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FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
(Mark One)
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2004
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ________________ to ________________
Commission file number 0-15411
Southwest Royalties, Inc. Income Fund VI, L.P.
(Exact name of registrant as specified
in its limited partnership agreement)
Tennessee 75-2127812
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
407 N. Big Spring, Suite 300
Midland, Texas 79701
(Address of principal executive offices)
(432) 686-9927
(Registrant's telephone number,
including area code)
Indicate by check mark whether 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 an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes No X
The registrant's outstanding securities consist of Units of limited
partnership interests for which there exists no established public market
from which to base a calculation of aggregate market value.
The total number of pages contained in this report is 24.
Glossary of Oil and Gas Terms
The following are abbreviations and definitions of terms commonly used in
the oil and gas industry that are used in this filing. All volumes of
natural gas referred to herein are stated at the legal pressure base to the
state or area where the reserves exit and at 60 degrees Fahrenheit and in
most instances are rounded to the nearest major multiple.
Bbl. One stock tank barrel, or 42 United States gallons liquid volume.
Developmental well. A well drilled within the proved area of an oil or
natural gas reservoir to the depth of a stratigraphic horizon known to be
productive.
Exploratory well. A well drilled to find and produce oil or gas in an
unproved area to find a new reservoir in a field previously found to be
productive of oil or natural gas in another reservoir or to extend a known
reservoir.
Farm-out arrangement. An agreement whereby the owner of the leasehold
or working interest agrees to assign his interest in certain specific
acreage to the assignee, retaining some interest, such as an overriding
royalty interest, subject to the drilling of one (1) or more wells or other
performance by the assignee.
Field. An area consisting of a single reservoir or multiple reservoirs
all grouped on or related to the same individual geological structural
feature and/or stratigraphic condition.
Mcf. One thousand cubic feet.
Net Profits Interest. An agreement whereby the owner receives a
specified percentage of the defined net profits from a producing property
in exchange for consideration paid. The net profits interest owner will
not otherwise participate in additional costs and expenses of the property.
Oil. Crude oil, condensate and natural gas liquids.
Overriding royalty interest. Interests that are carved out of a
working interest, and their duration is limited by the term of the lease
under which they are created.
Present value and PV-10 Value. When used with respect to oil and
natural gas reserves, the estimated future net revenue to be generated from
the production of proved reserves, determined in all material respects in
accordance with the rules and regulations of the SEC (generally using
prices and costs in effect as of the date indicated) without giving effect
to non-property related expenses such as general and administrative
expenses, debt service and future income tax expenses or to depreciation,
depletion and amortization, discounted using an annual discount rate of
10%.
Production costs. Costs incurred to operate and maintain wells and
related equipment and facilities, including depreciation and applicable
operating costs of support equipment and facilities and other costs of
operating and maintaining those wells and related equipment and facilities.
Proved Area. The part of a property to which proved reserves have been
specifically attributed.
Proved developed oil and gas reserves. Proved developed oil and gas
reserves are reserves that can be expected to be recovered from existing
wells with existing equipment and operating methods.
Proved properties. Properties with proved reserves.
Proved reserves. The estimated quantities of crude oil, natural gas,
and natural gas liquids that geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions.
Proved undeveloped reserves. Proved undeveloped oil and gas reserves
are reserves that are expected to be recovered from new wells on undrilled
acreage, or from existing wells where a relatively major expenditure is
required for recompletion.
Reservoir. A porous and permeable underground formation containing a
natural accumulation of producible oil or gas that is confined by
impermeable rock or water barriers and is individual and separate from
other reservoirs.
Royalty interest. An interest in an oil and natural gas property
entitling the owner to a share of oil or natural gas production free of
costs of production.
Working interest. The operating interest that gives the owner the
right to drill, produce and conduct operating activities on the property
and a share of production.
Workover. Operations on a producing well to restore or increase
production.
