UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC. 20549
FORM 10-Q
[X] QUARTERLY REPORT UNDER 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, 2007 Commission file number 000-50175
DORCHESTER MINERALS, L.P.
(Exact name of Registrant as specified in its charter)
Delaware 81-0551518
(State or other jurisdiction of (I.R.S. Employer Identification No.)
Incorporation or organization)
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
Indicate by check mark whether the registrant is a large accelerated
filer, an accelerated filer or a non-accelerated filer. See definition of
"accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange
Act. (Check one):
Large accelerated filer Accelerated filer X Non-accelerated filer
Indicate by check mark whether the registrant is a shell company
(as defined in Rule 12b-2 of the Act.): Yes No X
As of May 3, 2007, 28,240,431 common units of partnership interest
were outstanding.
TABLE OF CONTENTS
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS................................3
PART I.........................................................................3
ITEM 1. FINANCIAL INFORMATION..........................................3
CONDENSED BALANCE SHEETS AS OF MARCH 31, 2007 (UNAUDITED) AND
DECEMBER 31, 2006....................................................4
CONDENSED STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED
MARCH 31, 2007 AND 2006 (UNAUDITED)..................................5
CONDENSED STATEMENTS OF CASH FLOWS FOR THE THREE MONTHS ENDED
MARCH 31, 2007 AND 2006 (UNAUDITED)..................................6
NOTES TO THE CONDENSED FINANCIAL STATEMENTS..............................7
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS......................................................8
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK....13
ITEM 4. CONTROLS AND PROCEDURES.......................................13
PART II.......................................................................14
ITEM 1. LEGAL PROCEEDINGS.............................................14
ITEM 1A. RISK FACTORS..................................................14
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS...14
ITEM 3. DEFAULTS UPON SENIOR SECURITIES...............................14
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS...........14
ITEM 5. OTHER INFORMATION.............................................14
ITEM 6. EXHIBITS......................................................14
SIGNATURES....................................................................15
INDEX TO EXHIBITS.............................................................16
CERTIFICATIONS................................................................17
2
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
Statements included in this report which 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 "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 herein 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.
PART I
ITEM 1. FINANCIAL INFORMATION
See attached financial statements on the following pages.
3
DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
CONDENSED BALANCE SHEETS
(In Thousands)
March 31, December 31,
2007 2006
----------- -----------
ASSETS (unaudited)
Current assets:
Cash and cash equivalents $ 13,828 $ 13,927
Trade receivables 5,894 6,088
Net profits interests receivable - related party 3,871 4,126
Current portion of note receivable - related party 42 50
Prepaid expenses 37 -
-------- --------
Total current assets 23,672 24,191
Note receivable - related party less current portion - 5
Other non-current assets 19 19
-------- --------
Total 19 24
Property and leasehold improvements - at cost:
Oil and natural gas properties (full cost method): 291,875 291,875
Less accumulated full cost depletion 151,873 148,064
-------- --------
Total 140,002 143,811
Leasehold improvements 512 512
Less accumulated amortization 121 109
-------- --------
Total 391 403
-------- --------
Net property and leasehold improvements 140,393 144,214
-------- --------
Total assets $164,084 $168,429
======== ========
LIABILITIES AND PARTNERSHIP CAPITAL
Current liabilities:
Accounts payable and other current liabilities $ 722 $ 303
Distributions payable to partners 44 -
Current portion of deferred rent incentive 39 39
-------- ---------
Total current liabilities 805 342
-------- --------
Deferred rent incentive less current portion 277 287
-------- --------
Total liabilities 1,082 629
-------- --------
Commitments and contingencies
Partnership capital:
General partner 6,652 6,797
Unitholders 156,350 161,003
-------- --------
Total partnership capital 163,002 167,800
-------- --------
Total liabilities and partnership capital $164,084 $168,429
======== ========
The accompanying condensed notes are an integral part of
these financial statements.
