DORCHESTER MINERALS, L.P. - Quarter Report: 2009 June (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 June 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
August 6, 2009, 29,840,431 common units of partnership interest were
outstanding.
TABLE OF
CONTENTS
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2
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.
3
DORCHESTER
MINERALS, L.P.
(A
Delaware Limited Partnership)
(In
Thousands)
|
June
30,
|
December
31,
|
|||||||
|
2009
|
2008
|
|||||||
|
ASSETS
|
(unaudited)
|
|||||||
|
Current
assets:
|
||||||||
|
Cash and cash
equivalents
|
$ | 9,217 | $ | 16,211 | ||||
|
Trade and
other receivables
|
4,573 | 5,053 | ||||||
|
Net profits
interests receivable - related party
|
1,183 | 4,428 | ||||||
|
Prepaid
expenses
|
25 | - | ||||||
|
Total current
assets
|
14,998 | 25,692 | ||||||
|
Other
non-current assets
|
19 | 19 | ||||||
|
Total
|
19 | 19 | ||||||
|
Property and
leasehold improvements - at cost:
|
||||||||
|
Oil and
natural gas properties (full cost method)
|
327,063 | 291,818 | ||||||
|
Accumulated
full cost depletion
|
(185,021 | ) | (178,272 | ) | ||||
|
Total
|
142,042 | 113,546 | ||||||
|
Leasehold
improvements
|
512 | 512 | ||||||
|
Accumulated
amortization
|
(231 | ) | (207 | ) | ||||
|
Total
|
281 | 305 | ||||||
|
Net property
and leasehold improvements
|
142,323 | 113,851 | ||||||
|
Total
assets
|
$ | 157,340 | $ | 139,562 | ||||
|
LIABILITIES
AND PARTNERSHIP CAPITAL
|
||||||||
|
Current
liabilities:
|
||||||||
|
Accounts
payable and other current liabilities
|
$ | 1,010 | $ | 733 | ||||
|
Current
portion of deferred rent incentive
|
39 | 39 | ||||||
|
Total current
liabilities
|
1,049 | 772 | ||||||
|
Deferred rent
incentive less current portion
|
188 | 208 | ||||||
|
Total
liabilities
|
1,237 | 980 | ||||||
|
Commitments
and contingencies
|
||||||||
|
Partnership
capital:
|
||||||||
|
General
partner
|
5,422 | 5,971 | ||||||
|
Unitholders
|
150,681 | 132,611 | ||||||
|
Total
partnership capital
|
156,103 | 138,582 | ||||||
|
Total
liabilities and partnership capital
|
$ | 157,340 | $ | 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
|
Six
Months Ended
|
|||||||||||||||
|
June
30,
|
June
30,
|
|||||||||||||||
|
2009
|
2008
|
2009
|
2008
|
|||||||||||||
|
Operating
revenues:
|
||||||||||||||||
|
Royalties
|
$ | 8,006 | $ | 18,604 | $ | 15,031 | $ | 33,375 | ||||||||
|
Net profits
interests
|
1,593 | 10,204 | 3,375 | 16,569 | ||||||||||||
|
Lease
bonus
|
80 | 140 | 89 | 257 | ||||||||||||
|
Other
|
5 | 40 | 13 | 59 | ||||||||||||
|
Total
operating revenues
|
9,684 | 28,988 | 18,508 | 50,260 | ||||||||||||
|
Costs and
expenses:
|
||||||||||||||||
|
Operating,
including production taxes
|
844 | 1,345 | 1,583 | 2,536 | ||||||||||||
|
Depletion and
amortization
|
3,473 | 3,648 | 6,773 | 7,438 | ||||||||||||
|
General and
administrative expenses
|
817 | 860 | 1,852 | 1,871 | ||||||||||||
|
Total costs
and expenses
|
5,134 | 5,853 | 10,208 | 11,845 | ||||||||||||
|
Operating
income
|
4,550 | 23,135 | 8,300 | 38,415 | ||||||||||||
|
Other income,
net
|
170 | 31 | 197 | 161 | ||||||||||||
|
Net
earnings
|
$ | 4,720 | $ | 23,166 | $ | 8,497 | $ | 38,576 | ||||||||
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Allocation of
net earnings:
|
||||||||||||||||
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General
partner
|
$ | 161 | $ | 662 | $ | 284 | $ | 1,125 | ||||||||
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Unitholders
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$ | 4,559 | $ | 22,504 | $ | 8,213 | $ | 37,451 | ||||||||
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Net earnings
per common unit (basic and diluted)
|
$ | 0.16 | $ | 0.80 | $ | 0.29 | $ | 1.33 | ||||||||
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Weighted
average common units outstanding
|
