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 September 30, 2006
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 November 6, 2006, 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 SEPTEMBER 30, 2006 (UNAUDITED) AND
DECEMBER 31, 2005..............................................4
CONDENSED STATEMENTS OF OPERATIONS FOR THE THREE AND NINE MONTHS ENDED
SEPTEMBER 30, 2006 AND 2005 (UNAUDITED)........................5
CONDENSED STATEMENTS OF CASH FLOWS FOR THE NINE MONTHS ENDED
SEPTEMBER 30, 2006 AND 2005 (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....................................................................14
INDEX TO EXHIBITS.............................................................15
CERTIFICATIONS................................................................16
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
Partnership's properties, changes in economic and industry conditions and
changes in regulatory requirements (including changes in environmental
requirements) and our Partnership's financial position, business strategy and
other plans and objectives for future operations. These and other factors are
set forth in our Partnership's 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.
DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
CONDENSED BALANCE SHEETS
(Dollars in Thousands)
September 30, December 31,
2006 2005
----------- -----------
ASSETS (unaudited)
Current assets:
Cash and cash equivalents $ 16,118 $ 23,389
Trade receivables 6,304 7,615
Net profits interests receivable - related party 3,901 6,996
Current portion of note receivable - related party 50 50
Prepaid expenses 12 22
-------- --------
Total current assets 26,385 38,072
Note receivable - related party less current portion 17 55
Other non-current assets 19 19
-------- --------
Total 36 74
Property and leasehold improvements - at cost:
Oil and natural gas properties (full cost method): 291,875 291,875
Less accumulated full cost depletion 143,914 129,643
-------- --------
Total 147,961 162,232
Leasehold improvements 512 512
Less accumulated amortization 97 60
-------- --------
Total 415 452
-------- --------
Net property and leasehold improvements 148,376 162,684
-------- --------
Total assets $174,797 $200,830
======== ========
LIABILITIES AND PARTNERSHIP CAPITAL
Current liabilities
Accounts payable and other current liabilities $ 1,606 $ 580
Current portion of deferred rent incentive 39 39
-------- ---------
Total current liabilities 1,645 619
-------- --------
Deferred rent incentive less current portion 297 326
-------- --------
Total liabilities 1,942 945
-------- --------
Commitments and contingencies
Partnership capital:
General partner 6,961 7,663
Unitholders 165,894 192,222
-------- --------
Total partnership capital 172,855 199,885
-------- --------
Total liabilities and partnership capital $174,797 $200,830
======== ========
The accompanying condensed notes are an integral part of
these financial statements.
DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
CONDENSED STATEMENT OF OPERATIONS
(Dollars in Thousands except Earnings per Unit)
(Unaudited)
Three Months Ended Six Months Ended
September 30, September 30,
----------------- ------------------
2006 2005 2006 2005
------- -------- -------- ---------
Operating revenues:
Net profits interests................. $ 5,125 $ 8,755 $17,003 $ 21,329
Royalties............................. 11,481 14,442 35,245 33,077
Lease bonus........................... 281 456 7,017 606
Other................................. 10 17 39 47
------- -------- ------- --------
Total operating revenues.............. 16,897 23,670 59,304 55,059
Cost and expenses:
Operating, including production taxes 1,315 1,028 3,134 2,501
Depletion and amortization............ 4,787 5,659 14,308 16,161
General and administrative expenses... 733 618 2,337 2,085
------- -------- ------- --------
Total costs and expenses................... 6,835 7,305 19,779 20,747
------- -------- ------- --------
Operating income .......................... 10,062 16,365 39,525 34,312
Other income (expense), net:
Investment income..................... 171 95 557 219
Other income (expense), net........... 159 (57) 159 (61)
------- -------- ------- --------
Total other income (expense), net..... 330 38 716 158
Net earnings .............................. $10,392 $ 16,403 $40,241 $ 34,470
======= ======== ======= ========
Allocation of net earnings:
General partner....................... $ 310 $ 461 $ 1,234 $ 946
======= ======== ======= ========
Unitholders........................... $10,082 $ 15,942 $39,007 $ 33,524
======= ======== ======= ========
Net earnings per common unit (basic and
diluted)................................. $ 0.36 $ 0.57 $ 1.38 $ 1.19
======= ======== ======= ========
Wtd. avg. common units outstanding 28,240 28,240 28,240 28,240
======= ======== ======= ========
The accompanying condensed notes are an integral part of
these financial statements.
DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
CONDENSED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)
Nine Months Ended
September 30,
--------------------
2006 2005
--------- ---------
Net cash provided by operating activities $ 59,962 $ 46,487
Cash flows used in investing activities:
Proceeds from related party note receivable 38 39
Capital expenditures - (109)
------- --------
Total cash flows provided by (used in) investing activities 38 (70)
------- --------
Cash flows used in financing activities:
Distributions paid to general partner and unitholders (67,271) (41,256)
-------- --------
Increase (decrease) in cash and cash equivalents (7,271) 5,161
Cash and cash equivalents at January 1, 23,389 12,365
-------- --------
Cash and cash equivalents at September 30, $ 16,118 $ 17,526
======== ========
The accompanying condensed notes are an integral part of
these financial statements.
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 commenced operations on January 31, 2003, upon
the combination of Dorchester Hugoton, Ltd., which was a publicly traded Texas
limited partnership, and Republic Royalty Company and Spinnaker Royalty Company,
L.P., both of which were privately held Texas partnerships.
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
Partnership's 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 Partnership's
common units by the weighted average number of units outstanding. Certain
amounts in the 2005 financial statements have been reclassified to conform
with the 2006 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 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 our Partnership. 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 Dorchester Minerals Operating LP
regarding royalty underpayments. Dorchester Minerals Operating LP believes
plaintiffs' claims, including severed claims, are completely without
merit. Based upon past measurements of such domestic gas usage, Dorchester
Minerals Operating LP believes the domestic gas damages sought by plaintiffs to
be minimal. An adverse decision could reduce amounts our Partnership receives
from the Net Profits Interests.
Our Partnership and Dorchester Minerals Operating LP 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 our Partnership's
combination on January 31, 2003, unitholder cash distributions per common unit
have been or will be:
Year Quarter Record Date Payment Date Amount
---- ------------- ---------------- ----------------- ----------
2003 1st (partial) April 28, 2003 May 8, 2003 $0.206469
2003 2nd July 28, 2003 August 7, 2003 $0.458087
2003 3rd October 31, 2003 November 10, 2003 $0.422674
2003 4th January 26, 2004 February 5, 2004 $0.391066
2004 1st April 30, 2004 May 10, 2004 $0.415634
2004 2nd July 26, 2004 August 5, 2004 $0.415315
2004 3rd October 25, 2004 November 4, 2004 $0.476196
2004 4th February 1, 2005 February 11, 2005 $0.426076
2005 1st April 29, 2005 May 9, 2005 $0.481242
2005 2nd July 25, 2005 August 4, 2005 $0.514542
2005 3rd October 24, 2005 November 3, 2005 $0.577287
2005 4th January 30, 2006 February 9, 2006 $0.805543
2006 1st May 1, 2006 May 11, 2006 $0.729852
2006 2nd July 24, 2006 August 3, 2006 $0.778120
2006 3rd October 23, 2006 November 3, 2006 $0.516082
Distributions beginning with the third quarter of 2004 were paid on
28,240,431 units; previous distributions were paid on 27,040,431 units. Our
partnership agreement requires the next cash distribution to be paid by
February 14, 2007.
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 the working interest
properties previously owned by Dorchester Hugoton and a minor portion of
mineral, royalty and working interest properties previously owned by Republic
and Spinnaker. 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 these properties. We refer to our net profits overriding
royalty interest in these properties as the Net Profits Interests. We receive
monthly payments equaling 96.97% of the net profits actually realized by the
operating partnership from these properties in the preceding month.