4
DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
CONDENSED STATEMENTS OF OPERATIONS
(Dollars In Thousands, Except Per Unit Amounts)
(Unaudited)
Three Months Ended
March 31,
-----------------
2007 2006
------- --------
Operating revenues:
Net profits interests................. $ 4,944 $ 6,556
Royalties............................. 9,669 11,947
Lease bonus........................... 93 764
Other................................. 8 12
------- --------
Total operating revenues................... 14,714 19,279
Cost and expenses:
Operating, including production taxes 968 850
Depletion and amortization............ 3,821 4,708
General and administrative expenses... 943 853
------- --------
Total costs and expenses................... 5,732 6,411
------- --------
Operating income .......................... 8,982 12,868
Other income, net.......................... 141 192
------- --------
Net earnings .............................. $ 9,123 $ 13,060
======= ========
Allocation of net earnings:
General partner....................... $ 260 $ 378
======= ========
Unitholders........................... $ 8,863 $ 12,682
======= ========
Net earnings per common unit (in dollars).. $ 0.31 $ 0.45
======= ========
Wtd. avg. common units outstanding (000's). 28,240 28,240
======= ========
The accompanying condensed notes are an integral part of
these financial statements.
5
DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
CONDENSED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)
Three Months Ended
March 31,
--------------------
2006 2005
--------- ---------
Net cash provided by operating activities $ 13,765 $ 21,494
Cash flows provided by investing activities:
Proceeds from related party note receivable 13 13
------- --------
Total cash flows provided by investing activities 13 13
------- --------
Cash flows used in financing activities:
Distributions paid to general partner and unitholders (13,877) (23,382)
-------- --------
Decrease in cash and cash equivalents (99) (1,875)
Cash and cash equivalents at January 1, 13,927 23,389
-------- --------
Cash and cash equivalents at March 31, $ 13,828 $ 21,514
======== ========
The accompanying condensed notes are an integral part of
these financial statements.
6
DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
NOTES TO THE CONDENSED FINANCIAL STATEMENTS
(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 condensed 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 income applicable to holders of our common units by the weighted
average number of units outstanding. Certain amounts in the 2006 financial
statements have been reclassified to conform with the 2007 presentation. Such
reclassifications did not impact net income, or total assets, or total
liabilities.
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. 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. The plaintiffs
consist primarily of Texas County, Oklahoma residents who, in residences located
on leases use natural gas from gas wells located on the same leases, at their
own risk, free of cost. The plaintiffs seek declaration that their domestic gas
use is not limited to stoves and inside lights and is not limited to a principal
dwelling as provided in the oil and gas leases entered into in the 1930s to the
1950s. Plaintiffs' claims against defendants include failure to prudently
operate wells, violation of rights to free domestic gas, and fraud. Plaintiffs
also seek certification of class action against defendants. On October 1, 2004,
the plaintiffs severed claims against the operating partnership regarding
royalty underpayments. On April 9, 2007, plaintiffs, for immaterial costs,
dismissed with prejudice all claims against the operating partnership regarding
domestic gas use. The operating partnership believes plaintiffs' remaining
claim regarding royalty underpayments is completely without merit. An adverse
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 financial position or operating
results.
3. Distributions to Holders of Common Units: Since commencing operations
on January 31, 2003, unitholder cash distributions per common unit have been or
will be:
Per Unit Amount
-----------------------------------------------------
2003 2004 2005 2006 2007
--------- --------- --------- --------- ---------
First Quarter............$0.206469 $0.415634 $0.481242 $0.729852 $0.461146
Second Quarter...........$0.458087 $0.415315 $0.514542 $0.778120
Third Quarter............$0.422674 $0.476196 $0.577287 $0.516082
Fourth Quarter...........$0.391066 $0.426076 $0.805543 $0.478596
Distributions beginning with the third quarter of 2004 were paid on
28,240,431 units; previous distributions were paid on 27,040,431 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, 2007.
