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 June 30, 2004
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)
3738 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 if the Registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes X No
As of August 3, 2004, 27,040,431 common units of partnership interest were
outstanding.
Page 1
TABLE OF CONTENTS
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS................................3
PART I.........................................................................3
ITEM 1. FINANCIAL INFORMATION...............................................3
CONDENSED BALANCE SHEETS AS OF JUNE 30, 2004 (UNAUDITED) AND
DECEMBER 31, 2003......................................................4
CONDENSED STATEMENTS OF OPERATIONS FOR THE THREE AND SIX MONTHS ENDED
JUNE 30, 2004 AND 2003 (UNAUDITED).....................................5
CONDENSED STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED
JUNE 30,2004 AND 2003 (UNAUDITED)......................................6
NOTES TO THE CONDENSED FINANCIAL STATEMENTS...............................7
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS...............................................9
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 2. CHANGES IN 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 AND REPORTS ON FORM 8-K...................................14
SIGNATURES....................................................................15
INDEX TO EXHIBITS.............................................................16
CERTIFICATIONS................................................................17
Page 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 made 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 the
Partnership's properties, changes in economic and industry conditions and
changes in regulatory requirements (including changes in environmental
requirements) and the Partnership's financial position, business strategy and
other plans and objectives for future operations. These and other factors are
set forth in the 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
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 amounts and results of operations of
Dorchester Minerals included in these financial statements as historical amounts
prior to February 1, 2003 reflect the results of operations of Dorchester
Hugoton. The effect of the combination is reflected in the balance sheet and in
the results of operations and cash flows since January 31, 2003. The combination
was accounted for using the purchase method of accounting.
PAGE 3
DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
CONDENSED BALANCE SHEETS
(Dollars in Thousands)
June 30, December 31,
2004 2003
------------ -----------
(unaudited)
ASSETS
Current assets:
Cash and cash equivalents....................... $ 11,901 $ 10,881
Trade receivables............................... 8,884 7,658
Note receivable - related party................. 180 205
Prepaid expenses................................ 36 69
--------- ---------
Total current assets........................ 21,001 18,813
Oil and natural gas properties - at cost (full
cost method)..................................... 268,230 268,189
Less accumulated depletion................... (98,374) (88,051)
--------- ---------
Net oil and natural gas properties............ 169,856 180,138
--------- ---------
Total assets................................ $190,857 $198,951
========= =========
LIABILITIES AND PARTNERSHIP CAPITAL
Current liabilities:
Accounts payable and other current liabilities.. $ 829 $ 512
--------- ---------
Total current liabilities.................. 829 512
Commitments and contingencies - -
Partnership capital:
General partner ................................ 8,036 8,246
Unitholders..................................... 181,992 190,193
--------- ---------
Total partnership capital.................. 190,028 198,439
--------- ---------
Total liabilities and partnership capital............ $190,857 $198,951
========= =========
The accompanying condensed notes are an integral part
of these financial statements.
PAGE 4
DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
CONDENSED STATEMENTS OF OPERATIONS
(Dollars in Thousands)
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
----------------- ------------------
2004 2003 2004 2003
------- --------- -------- ---------
Net operating revenues:
Net profits interest.................. $ 6,292 $ 5,332 $12,286 $ 10,206
Natural gas sales..................... - - - 2,401
Royalties............................. 6,816 5,901 13,855 12,456
Other................................. 272 67 680 193
------- --------- -------- ---------
Total net operating revenues.......... 13,380 11,300 26,821 25,256
Cost and expenses:
Operating, including production taxes. 497 534 1,080 1,316
Depreciation, depletion and amort..... 5,022 6,672 10,323 11,643
Impairment of full cost properties.... - 22,214 - 22,214
General and administrative............ 748 687 1,590 1,594
Management fees....................... - - - 524
Combination costs and related expenses - 173 - 3,080
------- --------- -------- --------
Total operating expenses.............. 6,267 30,280 12,993 40,371
------- --------- -------- ---------
Operating income (loss).................... 7,113 (18,980) 13,828 (15,115)
Other income (expense)
Investment income..................... 19 4 36 25
Other income (expense), net........... 176 48 95 105
------- --------- -------- ---------
Total other income (expense).......... 195 52 131 130
Net earnings (loss)........................ $ 7,308 $(18,928) $13,959 $(14,985)
======= ========= ======== =========
Allocation of net earnings (loss):
General partner....................... $ 180 $ (479) $ 346 $ (348)
======= ========= ======== =========
Unitholders........................... $ 7,128 $(18,449) $13,613 $(14,637)
======= ========= ======== =========
Net earnings (loss) per common
unit(in dollars).......................... $ 0.26 $ (0.68) $ .50 $ (0.60)
======= ========= ======== =========
Wtd. avg. common units outstanding (000's) 27,040 27,040 27,040 24,324
======= ========= ======== =========
The accompanying condensed notes are an integral part
of these financial statements.