In accordance with our partnership agreement we have the continuing
right 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 Profits Interests created upon our formation. Two such
interests, called the 2003/2004/2005 NPI and the 2006 NPI, resulted from
transferring various properties to the operating partnership subject to a Net
Profits Interest. As of September 30, 2006 cumulative costs and expenses, which
include an interest equivalent, totaled $4,111,000 attributable to the
2003/2004/2005 NPI properties and exceeded cumulative revenues by $115,000, an
amount which we refer to as the 2003/2004/2005 NPI deficit. The 2006 NPI deficit
was $85,000, with no revenues received. Our financial statements do not reflect
activity attributable to properties subject to Net Profits Interests that are in
a deficit status, except for temporary deficits. Consequently, revenues,
expenses, production sales volumes and prices set forth herein do not reflect
amounts attributable to the 2003/2004/2005 NPI or the 2006 NPI properties.
However, information concerning acreage owned and drilling activity attributable
to these properties is included herein.
Commodity Price Risks
Our profitability is affected by volatility in prevailing oil and
natural gas prices. Oil and natural gas prices have been subject to significant
volatility in recent years in response to changes in the supply and demand for
oil and natural gas in the market and general market volatility.
Results of Operations
Three and Nine Months Ended September 30, 2006 as compared to Three and Nine
Months Ended September 30, 2005
Normally, our period-to-period changes in net earnings and cash flows
from operating activities are principally determined by changes in crude oil
and natural gas sales volumes and prices. Our portion of oil and natural gas
sales and weighted average prices were:
Three Months Ended Nine Months Ended
----------------------- -----------------
September 30, June 30, September 30,
-------------- --------- ----------------
Accrual Basis Sales Volumes: 2006 2005 2006 2006 2005
---------------------------- ------- ------- ------- ------- ------
Net Profits Interests Gas Sales (mmcf) 1,128 1,228 1,140 3,394 3,666
Net Profits Interests Oil Sales (mbbls) 4 2 4 11 7
Royalty Properties Gas Sales (mmcf) 1,018 1,097 1,014 2,997 2,961
Royalty Properties Oil Sales (mbbls) 84 94 84 253 264
Weighted Average Sales Price:
Net Profits Interests Gas Sales ($/mcf) $ 5.87 $ 8.49 $ 5.80 $ 6.36 $ 7.10
Net Profits Interests Oil Sales ($/bbl) $63.25 $57.20 $53.51 $55.04 $48.84
Royalty Properties Gas Sales ($/mcf) $ 6.09 $ 8.22 $ 6.18 $ 6.54 $ 6.71
Royalty Properties Oil Sales ($/bbl) $62.83 $57.78 $65.86 $61.77 $50.04
Production Costs Deducted
Under the Net Profits
Interests ($/mcfe) (1) $ 1.61 $ 1.48 $ 1.36 $ 1.57 $ 1.40
________________________________________________________
(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
third quarter decreased 10.6% from 94 mbbls in 2005 to 84 mbbls in 2006. Oil
sales volumes attributable to our Royalty Properties during the first nine
months decreased 4.2% from 264 mbbls in 2005 to 253 mbbls in 2006. Natural
gas sales volumes attributable to our Royalty Properties during the third
quarter decreased 7.2% from 1,097 mmcf in 2005 to 1,018 mmcf in 2006. Natural
gas sales volumes attributable to our Royalty Properties during the first nine
months increased 1.2% from 2,961 in 2005 to 2,997 mmcf in 2006. The decreases in
oil and natural gas sales volumes are primarily attributable to new wells
drilled on the Royalty Properties in late 2004 and early 2005. As previously
reported, these wells have exhibited significant production declines after
initially producing at anomalously high rates. Year to date natural gas sales
volumes attributable to our Royalty Properties were positively affected by prior
period adjustments received in the second and third quarter. Oil and natural
gas sales volumes attributable to our Royalty Properties during the third
quarter were essentially unchanged from second quarter levels.
Oil sales volumes attributable to our Net Profits Interests during the
third quarter and first nine months of 2006 increased from 7 to 11 mbbls
respectively when compared to the same periods of 2005 as a result of additional
wells being developed on existing Net Profits Interests' properties. Natural gas
sales volumes attributable to our Net Profits Interests during the third quarter
and first nine months of 2006 decreased from the same periods of 2005. Third
quarter sales of 1,128 mmcf during 2006 were 8.1% less than 1,2228 mmcf during
2005. First nine months sales of 3,394 mmcf during 2006 were 7.4% less than
3,666 mmcf during 2005. The natural gas sales volume decreases were a result of
natural reservoir decline. Production sales volumes and prices from the
2003/2004/2005 NPI and the 2006 NPI properties are excluded from the above
table. See "Overview" above.