PART I. - FINANCIAL INFORMATION
Item 1. Financial Statements
The unaudited condensed financial statements included herein have been
prepared by the Registrant (herein also referred to as the "Partnership")
in accordance with generally accepted accounting principles for interim
financial information and with the instructions to Form 10-Q and Rule 10-01
of Regulation S-X. Accordingly, they do not include all of the information
and footnotes required by generally accepted accounting principles for
complete financial statements. In the opinion of management, all
adjustments necessary for a fair presentation have been included and are of
a normal recurring nature. The financial statements should be read in
conjunction with the audited financial statements and the notes thereto for
the year ended December 31, 2003, which are found in the Registrant's Form
10-K Report for 2003 filed with the Securities and Exchange Commission.
The December 31, 2003 balance sheet included herein has been taken from the
Registrant's 2003 Form 10-K Report. Operating results for the three and
six month periods ended June 30, 2004 are not necessarily indicative of the
results that may be expected for the full year.
Southwest Royalties, Inc. Income Fund VI
Balance Sheets
June 30, December
31,
2004 2003
------ ------
(unaudit
ed)
Assets
- ---------
Current assets:
Cash and cash equivalents $ 171,796 234,954
Receivable from Managing General 290,704 189,477
Partner
Oklahoma withholding prepayment 124 124
-------- --------
---- -----
Total current assets 462,624 424,555
-------- --------
---- -----
Oil and gas properties - using the
full-
cost method of accounting 8,547,31 8,547,31
7 7
Less accumulated depreciation,
depletion and amortization 6,199,46 6,143,46
0 0
-------- --------
---- -----
Net oil and gas properties 2,347,85 2,403,85
7 7
-------- --------
---- -----
$ 2,810,48 2,828,41
1 2
======= =======
Liabilities and Partners' Equity
- -------------------------------------
- ---
Asset retirement obligation $ 533,936 513,400
-------- --------
---- -----
Partners' equity:
General partner (626,676 (622,829
) )
Limited partners 2,903,22 2,937,84
1 1
-------- --------
---- -----
Total partners' equity 2,276,54 2,315,01
5 2
-------- --------
---- -----
$ 2,810,48 2,828,41
1 2
======= =======
Southwest Royalties, Inc. Income Fund VI
Statements of Operations
(unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2004 2003 2004 2003
----- ----- ----- -----
Revenues
- -------------
Income from net profits $ 314,554 331,408 695,779 628,687
interests
Interest 463 373 925 391
Other - - 250 -
-------- -------- --------- ---------
-- -- - -
315,017 331,781 696,954 629,078
-------- -------- --------- ---------
-- -- - -
Expenses
- ------------
General and administrative 43,602 49,424 83,886 86,900
Depreciation, depletion and 29,000 38,000 56,000 66,000
amortization
Accretion of asset 10,268 9,997 20,535 19,993
retirement obligation
-------- -------- --------- ---------
-- -- - -
82,870 97,421 160,421 172,893
-------- -------- --------- ---------
-- -- - -
Net income before cumulative 232,147 234,360 536,533 456,185
effect
Cumulative effect of change
in accounting
principle - SFAS No. 143 - - - - 116,637
See Note 3
-------- -------- --------- ---------
-- -- - -
Net income $ 232,147 234,360 536,533 572,822
====== ====== ====== ======
Net income allocated to:
Managing General Partner $ 23,215 23,436 53,653 57,282
====== ====== ====== ======
Limited Partners $ 208,932 210,924 482,880 515,540
====== ====== ====== ======
Per limited partner unit $ 10.45
before cumulative effect 10.55 24.14 20.53
Cumulative effects per - - - 5.25
limited partner unit
-------- -------- --------- ---------
-- -- - -
Per limited partner unit $ 10.45
10.55 24.14 25.78
====== ====== ====== ======
Southwest Royalties, Inc. Income Fund VI
Statements of Cash Flows
(unaudited)
Six Months Ended
June 30,
2004 2003
---- ----
Cash flows from operating
activities:
Cash received from income from
net
profits interests $ 561,151 407,687
Cash paid to suppliers (50,484) (40,551)