PAGE 5
DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
CONDENSED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
Six Months Ended
June 30,
----------------------
2004 2003
--------- ---------
Net cash provided by operating activities. ........... $ 23,518 $ 16,286
--------- ---------
Cash flows from investing activities:
Cash received in combination................... - 68
Capital expenditures........................... (128) (5)
--------- ---------
Net cash provided by (used in) investing activities... (128) 63
--------- ---------
Cash flows from financing activities:
Distributions paid to Partners................ (22,370) (26,365)
--------- ---------
Increase (decrease) in cash and cash equivalents...... 1,020 (10,016)
Cash and cash equivalents at January 1................ 10,881 23,129
--------- ---------
Cash and cash equivalents at June 30.................. $ 11,901 $ 13,113
========= =========
Non cash investing and financing activities:
Acquisition of assets for units
Oil and gas properties...................... $ - $233,466
Receivables................................. - 3,660
Cash........................................ - 68
--------- ---------
Value assigned to assets acquired........... $ - $237,194
========= =========
The accompanying condensed notes are an integral part
of these financial statements.
PAGE 6
DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
NOTES TO THE CONDENSED FINANCIAL STATEMENTS
(Unaudited)
1. BASIS OF PRESENTATION: Dorchester Minerals, L.P. (the "Partnership") is a
publicly traded Delaware limited partnership that was formed in December 2001 in
connection with the combination, which was completed on January 31, 2003, of
Dorchester Hugoton, Ltd., which was a publicly traded Texas limited partnership,
and Republic Royalty Company (Republic) and Spinnaker Royalty Company, L.P.,
(Spinnaker) 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 the 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 the Partnership's common units by
the weighted average number of units outstanding.
The accompanying financial statements reflect the combination completed on
January 31, 2003 and accounted for using the purchase method of accounting. In
accordance with the purchase method of accounting, Dorchester Hugoton was
designated as the accounting acquiror. Under the purchase method of accounting,
the Partnership used the market price of Dorchester Hugoton's partnership units
on the last day of trading, adjusted for the liquidating distribution to
Dorchester Hugoton Unitholders, to determine the value of the Republic and
Spinnaker oil and gas properties merged into the Partnership. Such method
increased the historic book values of the oil and gas properties of Republic and
Spinnaker by approximately $192,000,000, which increased the Partnership's
quarterly depletion. See the Partnership's Form 8-K filed on April 15, 2003 and
Note 4 and Critical Accounting Policies for more details.
Prior to January 31, 2003, the Partnership had no combined operations. In
these circumstances, the Partnership is required to present, discuss and analyze
the financial condition and results of operations of our Partnership for the
three and six month periods ended June 30, 2004 and 2003 by including the
financial condition and results of Dorchester Hugoton, the accounting acquiror,
for the one month period ended January 31, 2003.