28,258 | 28,240 | 28,249 | 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)
|
Six Months
Ended
|
||||||||
|
June
30,
|
||||||||
|
2009
|
2008
|
|||||||
|
Net cash
provided by operating activities
|
$ | 19,511 | $ | 39,886 | ||||
|
Cash flows
provided by (used in) investing activities:
|
||||||||
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Adjustment
related to acquisition of natural gas properties
|
967 | - | ||||||
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Capital
expenditures
|
- | (50 | ) | |||||
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Total cash
flows provided by (used in) investing activities
|
967 | (50 | ) | |||||
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Cash flows
used in financing activities:
|
||||||||
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Distributions
paid to general partner and unitholders
|
(27,472 | ) | (31,662 | ) | ||||
|
(Decrease)
increase in cash and cash equivalents
|
(6,994 | ) | 8,174 | |||||
|
Cash and cash
equivalents at beginning of period
|
16,211 | 15,001 | ||||||
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Cash and cash
equivalents at end of period
|
$ | 9,217 | $ | 23,175 | ||||
|
Non-cash
investing and financing activities:
|
||||||||
|
Value
of units issued for natural gas properties acquired
|
$ | 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.
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
|
||||||
|
First
quarter
|
$0.401205
|
$0.572300
|
$0.461146
|
$0.729852
|
$0.481242
|
|||||
|
Second
quarter
|
$0.271354
|
$0.769206
|
$0.473745
|
$0.778120
|
$0.514542
|
|||||
|
Third
quarter
|
$0.948472
|
$0.560502
|
$0.516082
|
$0.577287
|
||||||
|
Fourth
quarter
|
$0.542081
|
$0.514625
|
$0.478596
|
$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. 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 November 15, 2009.
5. New
Accounting Pronouncements: In September 2006, the Financial
Accounting Standards Board (“FASB”) issued Statement of Financial Accounting
Standards (“SFAS”) No. 157, Fair
Value Measurements. 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 SFAS 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 material impact on our consolidated
financial statements.
In
April 2009, the FASB issued FSP No. 107-1 and Accounting Principles Board (APB)
28-1, Interim
Disclosures about Fair Value of Financial Instruments (“FSP 107-1”). FSP
107-1 requires disclosures about fair value of financial instruments for interim
reporting periods and amends APB Opinion No. 28 Interim
Financial Reporting to require those disclosures in summarized financial
information at interim reporting periods. The FSP is effective for the period
ended June 30, 2009 and did not have a material impact on the consolidated
financial statements.
On
June 29, 2009, the FASB issued SFAS 168, The
FASB Accounting Standards Codification and the Hierarchy of Generally Accepted
Accounting Principles. SFAS No. 168 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. SFAS 168 replaces SFAS 162,
The
Hierarchy of Generally Accepted Accounting Principles, which was issued
in May 2008. The Codification will be effective for all reporting periods that
end after September 15, 2009. We expect no material impact on our
consolidated financial statements from SFAS 168.
In
May 2009, the FASB issued SFAS 165, Subsequent
Events, to incorporate the accounting and disclosure requirements for
subsequent events into U.S. generally accepted accounting principles. SFAS 165
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 SFAS 165 as of June 30, 2009, which was the
required effective date.
6. Subsequent
Events: We evaluated subsequent events through August 6,
2009 which represents the date the financial statements were issued. We are not
aware of any subsequent events which would require recognition or disclosure in
the financial statements.