7
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Overview
We own producing and nonproducing mineral, royalty, overriding royalty,
net profits and leasehold interests. We refer to these interests as the Royalty
Properties. We currently own Royalty Properties in 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 interests
properties and a minor portion of mineral and royalty interest properties. We
refer to Dorchester Minerals Operating LP as the "operating partnership." We
directly and indirectly own a 96.97% net profits overriding royalty interest in
four property groups, the three created when we commenced operations and the
2003-2006 NPI. We refer to our net profits overriding royalty interest in these
property groups as the Net Profits Interests. We 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.
In accordance with our partnership agreement we have the continuing
right and obligation to create additional Net Profits Interests by transferring
properties to the operating partnership subject to the reservation of a Net
Profits Interest identical to the Net Profit Interests created when we commenced
operations in 2003. The purpose of such Net Profits Interests is to avoid the
Partnership's participation as a working interest or other cost expense-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 was created for each of calendar years
2003 through 2006 by transferring various properties to the operating
partnership subject to a Net Profits Interest. These interests were subsequently
combined and we currently refer to them as the 2003-2006 NPI which is our
fourth separate Net Profits Interest. As of March 31, 2007, cumulative operating
and development costs presented in the following table, which include amounts
equivalent to an interest charge, exceeded cumulative revenues of the 2003-2006
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 2003-2006 NPI recovers the deficit
amount. Once in profit status, we will receive the Net Profits Interest payment
attributable to these properties. Our 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 2003-2006 NPI.
The following table sets forth cash receipts and disbursements
attributable to the 2003-2006 Net Profits Interest:
2003-2006 Net Profits Interest Cash Basis Results
(in Thousands)
--------------------------------------------------
Cumulative Three Months Cumulative
Total at Ended Total at
December 31, 2006 March 31, 2007 March 31, 2007
----------------- --------------- --------------
Cash received for revenue $4,945 $ 634 $ 5,579
Cash paid for operating costs (852) (106) (958)
Cash paid for development costs (4,311) (504) (4,815)
------- ------- -------
Net cash (paid) received $ (218) $ 24 $ (194)
======= ======= =======
Cumulative NPI Deficit $ (218) $ (194) $ (194)
======= ======= =======
The development costs pertain to more properties than the properties
producing revenue due to timing differences between operating partnership
expenditures and oil and gas production and payments to the operating
partnership. Amounts in the above table 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 2003-2006 NPI may not be indicative of future
results of the 2003-2006 NPI and may not indicate when the deficit status may
end and when Net Profits Interests payment may begin from the 2003-2006 NPI.
8
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 and general market volatility.
Results of Operations
Three Months Ended March 31, 2007 as compared to Three Months
Ended March 31, 2006
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,
--------------------------
Accrual Basis Sales Volumes: 2007 2006
--------- ---------
Royalty Properties Gas Sales (mmcf)................. 858 965
Royalty Properties Oil Sales (mbbls)................ 74 85
Net Profits Interests Gas Sales (mmcf).............. 1,016 1,126
Net Profits Interests Oil Sales (mbbls)............. 4 3
Accrual Basis Weighted Average Sales Price:
Royalty Properties Gas Sales ($/mcf)................ $ 6.60 $ 7.39
Royalty Properties Oil Sales ($/bbl)................ $53.87 $56.67
Net Profits Interests Gas Sales ($/mcf)............. $ 6.74 $ 7.42
Net Profits Interests Oil Sales ($/bbl)............. $46.41 $47.04
Accrual Basis Production Costs Deducted
Under the Net Profits Interests ($/mcfe) (1)........ $ 2.08 $ 1.75
________________________________________________________
(1) Provided to assist in determination of revenues; applies only to Net Profit
Interest sales volumes and prices.
Oil sales volumes attributable to our Royalty Properties during the
first quarter decreased 12.9% from 85 mbbls in 2006 to 74 mbbls in 2007.