2. CONTINGENCIES: In January 2002, some individuals and an association called
Rural Residents for Natural Gas Rights, referred to as RRNGR, sued Dorchester
Hugoton, Ltd., Anadarko Petroleum Corporation, Conoco, Inc., XTO Energy Inc.,
ExxonMobil Corporation, Phillips Petroleum Company, Incorporated and Texaco
Exploration and Production, Inc. Dorchester Minerals Operating LP, owned
directly and indirectly by our general partner, 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 the Partnership. The
suit is currently pending in the District Court of Texas County, Oklahoma and
discovery is underway by the plaintiffs and defendants. The individuals and
RRNGR 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 lease agreements with
defendants in the 1930s to the 1950s. Plaintiffs' claims against defendants
include failure to prudently operate wells, violation of rights to free domestic
gas, violation of irrigation gas contracts, underpayment of royalties, a request
for accounting, and fraud. Plaintiffs also seek certification of class action
against defendants. Dorchester Minerals Operating LP believes plaintiffs' claims
are completely without merit. In July 2002, the defendants were granted a motion
for summary judgment removing RRNGR as a plaintiff. Based upon past measurements
of such gas usage, Dorchester Minerals Operating LP believes the damages sought
by plaintiffs to be minimal. An adverse decision could reduce amounts the
Partnership receives from the Net Profits Interests.
The 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.
PAGE 7
3. COMBINATION TRANSACTION: On January 31, 2003, Dorchester Hugoton
transferred certain assets to Dorchester Minerals Operating LP in exchange for
a net profits interest, contributed the net profits interest and other assets to
the Partnership and subsequently liquidated. Republic and Spinnaker transferred
certain assets to Dorchester Minerals Operating LP in exchange for net profits
interests and subsequently merged with the Partnership. For accounting purposes
Dorchester Hugoton is deemed the acquiror. The value assigned to the assets of
Republic and Spinnaker was based on the market capitalization of Dorchester
Hugoton and the share of the total common units of the Partnership received by
the former partners of Republic (10,953,078 common units) and Spinnaker
(5,342,973 common units). The assets of Republic and Spinnaker were valued at
$237,194,000 which was allocated as follows:
Cash.................................. $ 68,000
Oil and gas properties................ 233,466,000
Receivables........................... 3,660,000
Total................................. $ 237,194,000
The following reflects unaudited pro forma data related to the combination
discussed herein. The unaudited pro forma data assumes the combination had taken
place as of the beginning of each period. The pro forma amounts are not
necessarily indicative of the results that may be reported in the future. Pro
forma adjustments have been made to depletion, depreciation, and amortization to
reflect the new basis of accounting for the assets of Spinnaker and Republic as
of January 31, 2003, and to January 2003 revenues to reflect the revenues of
Dorchester Hugoton as Net Profits Interests.
Three Months Ended Six Months Ended
June 30, June 30,
------------------ -----------------
2003 2003
------------------ -----------------
Revenues $ 11,300,000 $ 27,145,000
Depletion $ 6,672,000 $ 13,394,000
Impairment $ 22,214,000 $ 22,214,000
Net earnings (loss) $ (18,928,000) $ (15,134,000)
Earnings (loss) per common unit $ (0.68) $ (0.54)
Nonrecurring items:
Severance and related costs --- $ 3,003,000
Combination-related costs $ 174,000 $ 670,000
4. IMPAIRMENT OF OIL AND GAS PROPERTIES: During the second quarter 2003, the
Partnership recorded a non-cash charge against earnings of $22,214,000. The
write-down represents an impairment of assets that results primarily from the
difference between the discounted present value of the Partnership's proved
natural gas and oil reserves using June 30, 2003 gas and oil prices as compared
to the book value assigned to former Republic and Spinnaker assets in accordance
with purchase accounting rules which value significantly exceeded historic book
value. The write-down is a function of such increased value and changes in
prevailing oil and gas prices since the consummation of the combination
transaction. Cash flow from operations and cash distributions to unitholders
were not affected by the write-down. See Note 1 and Note 3 and Critical
Accounting Policies.