8
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 June 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
|
Six
Months
Ended
6/30/09
|
Cumulative
Total
at
6/30/09
|
||||||||||
|
Cash received
for revenue
|
$ | 14,216 | $ | 1,538 | $ | 15,754 | ||||||
|
Cash paid for
operating costs
|
2,226 | 384 | 2,610 | |||||||||
|
Cash paid for
development costs
|
11,724 | 2,076 | 13,800 | |||||||||
|
Budgeted
capital expenditures
|
905 | 948 | 1,853 | |||||||||
|
Net
|
$ | (639 | ) | $ | (1,870 | ) | $ | (2,509 | ) | |||
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 Six Months Ended June 30, 2009 as compared to Three and Six Months Ended
June 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
|
Six Months
Ended
|
|||||||||||||||||||
|
June
30,
|
March
31,
|
June
30,
|
||||||||||||||||||
|
Accrual basis
sales volumes:
|
2009
|
2008
|
2009
|
2009
|
2008
|
|||||||||||||||
|
Royalty
properties gas sales (mmcf)
|
1,019 | 872 | 1,037 | 2,056 | 1,864 | |||||||||||||||
|
Royalty
properties oil sales (mbbls)
|
80 | 80 | 74 | 154 | 152 | |||||||||||||||
|
Net profits
interests gas sales (mmcf)
|
903 | 974 | 887 | 1,790 | 1,961 | |||||||||||||||
|
Net profits
interests oil sales (mbbls)
|
3 | 3 | 3 | 6 | 7 | |||||||||||||||
|
Accrual basis
weighted average sales price:
|
||||||||||||||||||||
|
Royalty
properties gas sales ($/mcf)
|
$ | 3.47 | $ | 10.73 | $ | 4.05 | $ | 3.76 | $ | 9.26 | ||||||||||
|
Royalty
properties oil sales ($/bbl)
|
$ | 55.90 | $ | 116.43 | $ | 38.45 | $ | 47.54 | $ | 106.14 | ||||||||||
|
Net profits
interests gas sales ($/mcf)
|
$ | 2.95 | $ | 11.90 | $ | 3.32 | $ | 3.13 | $ | 9.96 | ||||||||||
|
Net profits
interests oil sales ($/bbl)
|
$ | 55.70 | $ | 116.81 | $ | 28.63 | $ | 42.07 | $ | 98.18 | ||||||||||
|
Accrual basis
production costs deducted
|
||||||||||||||||||||
|
under the net profits
interests ($/mcfe)
(1)
|
$ | 1.41 | $ | 1.94 | $ | 1.45 | $ | 1.43 | $ | 1.96 | ||||||||||
|
|
(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 second quarter were unchanged at 80 mbbls in 2009
and in 2008. Oil sales volumes attributable to our Royalty Properties during the
first six months were also virtually unchanged at 154 mbbls in 2009 compared to
152 mbbls in 2008. Natural gas sales volumes attributable to our Royalty
Properties during the second quarter increased 16.9% from 872 mmcf in 2008 to
1,019 mmcf in 2009. Natural gas sales volumes attributable to our Royalty
Properties during the first six months increased 10.3% from 1,864 in 2008 to
2,056 mmcf in 2009. The increase in natural gas sales volumes was primarily
attributable to results from new drilling activity in the second half of
2008.
Oil sales volumes
attributable to our Net Profits Interests during the second quarter and first
six 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 second quarter and first six months of 2009 decreased from
the same periods of 2008. Second quarter sales volumes of 903 mmcf
during 2009 were 7.3% less than 974 mmcf during 2008. First six month
sales volumes of 1,790 mmcf during 2009 were 8.7% less than 1,961 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 52.0% from $116.43/bbl during the second quarter of 2008 to $55.90/bbl
during the second quarter of 2009 and decreased 55.2% from $106.14/bbl during
the first six months of 2008 to $47.54/bbl during the same period of
2009. Second quarter weighted average natural gas sales prices from
Royalty Properties decreased 67.7% from $10.73/mcf during 2008 to $3.47/mcf
during 2009. The six months ended June 30 weighted average Royalty
Properties natural gas sales prices decreased 59.4% from $9.26/mcf during 2008
to $3.76/mcf during 2009. Both oil and natural gas price changes
resulted from changing market conditions.