Natural gas sales volumes attributable to our Royalty Properties during the
first quarter decreased 11.1% from 965 mmcf in 2006 to 858 mmcf in 2007. The
decreases in oil and natural gas sales volumes were primarily attributable to
wells completed in the T-Patch Field in early 2006. As previously reported,
these wells have exhibited significant production declines after initially
producing at anomalously high rates. In addition, Royalty Properties located in
the Mid-Continent experienced weather-related production disruptions in January.
Oil sales volumes attributable to our Net Profits Interests during the
first quarter of 2007 were virtually unchanged from 2006. Natural gas sales
volumes attributable to our Net Profits Interests during the first quarter
decreased 9.8% from 1,126 mmcf during 2006 to 1,016 mmcf during 2007 due to
natural reservoir decline, scheduled equipment and facility maintenance and
weather-related production disruptions in January. Production sales volumes and
prices from the 2003-2006 NPI are excluded from the above table. See "Overview"
above.
Weighted average oil sales prices attributable to our interest in
Royalty Properties decreased 4.9% from $56.67/bbl during the first quarter of
2006 to $53.87/bbl during the first quarter of 2007. Similarly, first quarter
weighted average natural gas sales prices from Royalty Properties decreased
10.7% from $7.39/mcf during 2006 to $6.60/mcf during 2007. Both oil and natural
gas price decreases resulted from changing market conditions.
First quarter weighted average oil sales prices from the Net Profits
Interests' properties decreased 1.3% from $47.04/bbl in 2006 to $46.41/bbl in
2007. First quarter weighted average natural gas sales prices from the Net
Profits Interests' properties decreased 9.2% from $7.42/mcf in 2006 to $6.74/mcf
in 2007. Such oil and natural gas price decreases resulted from changing market
conditions.
In an effort to provide the reader with information concerning prices of
oil and 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
9
oil and gas may be described generally, actual cash receipts may be materially
impacted by purchasers' release of suspended funds and by prior period
adjustments.
Cash receipts attributable to our Net Profits Interests during the 2007
first quarter totaled $5,199,000. These receipts generally reflect oil and gas
sales from the properties underlying the Net Profits Interests during November
2006 through January 2007. The weighted average indicated prices for oil and gas
sales during the 2007 first quarter attributable to the Net Profits Interests
were $45.90/bbl and $6.43/mcf, respectively.
Cash receipts attributable to our Royalty Properties during the 2007
first quarter totaled $9,274,000. These receipts generally reflect oil sales
during December 2006 through February 2007 and gas sales during November 2006
through January 2007. The weighted average indicated prices for oil and gas
sales during the 2007 first quarter attributable to the Royalty Properties were
$53.25/bbl and $6.59/mcf, respectively.
Our first quarter net operating revenues decreased 23.7% from
$19,279,000 during 2006 to $14,714,000 during 2007 primarily as a result of
decreased oil and gas sales prices and volumes. Additionally, first quarter
2006 net operating revenues included a non-refundable lease bonus payment of
$616,000 related to our Arkansas lease transactions.
Costs and expenses decreased 10.6% from $6,411,000 during the first
quarter of 2006 to $5,732,000 during the first quarter of 2007. Such decreases
primarily resulted from decreased depletion and amortization.
Depletion and amortization decreased 18.8% during the first quarter
ended March 31, 2007 when compared to the same period of 2006. The decrease from
$4,708,000 to $3,821,000 resulted from a lower depletable base due to effects of
previous depletion and upward revisions in oil and gas reserve estimates at 2006
year end.
We received cash payments in the amount of $270,000 from various sources
during the first quarter of 2007 including lease bonuses attributable to 13
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 $300/acre.