5. DISTRIBUTION TO HOLDERS OF COMMON UNITS: Since the Partnership's
combination on January 31, 2003, unitholder cash distributions per common unit
have been:
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
The next cash distribution will be paid by November 15, 2004.
PAGE 8
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Overview
Dorchester Minerals, L.P. is a publicly traded Delaware limited partnership
that was formed in December 2001 in connection with the combination, which was
completed on January 31, 2003, of Dorchester Hugoton, which was a publicly
traded Texas limited partnership, and Republic and Spinnaker both of which were
privately held Texas partnerships.
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
interest properties previously owned by Republic and Spinnaker. We refer to
Dorchester Minerals Operating LP by the term "operating partnership". Our
Partnership directly and indirectly holds 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. After the
close of each month, we receive a payment equaling 96.97% of the net proceeds
actually received during that month from the properties subject to the Net
Profits Interests.
In addition to the Net Profits Interests, we also hold producing and non-
producing mineral, royalty, overriding royalty, net profits and leasehold
interests, which we acquired as part of the combination upon the mergers of
Republic and Spinnaker into our Partnership. We refer to these interests as the
Royalty Properties. We currently own Royalty Properties in 563 counties and
parishes in 25 states.
Basis of Presentation
In the combination completed on January 31, 2003 and accounted for as a
purchase, Dorchester Hugoton was designated as the accounting acquiror. Prior to
January 31, 2003, our Partnership had no combined operations. In these
circumstances, we are required to present, discuss and analyze the financial
condition and results of operations of our Partnership for the three and six
month periods ended June 30, 2004 and 2003 by including the financial condition
and results of Dorchester Hugoton, the accounting acquiror, for the one month
period ended January 31, 2003. For the purposes of this presentation, the term
combination means the transactions consummated in connection with the
combination of the business and properties of Dorchester Hugoton, Republic and
Spinnaker.
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 Six Months Ended June 30, 2004 as compared to Three and Six Months
Ended June 30, 2003
Normally, our period-to-period changes in net earnings and cash flows from
operating activities are principally determined by changes in natural gas and
crude oil sales volumes and prices. Our portion of gas and oil sales and
weighted average prices were:
Three Months Ended Six Months Ended
-------------------- ----------------
March
June 30, 31, June 30,
------------ ------ ------- ------
Accrual Basis Sales Volumes: 2004 2003 2004 2004 2003
----- ----- ------ ------- ------
Dorchester Hugoton Gas Sales (mmcf)(1) -- -- -- -- 448
Net Profits Interests Gas Sales(mmcf) 1,352 1,261 1,347 2,699 2,147
Net Profits Interests Oil Sales (mbbls) 2 1 2 4 3
Royalty Props. Gas Sales(mmcf) 822 817 888 1,710 1,475
Royalty Props. Oil Sales (mbbls 67 84 80 147 141
Weighted Average Sales Price:
Dorchester Hugoton Gas Sales ($/mcf) -- -- -- -- $ 5.20
Net Profits Interests Gas Sales($/mcf) $ 5.81 $ 5.51 $ 5.46 $ 5.64 5.97
Net Profits Interests Oil Sales ($/bbl) $35.25 $22.99 $30.15 $32.28 $29.20
Royalty Properties Gas Sales ($/mcf) $ 5.28 $ 4.62 $ 5.05 $ 5.16 $ 5.68
Royalty Properties Oil Sales ($/bbl) $36.90 $25.29 $31.96 $34.21 $28.79
Production Costs Deducted Under
the Net Profits Interests ($/mcfe)(2) $ 1.23 $ 1.33 $ 1.09 $ 1.16 $ 1.27
______________________________________
(1) For purposes of comparison the January 2003 Dorchester Hugoton volumes have
been reduced to reflect our 96.97% Net Profits Interest in production from
the underlying properties.
(2) Provided to assist in determination of revenues; applies only to Net
Profits Interests sales volumes and prices.