Second quarter
weighted average oil sales prices from the Net Profits Interests’ properties
decreased 52.3% from $116.81/bbl in 2008 to $55.70/bbl in 2009. The
first six months Net Profits Interests’ oil sales prices decreased 57.2% from
$98.18/bbl in 2008 to $42.07/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 second
quarter of 2009 and first six months of 2009 compared to the same periods of
2008. Second quarter natural gas sales prices of $2.95/mcf in 2009
were 75.2% less than $11.90/mcf in 2008. The six months ended June
30, 2009 natural gas prices decreased 68.6% to $3.13/mcf from $9.96/mcf in the
same period of 2008. Natural gas sales price decreases during the
three- and six- month periods resulted from changing market conditions along
with 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 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.
10
Our
second quarter net operating revenues decreased 66.6% from $28,988,000
during 2008 to $9,684,000 during 2009. Net operating revenues for the
first six months of 2009 decreased 63.2% from $50,260,000 during 2008 to
$18,508,000 during 2009. Both the quarterly and six-month decrease resulted from
decreased gas and oil sales prices including a 2007 natural gas liquid payment
received during the second quarter 2008.
Costs and expenses
decreased 12.3% from $5,853,000 during the second quarter of 2008 to $5,134,000
during the second quarter of 2009, while six months ended June 30 costs and
expenses decreased 13.8% from $11,845,000 during 2008 to $10,208,000 during
2009. Such decreases primarily resulted from decreased production tax
on lower operating revenues and reduced depletion and amortization.
Depletion and
amortization decreased 4.8% during the second quarter ended June 30, 2009 and
8.9% during the six months ended June 30, 2009 when compared to the same periods
of 2008. The decreases from $3,648,000 and $7,438,000 during the
second quarter and six months ended June 30, 2008, respectively, to
$3,473,000 and $6,773,000 during the same periods of 2009 respectively, 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.
Second quarter net
earnings allocable to common units decreased 79.7% from $22,504,000 during
2008 to $4,559,000 during 2009. First six months common unit net
earnings decreased 78.1% from $37,451,000 during 2008 to $8,213,000 during
2009. Both decreases are primarily the result of decreased oil and
natural gas sales prices.
Net cash provided
by operating activities decreased 65.7% from $22,683,000 during the second
quarter of 2008 to $7,776,000 during the second quarter of 2009 and decreased
51.1% from $39,886,000 for the first six months during 2008 to $19,511,000
during the same period of 2009. Decreases in both periods are
primarily due to decreased oil and natural gas sales prices. Abnormal
natural gas liquid payments were also received in first quarter 2009 and second
quarter 2008. See discussion above on net operating revenues for more
details.
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 second quarter totaled
$7,009,000. These receipts generally reflect oil sales during March through May
2009 and natural gas sales during February through April 2009. The
weighted average indicated prices for oil and natural gas sales during the 2009
second quarter attributable to the Royalty Properties were $46.58/bbl and
$3.75/mcf, respectively.
Cash receipts
attributable to our Net Profits Interests during the 2009 second quarter totaled
$1,532,000. These receipts reflect oil and natural gas sales from the properties
underlying the Net Profits Interests generally during February through April
2009. The weighted average indicated prices received during the 2009
second quarter for oil and natural gas sales were $37.91/bbl and $2.94/mcf,
respectively.
We
received cash payments in the amount of $249,000 from various sources during the
second quarter of 2009 including lease bonuses attributable to ten 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 $200/acre.
Our second quarter
cash distribution included $1,067,000 of second quarter cash receipts from the
acquired Barnett Shale properties. This cash payment contained
non-recurring items and, therefore, may not be reflective of future cash
generated by the acquired properties. See Note 3 to the consolidated
financial statements and Barnett Shale discussion below.
11
We
received
division orders for, or otherwise identified, 106 new wells completed on our
Royalty Properties and Net Profits Interests located in 46 counties and parishes
in 11 states during the second quarter of 2009. The operating partnership
elected to participate in 20 wells to be drilled on our Net Profits Interests located
in seven 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 tables below.