We received division orders, or otherwise identified, 75 new wells
completed on our Royalty Properties and Net Profit Interests located in 32
counties and parishes in 10 states during the first quarter of 2007. The
operating partnership elected to participate in nine wells to be drilled on our
Net Profits Interests located in six counties in three 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 and discussion. Wells detailed in the Fayetteville Shale discussion are
excluded from this table:
State County/Parish Operator Well Name Ownership Test Rates, per day
----- ------------- --------------------- --------------------- -------------- -------------------------
WI(1) NRI(1) Gas, mcf Oil, bbls
----- ------ -------- ---------
Royalty Properties
------------------
TX Starr Petrohawk Energy Corp Cleopatra #5 -- 1.625% 10,350 86
OK Roger Mills Conoco Phillips Smith 6-5 -- 1.871% 4,114 --
TX Starr Ascent Operating, LP Garza Hitchcock #10 -- 2.653% 2,120 34
TX Panola Chesapeake Operating Bill Powers A #6 -- 5.521% 923 1
TX Hidalgo Samson Lone Star LP Schlaben #6 -- 3.125% 1,552 --
OK Woodward Chesapeake Operating Vera Mae 1-34 -- 3.750% 987 --
AR Logan The Houston Expl Co Lowder GU 7-2 -- 0.459% 7,762 --
OK Beckham Apache Corp. Perryman 8-25 -- 1.489% 1,816 5
Net Profits Interests
---------------------
MT Richland Slawson Exploration Saber 1-4H 1.645% 1.645% -- 223
ND Mountrail Petro-Hunt Rice 10B-2-1H 0.175% 0.175% -- 193
____________________________________
(1) WI and NRI mean working interest and net revenue interest, respectively.
10
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. Nineteen wells have been permitted on the lands as of
April 27, 2007. Wells which 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. Information concerning the permitted wells is
set forth below:
DMLP DMOLP
------- ---------------- -----------
County Operator Well Name NRI(2) WI(1) NRI(2) Mcf per day
-------- ------------- ----------------------- ------- ---------------- -----------
Cleburne SEECO Mulliniks 9-12 #1-35H 7.266% 5.000% 3.750% --
Cleburne SEECO Mulliniks 9-12 #2-35H 7.266% 5.000% 3.750% --
Cleburne SEECO Mulliniks 9-12 #3-35H 7.266% 5.000% 3.750% --
Conway SEECO Beck 8-16 #1-1H 10.000% 5.000% 3.750% --
Conway Arrington Beverly Crofford #1-14 H 2.500% 1.250% 0.938% --
Conway SEECO Jerome Carr #1-31H 5.054% 3.796% 2.847% 1,846
Conway SEECO Jerome Carr #2-31H 5.054% 3.796% 2.847% 3,234
Conway SEECO Polk 09-15 #1-30H 10.114% 5.556% 4.216% --
Pope Penn Virginia Brown #1-33H 2.500% 1.250% 0.938% --
Pope Penn Virginia Tackett #1-33H 2.500% 1.250% 0.938% 287
Van Buren SEECO Hillis #1-27 6.250% 6.250% 6.250% 880
Van Buren SEECO Hillis #1-27H 0.781% 0.000% 0.781% 2,334
Van Buren SEECO Jones 10-16 #1-33H 3.125% 3.125% 3.125% 2,207
Van Buren SEECO Jones 10-16 #2-33H 3.125% 3.125% 3.125% --
Van Buren SEECO Quattlebaum #1-32H 0.781% 0.000% 0.000% 1,717
Van Buren SEECO Quattlebaum #2-32H 0.781% 0.000% 0.000% --
Van Buren SEECO Russell #1-33H 6.250% 6.250% 6.250% 2,928
Van Buren SEECO Russell #2-33H 6.250% 6.250% 6.250% 844
White Chesapeake Hays 8-6 #1-18H 0.781% 0.000% 0.000% --
____________________________________
(1) WI means the working interest owned by the operating partnership and
subject to the Net Profits Interest.
(2) NRI means the net revenue interest attributable to our royalty interest
or to the operating partnership's working interest
and subject to the Net Profits Interest.