PAGE 9
Oil sales volumes attributable to our Royalty Properties during the second
quarter decreased 20% from 84,000 bbls during 2003 to 67,000 bbls during 2004 as
a result of our receipt of retroactive volume adjustments in the second quarter
of 2003. Gas sales volumes attributable to our Royalty Properties during the
second quarter increased less than 1% from 817 mmcf during 2003 to 822 mmcf
during 2004.
Oil sales volumes attributable to our Net Profits Interests during the
second quarter increased 100% from 1,000 bbls during 2003 to 2,000 bbls during
2004 due to activity on the Net Profits Interest properties. Gas sales volumes
attributable to our Net Profits Interests during the second quarter increased 7%
from 1,261 mmcf during 2003 to 1,352 mmcf during 2004 due to increased
production resulting from additional field compression on the Oklahoma
properties previously owned by Dorchester Hugoton and new activity on the Net
Profits Interest properties. Such increases help offset declines in existing
wells and reservoirs.
Weighted average oil sales prices attributable to the Partnership's
interest in Royalty Properties increased 46% from $25.29 per bbl during the
second quarter 2003 to $36.90 per bbl during the second quarter 2004. Similarly,
second quarter weighted average Partnership natural gas sales prices from
Royalty Properties increased 14% from $4.62 per mcf during 2003 to $5.28 per mcf
during 2004. Both oil and gas price increases resulted from changing market
conditions.
Second quarter weighted average oil sales prices from the Net Profits
Interests' properties increased 53% from $22.99 per bbl in 2003 to $35.25 per
bbl in 2004. Second quarter weighted average natural gas sales prices from the
Net Profits Interests' properties increased 5% from $5.51 per mcf in 2003 to
$5.81 per mcf in 2004. Such oil and gas price increases are due to changing
market conditions.
Oil and natural gas sales volumes attributable to the Royalty Properties
and oil and natural gas sales volumes attributable to the Net Profits Interests
from Republic and Spinnaker are included in our results for the six month period
ended June 30, 2004 and are included for only the five months ended June 30,
2003. See "Basis of Presentation" and Note 1 of the Notes to the Condensed
Financial Statements.
Weighted average prices for oil and natural gas sales volumes attributable
to the Royalty Properties and also to the Net Profits Interests from Republic
and Spinnaker are included in our results for the six months ended June 30, 2004
and are included for only the five months ended June 30, 2003. See "Basis of
Presentation" and Note 1 of the Notes to the Condensed Financial Statements.
Our second quarter net operating revenues increased 18% from $11,300,000
during 2003 to $13,380,000 during 2004 due primarily to increased natural gas
prices and crude oil prices. Comparing the first six month periods, net
operating revenue rose 6% from $25,256,000 during 2003 to $26,821,000 during
2004, primarily as a result of improvement of natural gas and crude oil prices.
Management cautions the reader in the comparison of results for the six month
periods because operations attributable to properties formerly owned by Republic
and Spinnaker are not included for January in the six-month period ending
June 30, 2003. See "Basis of Presentation" and Note 1of the Notes to the
Condensed Financial Statements.
Costs and expenses during the second quarter of 2004 decreased 79% from
$30,280,000 during the second quarter of 2003 to $6,267,000. Similarly, costs
and expenses during the six months ended June 30, 2004 of $12,993,000 were 68%
lower than costs in the six months ended June 30, 2003 of $40,371,000. Such
decrease in costs is primarily due to a second quarter 2003 non-cash charge
against earnings of $22,214,000 representing an impairment of assets during
2003. See Note 4 of the Notes to the Condensed Financial Statements.
Several categories of costs during the first six months of 2004 were lower
than the first six months of 2003 due to non-recurring expenses associated with
the 2003 liquidation of Dorchester Hugoton. Such 2003 costs are mostly
combination and related expenses of $2,907,000, consisting primarily of
$2,500,000 in severance payments and related costs. Similarly management fees in
2003 include a one-time $496,000 charge.