Weighted average oil sales prices attributable to our interest in
Royalty Properties increased 8.7% from $57.78/bbl during the third quarter of
2005 to $62.83/bbl during the third quarter of 2006 and 23.4% from $50.04/bbl
during the first nine months of 2005 to $61.77/bbl during the first nine months
of 2006. The third quarter weighted average natural gas sales prices from
Royalty Properties were down 25.9% from $8.22/mcf during 2005 to $6.09/mcf
during 2006. The nine months ended September 30 weighted average natural gas
sales prices decreased 2.5% from $6.71/mcf during 2005 to $6.54/mcf during 2006.
Both oil and natural gas price changes resulted from changing market conditions.
Third quarter weighted average oil sales prices from the Net Profits
Interests' properties increased 10.6% from $57.20/bbl in 2005 to $63.25/bbl in
2006. The first nine months Net Profits Interests oil sales prices increased
12.7% from $48.84/bbl in 2005 to $55.04/bbl in 2006. Weighted average natural
gas sales prices attributable to the Net Profits Interests decreased during the
third quarter and the first nine months of 2006 compared to the same periods of
2005. Third quarter natural gas sales prices of $5.87/mcf in 2006 were 30.9%
less than $8.49/mcf in 2005. The nine months ended September 30, 2006 natural
gas prices decreased 10.4% to $6.36/mcf from $7.10/mcf in the same period of
2005. Changing market conditions resulted in increased oil prices and decreased
natural gas sales prices.
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 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 2006
third quarter totaled $5,069,000. These receipts generally reflect oil and gas
sales from the properties underlying the Net Profits Interests during May
through July 2006. The weighted average indicated prices for oil and gas sales
during the 2006 third quarter attributable to the Net Profits Interests were
$60.08/bbl and $5.70/mcf, respectively.
Cash receipts attributable to our Royalty Properties during the 2006
third quarter totaled $10,390,000. These receipts generally reflect oil sales
during June through August 2006 and gas sales during May through July 2006. The
weighted average indicated prices for oil and gas sales during the 2006 third
quarter attributable to the Royalty Properties were $64.37/bbl and $6.07/mcf,
respectively.
Our third quarter net operating revenues decreased 28.6% from
$23,670,000 during 2005 to $16,897,000 during 2006 primarily as a result of
decreased gas sales prices and decreased gas and oil sales volumes partially
offset by increased oil sales prices. Net operating revenues for the first nine
months of 2006 increased 7.7% from $55,059,000 during 2005 to $59,304,000. The
nine-month changes resulted primarily from essentially unchanged royalty natural
gas sales volumes and prices, decreased NPI gas volumes and prices and increased
oil sales prices offset by decreased oil sales volumes. Year to date net
operating revenues during 2006 included lease bonus payments of $6,151,000
attributable to the previously announced Arkansas lease transaction.
Costs and expenses decreased 6.4% from $7,305,000 during the third
quarter of 2005 to $6,835,000 during the third quarter of 2006, while the nine
months ended September 30 costs and expenses decreased 4.7% from $20,747,000
during 2005 to $19,779,000 during 2006. Such decreases primarily resulted from
decreased depletion and amortization, offset by increased ad valorem taxes on
royalty properties as a result of increased taxing authority valuations due to
higher product prices at 2005 year end.
Investment income increased from $95,000 in the third quarter of 2005
to $171,000 in the third quarter of 2006, and increased from $219,000 in the
first nine months of 2005 to $557,000 in the first nine months of 2006, due to
increased cash flows and higher interest rates during the first nine months of
2006. We received $159,000 in other income related to class action litigation
settlements during the third quarter of 2006.
Depletion and amortization decreased 15.4% during the third quarter
ended September 30, 2006 and 11.5% during the nine months ended September 30,
2006 when compared to the same periods of 2005. The decreases from $5,659,000
and $16,161,000 during the third quarter and nine months ended September 30,
2005 respectively, to $4,787,000 and $14,308,000 during the same periods of 2006
respectively, resulted from a lower depletable base due to effects of previous
depletion.
