
|
Q2
2008
|
Q3
2008
|
Q4
2008
|
Q1
2009
|
Total
|
||||||||||
|
New
Well Permits
|
1
|
2
|
11
|
35
|
15
|
21
|
15
|
21
|
19
|
140
|
|||||||||
|
Wells
Spud
|
0
|
1
|
9
|
33
|
12
|
17
|
22
|
13
|
9
|
116
|
|||||||||
|
Wells
Completed
|
0
|
1
|
5
|
23
|
10
|
17
|
12
|
17
|
12
|
97
|
|||||||||
|
Wells
in Pay Status (1)
|
0
|
0
|
0
|
6
|
5
|
8
|
10
|
7
|
12
|
48
|
|
(1)
|
Wells
in pay status means wells for which revenue was initially received during
the indicated period.
|
Net cash
receipts for the Royalty Properties attributable to interests in these lands
totaled $510,000 in the first quarter from 45 wells. Net cash
receipts for the Minerals NPI Properties attributable to interests in these
lands totaled $376,000 in the first quarter from 36 wells.
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.
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. Sixty-eight wells have been permitted on these lands as of
March 31, 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 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 is a summary of all permitting, drilling and completion activity through
March 31, 2009 for wells in which we have a royalty or Net Profits
Interest.
|
2004
|
2005
|
2006
|
2007
|
Q1
2008
|
Q2
2008
|
Q3
2008
|
Q4
2008
|
Q1
2009
|
Total
|
||||||||||
|
New
Well Permits
|
2
|
1
|
0
|
15
|
8
|
15
|
15
|
12
|
0
|
68
|
|||||||||
|
Wells
Spud
|
1
|
1
|
0
|
11
|
2
|
9
|
10
|
9
|
8
|
51
|
|||||||||
|
Wells
Completed
|
1
|
1
|
0
|
7
|
5
|
4
|
11
|
6
|
1
|
36
|
|||||||||
|
WI
Wells in Pay Status(1)
|
0
|
0
|
0
|
0
|
0
|
2
|
1
|
0
|
0
|
3
|
|
(1)
|
Wells
in pay status means wells for which revenue was initially received during
the indicated period.
|
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 3 of the Notes
to the Condensed Consolidated Financial Statements for the amounts and dates of
cash distributions to unitholders.
We are
not directly liable for the payment of any exploration, development or
production costs. We do not have any transactions, arrangements or other
relationships that could materially affect our liquidity or the availability of
capital resources. We have not guaranteed the debt of any other party, nor do we
have any other arrangements or relationships with other entities that could
potentially result in unconsolidated debt.
12
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
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.”
In 1998,
Oklahoma regulations removed production quantity restrictions in the
Guymon-Hugoton field and did not address efforts by third parties to persuade
Oklahoma to permit infill drilling in the Guymon-Hugoton field. Infill drilling
could require considerable capital expenditures. The outcome and the cost of
such activities are unpredictable and could influence the amount we receive from
the Net Profits Interests. The operating partnership believes it now
has sufficient field compression and permits for vacuum operation for the
foreseeable future.
Liquidity
and Working Capital
Cash and
cash equivalents totaled $12,039,000 at March 31, 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.
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.
13
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 effectively ensure that
the information required to be disclosed in the reports we file with the
Securities and Exchange Commission is recorded, processed, summarized and
reported within the time periods specified by the Securities and Exchange
Commission.
Changes
in Internal Controls
There
were no changes in our internal controls (as defined in Rule 13a-15(f) of the
Securities Exchange Act of 1934) during the quarter ended March 31, 2009 that
have materially affected, or are reasonably likely to materially affect, our
internal controls subsequent to the date of their evaluation of our disclosure
controls and procedures.
|
LEGAL
PROCEEDINGS
|
|||
|
See
Note 2 – Contingencies in Notes to the Condensed Consolidated Financial
Statements.
|
|||
|
RISK
FACTORS
|
|||
|
None.
|
|||
|
UNREGISTERED
SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
|
|||
|
None.
|
|||
|
DEFAULTS
UPON SENIOR SECURITIES
|
|||
|
None.
|
|||
|
SUBMISSION
OF MATTERS TO A VOTE OF SECURITY HOLDERS
|
|||
|
None.
|
|||
|
OTHER
INFORMATION
|
|||
|
None.
|
|||
|
EXHIBITS
|
|||
|
See
the attached Index to Exhibits.
|
|||
14
Pursuant
to the requirements of the Securities Exchange Act of 1934, the Registrant has
duly caused this report to be signed on its behalf by the undersigned thereunto
duly authorized.
|
DORCHESTER
MINERALS, L.P.
|
|||
|
By:
|
Dorchester
Minerals Management LP
|
||
|
its
General Partner
|
|||
|
By:
|
Dorchester
Minerals Management GP LLC
|
||
|
its
General Partner
|
|||
|
By:
|
/s/
William Casey McManemin
|
||
|
William
Casey McManemin
|
|||
|
Date:
May 7, 2009
|
Chief
Executive Officer
|
||
|
By:
|
/s/
H.C. Allen, Jr.
|
||
|
H.C.