Other income during the three and six month period ended June 30 increased
from $52,000 and $130,000, respectively, during 2003 to $195,000 and $131,000,
respectively, during the same periods in 2004. We received partial payment of a
legal judgment in the amount $76,000 and accrued an additional $108,100
attributable to the same matter during June 2004. The first six months of 2004
include expenses of $87,000 attributable to unsuccessful property acquisition
attempts in the first quarter. Note that lease bonus revenue is included in
Other net operating revenue and is not reflected as Other income.
Depletion, depreciation and amortization during the three and six month
period ended June 30 decreased from $6,672,000 and $11,643,000, respectively,
during 2003 to $5,022,000 and $10,323,000, respectively, during 2004, primarily
as a result of a reduced depletable asset base, mainly due to impairments and
prior quarterly
PAGE 10
depletion. Management cautions the reader in the comparison of results for these
periods, because operations of the properties formerly owned by Republic and
Spinnaker are not included for January in the six-month period ending
June 30, 2003 and due to the application of purchase accounting methods. See
"Basis of Presentation", "Critical Accounting Policies", and Notes 1, 3 and 4 of
the Notes to the Condensed Financial Statements.
We received cash payments in the amount of $391,000 from various sources
during the first quarter of 2004 including lease bonus attributable to 15 leases
and pooling elections located in seven counties and parishes in three states.
Each of these leases reflected royalty terms of 25% and lease bonuses ranging up
to $300/acre. Twelve of these leases included a commitment to drill an
exploratory well on lands in which we own an interest or lands pooled therewith,
and in the event subsequent wells are drilled on such lands, we retain the right
for the operating partnership to participate in each such well with as much as
50% of our original interest subject to our reservation of a 96.97% Net Profits
Interest.
We received division orders for, or otherwise identified 43 new wells
completed on our Royalty Properties and Net Profits Interests in 23 counties and
parishes in eight states during the second quarter of 2004. Selected new wells
and the royalty interests owned therein by us and the working interests and net
revenue interests owned therein by the operating partnership are summarized in
the following table:
Test Rates
per day
------------
Ownership
County/ ------------ Gas Oil
State Parish Operator Well Name WI(1) NRI(1) mcf bbls
- ------ --------- --------- ----------------- ----- ----- ------ ------
Royalty Properties
- ---------------------
Arkansas Sebastian Hanna KMW #2 -- 0.6% 11,900 -
Louisiana Bienville Will-Drill La. Minerals 9-1 -- 1.4% 1,225 30
Texas Winkler Crownquest Keystone Cattle 444 -- 1.2% 165 43
Net Profits Interests
- ---------------------
Oklahoma Washita Cimarex Green 5-2 BPO(2) 7.0% 8.8% 3,077 183
Green 5-2 APO(2) 8.8% 9.4%
Oklahoma Washita Cimarex Sullivan 6-2 BPO(2) 7.0% 8.8% 3,198 200
Sullivan 6-2 APO(2) 8.8% 9.4%
____________________________________
(1) WI and NRI mean working interest and net revenue interest, respectively.
(2) BPO and APO mean before payout and after payout, respectively.
Second quarter net earnings allocable to common units increased from a
$18,449,000 loss during 2003 to $7,128,000 during 2004, due primarily to
increased natural gas and crude oil sales prices and due to the non-cash charge
against earnings during 2003. Generally for the same reasons, net earnings
during the first six months of 2004 were $13,613,000 compared to a $14,637,000
loss in the same period in 2003.
Net cash provided by operating activities decreased 9% from $12,912,000
during the second quarter 2003 to $11,741,000 during the second quarter 2004,
principally due to timing of collection of accounts receivable offset by
improved oil and natural gas sales prices. Net cash provided by operating
activities increased 44% from $16,286,000 during the six months ended June 30,
2003 to $23,518,000 during the six months ended June 30, 2004 as a result of the
combination. Management cautions the reader in the comparison of results for the
six month periods because operations of the properties formerly owned by
Republic and Spinnaker are not included for January in the six-month period
ending June 30, 2003. See "Basis of Presentation" and Notes 1 and 3 of the Notes
to the Condensed Financial Statements.