We received cash payments in the amount of $604,000 from various
sources during the third quarter of 2006 including lease bonuses attributable to
12 consummated leases and pooling elections located in six counties and
parishes in four states. The consummated leases reflected royalty terms ranging
up to 25% and lease bonuses ranging up to $625/acre.
We received division orders, or otherwise identified, 98 new wells
completed on our Royalty Properties and Net Profit Interests located in 49
counties and parishes in 11 states during the third quarter of 2006. The
operating partnership elected to participate in seven wells to be drilled on our
Net Profits Interests located in six counties in four 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:
County/
State Parish Operator Well Name Ownership Test Rates, per day
----- ------- ----------- -------------- ------------ -------------------
WI(1) NRI(1) Gas,mcf Oil,bbls
----- ------ ------- --------
Royalty Properties
--------------------
TX Jackson Neumin Prod. Kubecka GU #1 -- 1.4% 4,000 400
TX Wheeler Devon Effie Hayes 18-3 -- 3.1% 3,004 17
OK Love Finley Res. W.Enville WMA 1-31 -- 2.4% 1,230 334
TX Panola Chesapeake Bill Powers A #5 -- 5.5% 1,116 37
TX Upton Pure Res. Bloxom A #3 -- 0.1% 3,351 364
TX Austin Jamex Beckendorff GU No.2 -- 1.8% 2,564 12
Net Profits Interests
---------------------
MT Richland Continental Carda 2-28 6.3% 5.9% 451 670
OK Ellis Crusader Raiders 1-27 3.8% 9.1% 640 71
OK Ellis Crusader Raiders 2-27H 3.8% 9.1% -- 333
AR Van Buren SEECO Russell 2-33H 6.3% 6.3% 866 --
OK Grady Ward Pet. McCasland Farms 1-18 0.8% 0.8% 2,122 32
____________________________________
(1) WI and NRI mean working interest and net revenue interest, respectively.
FAYETTEVILLE SHALE LEASE TRANSACTION - We entered into an agreement on
March 30, 2006 to lease our interest in certain lands located in Cleburne,
Conway, Faulkner, Franklin, Johnson, Pope, Van Buren, and White Counties,
Arkansas. We received a non-refundable payment in the amount of $616,000, which
amount was included in the Partnership's first quarter distribution to
unitholders. The agreement provided 90 days for title due diligence and
documentation.
On June 28, 2006 we leased our average 8.6% mineral interest in 179
sections of land in these eight counties and received additional payments
totaling $5,535,000. This amount was included in our second quarter distribution
to unitholders. The leases reflect one-fourth royalty and five year primary
terms. Assuming the lands are pooled into 640 acre units, we will own an average
2.1% net royalty interest in each well drilled in these sections. In addition to
the basic lease terms, we have the option, but not the obligation, to
participate for an average 3.5% net working interest in 117 of 179 sections. To
date, elections have been made to participate in three wells under this
agreement with working interests ranging from 3.8% to 5.0%. A fourth well has
been permitted.
We elected not to lease our interest in four sections located in the
Gravel Hill Field area of Van Buren County, representing an additional 260 net
mineral acres. The Partnership's optional working interest in the leased lands
and the unleased mineral interest in the Gravel Hill Field area have been
assigned to the operating partnership pursuant to the existing Net Profits
Interest agreements. Two horizontal wells have been drilled and completed and
one additional well has been proposed on these lands. The SEECO Russell 2-33H
well, located in the Gravel Hill Field area of Van Buren County, was completed
on August 26 at a reported initial rate of 866 mcfd. The operating partnership
has also elected to participate in the Jones 10-16 1-33H with a 3.1% working
interest.
Third quarter net earnings allocable to common units decreased 36.8%
from $15,942,000 during 2005 to $10,082,000 during 2006. First nine months
common unit net earnings increased 16.4% from $33,524,000 during 2005 to
$39,007,000 during 2006. The 2006 decrease from third quarter 2005 net earnings
is primarily a result of decreased 2006 gas sales prices and, to a lesser
extent, decreased gas sales volumes. Third quarter 2006 oil sales price
increases from 2005 more than offset oil sales volume decreases from 2005. The
2006 nine-month period compared to the same period in 2005 increased because of
lower gas prices and lower gas and oil volumes in 2006 were more than offset by
increased 2006 oil sales prices and the $6,151,000 lease bonus payments in 2006
attributable to the previously announced Arkansas lease transaction.