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
|
|||
|
OK
|
Ellis
|
Crusader
Energy
|
Raiders
5-27H
|
--
|
3.750%
|
9.063%
|
1,142
|
176
|
|||
|
TX
|
Starr
|
El Paso
E&P Co.
|
Guerra USA GU
“D” #17
|
8.194%
|
--
|
--
|
6,800
|
--
|
|||
|
TX
|
Starr
|
El Paso
E&P Co.
|
Guerra USA GU
“D” #18
|
8.194%
|
--
|
--
|
366
|
5
|
|||
|
TX
|
Starr
|
Ram Operating
Co.
|
Garza
Hitchcock #18
|
2.653%
|
--
|
--
|
2,491
|
--
|
|||
|
TX
|
Wheeler
|
Kaiser-Francis
|
Burrell A W
104
|
0.710%
|
--
|
--
|
8,964
|
--
|
|||
|
(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 fifty-seven wells have been permitted on the lands
as of June 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 second
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
|
Mulliniks
9-12 #6-35H2
|
1.401%
|
1.992%
|
1.494%
|
4,323
|
|||
|
Conway
|
Chesapeake
|
Collinsworth
7-16 #1-10H3
|
2.312%
|
4.553%
|
3.414%
|
--
|
|||
|
Conway
|
SEECO
|
Charles
Reeves 9-15 #3-10H3
|
2.849%
|
4.559%
|
3.419%
|
3,976
|
|||
|
Conway
|
SEECO
|
Charles
Reeves 9-15 #4-10H3
|
2.974%
|
4.758%
|
3.569%
|
1,895
|
|||
|
Conway
|
SEECO
|
Charles
Reeves 9-15 #5-10H3
|
2.974%
|
4.375%
|
3.569%
|
3,884
|
|||
|
Conway
|
SEECO
|
Polk 9-15
#4-30H
|
5.930%
|
5.561%
|
4.220%
|
--
|
|||
|
Faulkner
|
Chesapeake
|
Hooten 8-12
#1-17H
|
0.752%
|
0.000%
|
0.000%
|
--
|
|||
|
Van
Buren
|
Petrohawk
|
Green Bay
11-14 #1-20H
|
0.703%
|
0.000%
|
0.000%
|
--
|
|||
|
Van
Buren
|
Petrohawk
|
Thacker 9-12
#2-21H
|
2.343%
|
4.375%
|
3.281%
|
1,538
|
|||
|
Van
Buren
|
SEECO
|
Howard Family
Trust 10-12 #2-9H16
|
2.594%
|
4.576%
|
3.432%
|
--
|
|||
|
Van
Buren
|
SEECO
|
Collums-Pennington
10-12 #1-20H
|
2.344%
|
4.375%
|
3.281%
|
2,081
|
|||
|
Van
Buren
|
SEECO
|
Collums-Pennington
10-12 #2-20H
|
2.344%
|
4.375%
|
3.281%
|
2,229
|
|||
|
White
|
Chesapeake
|
Gillam 9-6
#1-23H
|
3.125%
|
5.000%
|
3.750%
|
820
|
|||
|
White
|
Chesapeake
|
Webb 9-6
#1-35H
|
2.344%
|
4.380%
|
3.285%
|
2,389
|
|||
|
(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
June 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
|
|||||||||
|
New Well
Permits
|
157
|
11
|
35
|
16
|
21
|
12
|
21
|
19
|
19
|
||||||||
|
Wells
Spud
|
132
|
9
|
33
|
12
|
17
|
19
|
13
|
21
|
7
|
||||||||
|
Wells
Completed
|
111
|
5
|
23
|
10
|
17
|
12
|
17
|
12
|
14
|
||||||||
|
Wells in Pay Status (1)
|
71
|
0
|
14
|
4
|
7
|
14
|
7
|
14
|
10
|
|
(1)
|
Wells in pay
status means wells for which revenue was initially received during the
indicated period.
|
|
(2)
|
Includes
activity begun in year 2004.
|
Net cash
receipts for the Royalty Properties attributable to interests in these lands
totaled $306,000 in the second quarter from 57 wells. Net cash receipts
for the Minerals NPI Properties attributable to interests in these lands totaled
$337,000 in the second quarter from 37 wells.