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 gas production and
property taxes not otherwise deducted from gross production revenues and general
and administrative expenses incurred on our behalf and properly 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 5 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
PAGE 11
availability of capital resources. We have not guaranteed the debt of any other
party, nor do we have any other arrangements or relationships with other
entities that could potentially result in unconsolidated debt.
Pursuant to the terms of our Partnership Agreement, we cannot incur
indebtedness other than trade payables, (i) in excess of $50,000 in the
aggregate at any given time or (ii) which would constitute "acquisition
indebtedness" (as defined in Section 514 of the Internal Revenue Code of 1986,
as amended).
Expenses and Capital Expenditures
The operating partnership does not currently anticipate drilling additional
wells as a working interest owner in the Fort Riley zone or the Council Grove
formation or elsewhere in the Oklahoma properties previously owned by Dorchester
Hugoton. Successful activities by others in these formations or other
developments could prompt a reevaluation of this position. Any such drilling is
estimated to cost $250,000 to $300,000 per well. Such activities by the
operating partnership could influence the amount we receive from the Net Profits
Interests. The operating partnership anticipates continuing additional fracture
treating in the Oklahoma properties previously owned by Dorchester Hugoton.
During the second quarter of 2004 one well was fracture treated at a cost of
$47,000. The well increased production from 89 to 139 mcf per day.
The operating partnership owns and operates the wells, pipelines and gas
compression and dehydration facilities located in Kansas and Oklahoma previously
owned by Dorchester Hugoton. 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. Both
infill drilling and removal of production limits could require considerable
capital expenditures. The outcome and the cost of such activities are
unpredictable. Such activities by the operating partnership could influence the
amount we receive from the Net Profits Interests. No additional compression
affecting the wells formerly owned by Dorchester Hugoton has been installed
since 2000 by operators on adjoining acreage. The operating partnership believes
it now has sufficient field compression to remain competitive with adjoining
operators for the foreseeable future.
Liquidity and Working Capital
Cash and cash equivalents totaled $11,901,000 at June 30, 2004 and
$10,881,000 at December 31, 2003.
CRITICAL ACCOUNTING POLICIES
We utilize the full cost method of accounting for costs related to our oil
and gas properties. Under this method, all such costs (productive and
nonproductive) 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 gas reserves discounted at 10% plus the lower of
cost or market value of unproved properties. In accordance with applicable
accounting rules, Dorchester Hugoton was deemed to be the accounting acquiror of
the Republic and Spinnaker assets. Our Partnership's acquisition of these assets
was recorded at a value based on the closing price of Dorchester Hugoton's
common units immediately prior to consummation of the combination transaction,
subject to certain adjustments. Consequently, the acquisition of these assets
was recorded at values that exceed the historical book value of these assets
prior to consummation of the combination transaction. Our Partnership did not
assign any book or market value to unproved properties, including nonproducing
royalty, mineral and leasehold interests. The full cost ceiling is evaluated at
the end of each quarter. For 2003, our unamortized costs of oil and gas
properties exceeded the ceiling test. As a result, in 2003, our Partnership
recorded full cost write-downs of $43,804,000. No additional impairments have
been recorded since the quarter ended September 30, 2003.
The discounted present value of our proved oil and 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
PAGE 12
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 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 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.
NEW ACCOUNTING STANDARDS
In July 2001, the Financial Accounting Standards Board issued SFAS No. 143,
"Accounting for Asset Retirement Obligations". SFAS No. 143 requires entities to
record the fair value of a liability for an asset retirement obligation in the
period in which it is incurred. SFAS No. 143 is effective for fiscal years
beginning after June 15, 2002. We adopted SFAS No. 143 on January 1, 2003, which
did not have a material effect on our financial statements.