First quarter net earnings allocable to common units decreased 30.1%
from $12,682,000 during 2006 to $8,863,000 during 2007. The 2007 decrease from
first quarter 2006 net earnings is primarily a result of decreased 2007 oil and
gas sales prices and decreased gas sales volumes.
Net cash provided by operating activities decreased 36.0% from
$21,494,000 during the first quarter of 2006 to $13,765,000 during the first
quarter of 2007 due to market pricing of oil and gas sales which resulted in
more income as well as higher receivables in first quarter 2006. See discussion
above on volumes and prices.
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 prices and sales 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 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
11
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
During February 2007 the operating partnership drilled one replacement
Guymon-Hugoton well and one Council Grove formation well, both in Oklahoma. The
Guymon-Hugoton well is awaiting connection to a pipeline. The Council Grove well
was a dry hole costing approximately $280,000. Final cost of the replacement
Guymon-Hugoton well is expected to be $430,000.
During 2007, depending upon rig availability, the operating partnership
anticipates drilling one additional well in the Oklahoma Council Grove
formation. The operating partnership does not otherwise currently anticipate
drilling additional wells as a working interest owner/operator in the Oklahoma
or Kansas properties. Successful activities by others or other developments
could prompt a reevaluation of this position. Present drilling and completion
costs are estimated at $350,000 - $450,000 per well. Such activities by the
operating partnership could influence the amount we receive from the Net Profits
Interests.
The operating partnership anticipates continuing fracture treating in
its Oklahoma properties but is unable to predict the cost as a specific
engineering study is required for each fracture treatment. Previous fracture
treatments in these properties have cost between $50,000 and $80,000 per well.
They did not require casing repairs. Such activities by the operating
partnership could influence the amount we receive from the Net Profits
Interests.
The operating partnership owns and operates the wells, pipelines and 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 are reflected in the
Net Profits Interests payments we receive from the operating partnership.
In 1998, Oklahoma regulations removed production quantity restrictions
in the Guymon-Hugoton field, and did not address efforts by third parties to
persuade Oklahoma to permit infill drilling in the Guymon-Hugoton field. Infill
drilling could require considerable capital expenditures. The outcome and the
cost of such activities are unpredictable and could influence the amount we
receive from the 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 $13,828,000 at March 31, 2007 and
$13,927,000 at December 31, 2006.
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 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 more significant revisions
will not be necessary in the future. Significant downward revisions could result
in an impairment representing a non-cash charge to earnings. In addition to the
impact
12
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 inability to gain accurate and timely information. Therefore, actual results
could differ from those estimates.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The following information provides quantitative and qualitative
information about our potential exposures to market risk. The term "market risk"
refers to the risk of loss arising from adverse changes in oil and natural gas
prices, interest rates and currency exchange rates. The disclosures are not
meant to be precise indicators of expected future losses, but rather indicators
of reasonably possible losses.
Market Risk Related to Oil and Natural Gas Prices
Essentially all of our assets and sources of income are from the
Royalties 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 which could expose us to foreign currency related market risk.
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, our principal
executive officer and principal financial officer carried out an evaluation of
the effectiveness of our disclosure controls and procedures. Based on their
evaluation, they have concluded that our disclosure controls and procedures
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, 2007 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.
13
PART II
ITEM 1. LEGAL PROCEEDINGS
See Note 2 - Contingencies, to the Financial Statements.
ITEM 1A. RISK FACTORS
None.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
ITEM 5. OTHER INFORMATION
None.
ITEM 6. EXHIBITS
See the attached Index to Exhibits.
14
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
/s/ William Casey McManemin
------------------------------------------
William Casey McManemin
Date: May 3, 2007 Chief Executive Officer
/s/ H.C. Allen, Jr.
------------------------------------------
H.C. Allen, Jr.
Date: May 3, 2007 Chief Financial Officer
15
INDEX TO EXHIBITS
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