BARNETT SHALE — On
May 15, 2009, we executed a definitive agreement to acquire 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 May 15, 2009, 32 wells were
drilled from 11 padsites located on or adjacent to the properties, of which 26
wells were completed for production and six were drilled but not yet completed
or connected to a pipeline. Permits to drill four additional wells on
the properties had been issued by regulatory agencies.
The transaction was
consummated on June 30, 2009 and was structured as a non-taxable contribution
and exchange. At the closing, in addition to conveying their interests to us,
the contributing parties delivered funds in an amount equal to their cash
receipts less cash disbursements during period April 1, 2009 through June 30,
2009 and we conveyed an aggregate of 1,600,000 common limited partnership units
to the contributing parties. The funds delivered at closing totaled
$1,067,000; approximately $520,000 of these funds were attributable to the
production during January, February and March 2009. The balance of the funds was
attributable to prior production periods and primarily due to one-time release
of production revenues previously suspended by the purchaser.
Estimated proved
developed reserves of 5,584.6 mmcf were assigned to the acquired properties as
of June 30, 2009 based on the report of independent petroleum engineering
consultant firm Huddleston & Co., Inc. These reserves include proved
developed nonproducing reserves assigned to six wells. No proved undeveloped
reserves were assigned to four permitted but undrilled locations or otherwise to
the properties.
As
of July 31, 2009, one of these six wells had been completed and was producing to
sales. In addition, one of the permitted locations had been drilled and was
waiting on completion and one other was drilling.
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. Seventy-two wells have been permitted on these lands as of
June 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 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.
13
Set forth below are
totals and a summary of permitting, drilling and completion activity through
June 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
|
|||||||||
|
New Well
Permits
|
72
|
0
|
15
|
8
|
16
|
15
|
12
|
0
|
3
|
||||||||
|
Wells
Spud
|
58
|
0
|
12
|
2
|
10
|
10
|
9
|
11
|
2
|
||||||||
|
Wells
Completed
|
44
|
0
|
7
|
5
|
5
|
10
|
6
|
8
|
1
|
||||||||
|
WI Wells in Pay Status(1)
|
3
|
0
|
0
|
0
|
2
|
1
|
0
|
0
|
0
|
|
(1)
|
Wells in pay
status means wells for which revenue was initially received during the
indicated period.
|
|
(2)
|
Includes
Activity begun in year 2004.
|
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
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 $9,217,000 at June 30, 2009 and $16,211,000 at
December 31, 2008.
14
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.
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.
15
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 June 30, 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.
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, other than the
following:
Certain
U.S. federal income tax deductions currently available with respect to oil and
gas exploration and development may be eliminated as a result of future
legislation.
The Proposed Fiscal
Year 2010 Federal Budget includes legislation that would, if enacted into law,
make significant changes to United States tax laws, including the elimination of
certain key U.S. federal income tax incentives currently available to oil and
natural gas exploration activities. These changes include, but are not limited
to, (i) the repeal of the percentage depletion allowance for oil and natural gas
properties, (ii) the elimination of current deductions for intangible drilling
and development costs, and (iii) an extension of the amortization period for
certain geological and geophysical expenditures. It is unclear
whether any such changes will be enacted or how soon any such changes could
become effective. The passage of any legislation as a result of these
proposals or any other similar changes in U.S. federal income tax laws
could eliminate certain tax deductions that are currently available to our
common unitholders and to oil and gas operators that we rely upon to develop our
properties. Such legislation or changes could negatively impact both
our unitholders and our Partnership financially.
The
adoption of climate change legislation by Congress could result in increased
operating costs and reduced demand for the oil and natural gas production from
our properties.