The FASB's Emerging Issues Task Force (EITF) reached a consensus that
mineral rights are tangible assets in EITF Issue 04-2, "Whether Mineral Assets
Are Tangible or Intangible Assets". The FASB ratified the EITF consensus,
subject to amendment of SFAS No. 141 and No. 142 through a FASB Staff Position
(FSP). Therefore, no changes would be required in the way the Partnership
classifies its mineral rights.
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 Partnership's
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 Partnership's disclosure
controls and procedures effectively ensure that the information required to be
disclosed in the reports the Partnership files with the Securities and Exchange
Commission is recorded, processed, summarized and reported, within the time
periods specified by the Securities and Exchange Commission.
PAGE 13
Changes in Internal Controls
There were no changes in our Partnership's internal controls or in other
factors that have materially affected, or are reasonably likely to materially
affect, our Partnership's internal controls subsequent to the date of their
evaluation of our disclosure controls and procedures.
PART II
Item 1. LEGAL PROCEEDINGS
None.
Item 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
None.
Item 3. DEFAULTS UPON SENIOR SECURITIES
None.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
a) We held our Annual Unitholders meeting on Wednesday, May 5, 2004
in Dallas, Texas.
b) Proxies were solicited by the Board of Managers pursuant to Regulation
14A under the Securities Exchange Act of 1934. There were no
solicitations in opposition to the nominees listed in the proxy
statement and all of such nominees were duly elected.
c) The only matter voted on at the meeting was the election of the three
nominees to the Board of Managers. Out of the 27,040,431 units issued
and outstanding and entitled to vote at the meeting, 25,055,367
units were present in person or by proxy. The results were as follows:
Votes Withheld
Nominee Votes for Election from Election Broker Non-Votes
Buford P. Berry 24,757,336 298,031 1,985,064
Rawles Fulgham 24,931,147 124,220 1,985,064
C. W. Russell 24,978,477 76,890 1,985,064
Item 5. OTHER INFORMATION
We have entered into indemnity agreements with our managers and executive
officers and certain other key employees that provide the maximum indemnity
allowed to by Section 108 of the Delaware Revised Uniform Limited Partnership
Act, as well as certain additional procedural protections. The indemnity
agreements provide that managers will be indemnified to the fullest extent not
prohibited by law against all expenses (including attorney's fees) and
settlement amounts paid or incurred by them in any action or proceeding as our
managers or executive officers, including any action on account of their
services as executive officers or managers of any other company or enterprise
when they are serving in such capacities at our request, and including any
action by us or in our right. In addition, the indemnity agreements provide for
reimbursement of expenses incurred in conjunction with being a witness in any
proceeding to which the indemnitee is not a party. We must pay in advance of a
final disposition of a proceeding or claim the expenses incurred by the
indemnitee no later than 10 days after our receipt of an undertaking by or on
behalf of the indemnitee, and the indemnitee is to repay the amount of the
expenses to the extent that it is ultimately determined that the indemnitee is
not entitled to be indemnified by us. The indemnity agreements also provide the
indemnitee with remedies in the event that we do not fulfill our obligations
under the indemnity agreements.
Item 6. EXHIBITS AND REPORTS ON FORM 8-K
a) Exhibits: See the attached Index to Exhibits.
b) Reports on Form 8-K filed during the quarter ended June 30, 2004:
(i) Filed April 16, 2004 on Item 9. Regulation FD Disclosure
(Regarding Slide Presentation)
(ii) Filed April 20, 2004 on Item 9. FD Disclosure and Item 12.
Results of Operations and Financial Condition (Regarding First
Quarter Cash Distribution)
(iii) Filed May 5, 2004 on Item 9. Regulation FD Disclosure and
Item 12. Results of Operations and Financial Condition
(Regarding First Quarter Earnings)
PAGE 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: August 4, 2004 Chief Executive Officer
/s/ H.C. Allen, Jr.
------------------------------------------------
H.C. Allen, Jr.
Date: August 4, 2004 Chief Financial Officer
PAGE 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)
10.1 Form of Indemnity Agreement
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
PAGE 16