Net cash provided by operating activities decreased 9.1% from
$17,005,000 during the third quarter of 2005 to $15,451,000 during the third
quarter of 2006. Net cash from operating activities for the first nine months
increased 29.0% from $46,487,000 in 2005 to $59,962,000 in 2006. Comparing the
2006 third quarter cash flow to the same period of 2005 shows that the
combination of oil price changes and oil volume changes essentially yielded the
same cash flow, while gas price declines and gas volume declines reduced overall
cash from operations. Gas prices and gas volumes in the 2006 nine-month period
were slightly lower than the same period in 2005, while oil prices in 2006 were
sharply higher than 2005 with 2006 oil volumes somewhat lower than 2005. These
nine-month period volume and price changes when combined with the $6,151,000
lease bonus payments in 2006 attributable to the previously announced Arkansas
transaction yielded an increase in 2006 nine-month cash from operations.
Texas Margin Tax
The Texas Legislature recently passed H.B. 3 which is a new tax system,
commonly referred to as the Texas margin tax. The Texas margin tax applies to
corporations and limited liability companies, general and limited partnerships
(unless otherwise exempt), limited liability partnerships, trusts (unless
otherwise exempt), business trusts, business associations, professional
associations, joint stock companies, holding companies, and joint ventures. The
effective date of the Texas margin tax is January 1, 2008, but the tax generally
will be imposed on gross revenues generated in 2007 and thereafter.
Limited partnerships that receive at least 90% of their gross income
from designated passive sources, including royalties from mineral properties and
other non-operated mineral interest income, and do not receive more than 10% of
their income from operating an active trade or business, are generally exempt
from the Texas margin tax as "passive entities." Our Partnership should meet the
requirements for being considered a "passive entity" for Texas margin tax
purposes and, therefore, it should be exempt from the Texas margin tax. If
exempt from tax at the Partnership level as a passive entity, each unitholder
that is considered a taxable entity under the Texas margin tax would generally
be required to include its Texas portion of Partnership revenues in its own
Texas margin tax computation.
Each unitholder is urged to consult his own tax advisor regarding the
requirements for filing state income, franchise and Texas margin tax returns.
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 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 2006-2008, depending upon rig availability, the operating partnership
anticipates drilling possibly two wells in the Oklahoma Council Grove formation,
deepening one existing Oklahoma Guymon-Hugoton well, and drilling one
replacement Guymon-Hugoton well. The operating partnership does not otherwise
currently anticipate drilling additional wells as a working interest
owner/operator in the Fort Riley zone or elsewhere in the Oklahoma properties.
Successful activities by others in these formations or other developments could
prompt a reevaluation of this position. Any such drilling is estimated to cost
$350,000 to $450,000 per well while deepening a well should cost less than
$150,000. Such activities by the operating partnership could influence the
amount we receive from the Net Profits Interests.
During the 2006 third quarter, the operating partnership fracture
treated one Oklahoma well which improved production from 208 mcf per day to 278
mcf per day while also increasing well shut-in pressure. The cost, including
casing leak repair, was $118,000.The operating partnership anticipates
continuing additional 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 147 wells, with associated
pipelines and gas compression and dehydration facilities located in Kansas and
Oklahoma Hugoton fields. The operating partnership anticipates gradual
increases in expenses as repairs and major maintenance to these facilities
becomes 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 Profit
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 by the operating partnership 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 $16,118,000 at September 30, 2006 and
$23,389,000 at December 31, 2005.
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.
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 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 Net
Profits Interests and the Royalty Properties, 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
September 30, 2006 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
ITEM 1. LEGAL PROCEEDINGS
None.
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.
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
Chief Executive Officer
Date: November 6, 2006
/s/ H.C. Allen, Jr.
-----------------------------------------------
H.C. Allen, Jr.
Chief Financial Officer
Date: November 6, 2006
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)
15