On
June 26, 2009, the U.S. House of Representatives approved adoption of the
“American Clean Energy and Security Act of 2009,” also known as the
“cap-and-trade legislation” or ACESA. One of the purposes of ACESA is
to control and reduce emissions of “greenhouse gases,” or “GHGs,” in the United
States. GHGs are certain gases, including carbon dioxide and methane,
which may be contributing to warming of the Earth’s atmosphere and other
climatic changes. ACESA would establish an economy-wide cap on
emissions of GHGs in the United States and would require a gradual overall
reduction in GHG emissions. The net effect of ACESA will be to impose
increasing costs on the combustion of carbon-based fuels such as oil, refined
petroleum products, and natural gas. The U.S. Senate has begun work
on its own legislation for controlling and reducing emissions of GHGs in the
United States. Although it is not possible at this time to predict
whether or when the Senate may act on climate change legislation or how any bill
approved by the Senate would be reconciled with ACESA, any laws or regulations
that may be adopted to restrict or reduce emissions of GHGs could require the
operating partnership and oil and gas operators that develop our properties to
incur increased operating costs, and could have an adverse effect on demand for
the oil and natural gas produced from our properties.
16
None.
None.
We
held our Annual Unitholders meeting on Wednesday, May 13, 2009 in Dallas,
Texas. Proxies were solicited by the Board of Managers pursuant to
Regulation 14A under the Securities Exchange Act of 1934. There were no
solicitations in opposition to the nominees listed in the proxy statement, and
all of such nominees were duly elected. The only matter voted on at
the meeting was the election of the three nominees to the Board of Managers. Out
of the 28,240,431 units then issued and outstanding and entitled to vote at the
meeting, 26,463,922 units were present in person or by proxy. The results were
as follows:
|
Nominee
|
Votes for
Election
|
Votes
Withheld from Election
|
Broker
Non-Votes
|
|
Buford P.
Berry
|
26,122,933
|
340,989
|
1,776,509
|
|
C. W. “Bill”
Russell
|
26,182,863
|
281,059
|
1,776,509
|
|
Ronald P.
Trout
|
26,186,512
|
277,410
|
1,776,509
|
ITEM
5. OTHER INFORMATION
None.
See the attached
Index to Exhibits.
SIGNATURES
Pursuant to the
requirements of the Securities Exchange Act of 1934, the Registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly
authorized.
|
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:
August 6, 2009
|
Chief
Executive Officer
|
||
|
By:
|
/s/ H.C.
Allen, Jr.
|
||
|
H.C. Allen,
Jr.
|
|||
|
Date:
August 6, 2009
|
Chief
Financial Officer
|
||
18
|
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)
|
19
|
Number
|
Description
|
|
|
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)
|
|
|
10.1
|
Contribution
and Exchange Agreement by and among Dorchester Minerals, L.P., Tiggator,
Inc., TRB Minerals, LP and West Fork Partners, L.P. dated May 15, 2009
(incorporated by reference to Exhibit 10.1 to Dorchester Minerals' Current
Report on Form 8-K filed on July 6, 2009).
|
|
|
10.2*
|
Amendment
No. 1 dated June 26, 2009 to the Contribution and Exchange Agreement by
and among Dorchester Minerals, L.P., Tiggator, Inc., TRB Minerals, LP and
West Fork Partners, L.P. dated May 15, 2009
|
|
|
10.3
|
Lock-up
Agreement by and between Dorchester Minerals, L.P. and Tiggator, Inc.
dated June 30, 2009 (incorporated by reference to Exhibit 10.2 to
Dorchester Minerals' Current Report on Form 8-K filed on July 6,
2009).
|
|
|
10.4
|
Lock-up
Agreement by and between Dorchester Minerals, L.P. and TRB Minerals, LP
dated June 30, 2009 (incorporated by reference to Exhibit 10.3 to
Dorchester Minerals' Current Report on Form 8-K filed on July 6,
2009).
|
|
|
10.5
|
Lock-up
Agreement by and between Dorchester Minerals, L.P. and West Fork Partners,
L.P. dated June 30, 2009 (incorporated by reference to Exhibit 10.4 to
Dorchester Minerals' Current Report on Form 8-K filed on July 6,
2009).
|
|
|
23.1*
|
Consent
of Huddleston & Co., Inc.
|
|
|
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)
|
* Filed
herewith
20