Allen, Jr.
|
|||
|
Date:
May 7, 2009
|
Chief
Financial Officer
|
||
15
|
Number
|
Description
|
|
|
3.1
|
|
Certificate
of Limited Partnership of Dorchester Minerals, L.P. (incorporated by
reference to Exhibit 3.1 to Dorchester Minerals’ Registration Statement on
Form S-4, Registration Number 333-88282)
|
|
3.2
|
|
Amended
and Restated Agreement of Limited Partnership of Dorchester Minerals, L.P.
(incorporated by reference to Exhibit 3.2 to Dorchester Minerals’ Report
on Form 10-K filed for the year ended December 31,
2002)
|
|
3.3
|
|
Certificate
of Limited Partnership of Dorchester Minerals Management LP (incorporated
by reference to Exhibit 3.4 to Dorchester Minerals’ Registration Statement
on Form S-4, Registration Number 333-88282)
|
|
3.4
|
|
Amended
and Restated Agreement of Limited Partnership of Dorchester Minerals
Management LP (incorporated by reference to Exhibit 3.4 to Dorchester
Minerals’ Report on Form 10-K for the year ended December 31,
2002)
|
|
3.5
|
|
Certificate
of Formation of Dorchester Minerals Management GP LLC (incorporated by
reference to Exhibit 3.7 to Dorchester Minerals’ Registration Statement on
Form S-4, Registration Number 333-88282)
|
|
3.6
|
|
Amended
and Restated Limited Liability Company Agreement of Dorchester Minerals
Management GP LLC (incorporated by reference to Exhibit 3.6 to Dorchester
Minerals’ Report on Form 10-K for the year ended December 31,
2002)
|
|
3.7
|
|
Certificate
of Formation of Dorchester Minerals Operating GP LLC (incorporated by
reference to Exhibit 3.10 to Dorchester Minerals’ Registration Statement
on Form S-4, Registration Number 333-88282)
|
|
3.8
|
|
Limited
Liability Company Agreement of Dorchester Minerals Operating GP LLC
(incorporated by reference to Exhibit 3.11 to Dorchester Minerals’
Registration Statement on Form S-4, Registration Number
333-88282)
|
|
3.9
|
|
Certificate
of Limited Partnership of Dorchester Minerals Operating LP (incorporated
by reference to Exhibit 3.12 to Dorchester Minerals’ Registration
Statement on Form S-4, Registration Number 333-88282)
|
|
3.10
|
|
Amended
and Restated Agreement of Limited Partnership of Dorchester Minerals
Operating LP. (incorporated by reference to Exhibit 3.10 to Dorchester
Minerals’ Report on Form 10-K for the year ended December 31,
2002)
|
|
3.11
|
|
Certificate
of Limited Partnership of Dorchester Minerals Oklahoma LP (incorporated by
reference to Exhibit 3.11 to Dorchester Minerals’ Report on Form 10-K for
the year ended December 31, 2002)
|
|
3.12
|
|
Agreement
of Limited Partnership of Dorchester Minerals Oklahoma LP (incorporated by
reference to Exhibit 3.12 to Dorchester Minerals’ Report on Form 10-K for
the year ended December 31, 2002)
|
|
3.13
|
|
Certificate
of Incorporation of Dorchester Minerals Oklahoma GP, Inc. (incorporated by
reference to Exhibit 3.13 to Dorchester Minerals’ Report on Form 10-K for
the year ended December 31, 2002)
|
|
3.14
|
|
Bylaws
of Dorchester Minerals Oklahoma GP, Inc. (incorporated by reference to
Exhibit 3.14 to Dorchester Minerals’ Report on Form 10-K for the year
ended December 31, 2002)
|
|
3.15
|
Certificate
of Limited Partnership of Dorchester Minerals Acquisition LP (incorporated
by reference to Exhibit 3.15 to Dorchester Minerals’ Report on Form 10-K
for the year ended December 31, 2004)
|
|
|
3.16
|
Agreement
of Limited Partnership of Dorchester Minerals Acquisition LP (incorporated
by reference to Exhibit 3.16 to Dorchester Minerals’ Report on Form 10-Q
for the quarter ended September 30, 2004)
|
|
|
3.17
|
Certificate
of Incorporation of Dorchester Minerals Acquisition GP, Inc. (incorporated
by reference to Exhibit 3.17 to Dorchester Minerals’ Report on Form 10-Q
for the quarter ended September 30, 2004)
|
|
|
3.18
|
Bylaws
of Dorchester Minerals Acquisition GP, Inc. (incorporated by reference to
Exhibit 3.18 to Dorchester Minerals’ Report on Form 10-Q for the quarter
ended September 30, 2004)
|
|
|
31.1
|
Certification
of Chief Executive Officer of the Partnership pursuant to Rule 13a-14(a)
of the Securities Exchange Act of 1934
|
|
|
31.2
|
Certification
of Chief Financial Officer of the Partnership pursuant to Rule 13a-14(a)
of the Securities Exchange Act of 1934
|
|
|
32.1
|
Certification
of Chief Executive Officer of the Partnership pursuant to 18 U.S.C. Sec.
1350
|
|
|
32.2
|
Certification
of Chief Financial Officer of the Partnership pursuant to 18 U.S.C. Sec.
1350 (contained within Exhibit 32.1
hereto)
|
16