Interest received 925 391
Other 250 -
-------- --------
-- --
Net cash provided by operating 511,842 367,527
activities
-------- --------
-- --
Cash flows provided by investing
activities:
Sale of oil and gas properties - 306
-------- --------
-- --
Cash flows used in financing
activities:
Distributions to partners (575,000 (253,561
) )
-------- --------
-- --
Net (decrease) increase in cash (63,158) 114,272
and cash equivalents
Beginning of period 234,954 18,015
-------- --------
-- --
End of period $ 171,796 132,287
====== ======
Reconciliation of net income to
net
cash provided by operating
activities:
Net income $ 536,533 572,822
Adjustments to reconcile net
income to
net cash provided by operating
activities:
Depreciation, depletion and 56,000 66,000
amortization
Accretion of asset retirement 20,535 19,993
obligation
Cumulative effect of change in
accounting
principle - SFAS No. 143 - (116,637
)
Increase in receivables (134,628 (221,000
) )
Increase in payables 33,402 46,349
-------- --------
-- --
Net cash provided by operating $ 511,842 367,527
activities
====== ======
Non cash investing and financing
activities::
Increase in oil and gas
properties - Adoption
of SFAS No. 143 $ - 616,464
====== ======
Southwest Royalties, Inc. Income Fund VI
(a Tennessee limited partnership)
Notes to Financial Statements
1. Organization
Southwest Royalties, Inc. Income Fund VI was organized under the
laws of the state of Tennessee on December 4, 1986, for the purpose of
acquiring producing oil and gas properties and to produce and market
crude oil and natural gas produced from such properties for a term of
50 years, unless terminated at an earlier date as provided for in the
Partnership Agreement. The Partnership sells its oil and gas
production to a variety of purchasers with the prices it receives being
dependent upon the oil and gas economy. Southwest Royalties, Inc. a
wholly-owned subsidiary of Clayton Williams Energy, Inc., serves as the
Managing General Partner. Revenues, costs and expenses are allocated
as follows:
Limited General
Partners Partners
-------- --------
Interest income on capital 100% -
contributions
Oil and gas sales 90% 10%
All other revenues 90% 10%
Organization and offering 100% -
costs (1)
Amortization of organization 100% -
costs
Property acquisition costs 100% -
Gain/loss on property 90% 10%
disposition
Operating and administrative 90% 10%
costs (2)
Depreciation, depletion and
amortization
of oil and gas properties 90% 10%
All other costs 90% 10%
(1)All organization costs in excess of 3% of initial capital
contributions will be paid by the Managing General Partner and
will be treated as a capital contribution. The Partnership paid
the Managing General Partner an amount equal to 3% of initial
capital contributions for such organization costs.
(2)Administrative costs in any year which exceed 2% of capital
contributions shall be paid by the Managing General Partner and
will be treated as a capital contribution.
2. Summary of Significant Accounting Policies
The interim financial information as of June 30, 2004, and for the
three and six months ended June 30, 2004, is unaudited. Certain
information and footnote disclosures normally included in financial
statements prepared in accordance with generally accepted accounting
principles have been condensed or omitted in this Form 10-Q pursuant
to the rules and regulations of the Securities and Exchange
Commission. However, in the opinion of management, these interim
financial statements include all the necessary adjustments to fairly
present the results of the interim periods and all such adjustments
are of a normal recurring nature. The interim consolidated financial
statements should be read in conjunction with the Partnership's Annual
Report on Form 10-K for the year ended December 31, 2003.
3. Cumulative effect of change in accounting principle - SFAS No. 143
On January 1, 2003, the Partnership adopted Statement of Financial
Accounting Standards No. 143, Accounting for Asset Retirement
Obligations ("SFAS No. 143"). Adoption of SFAS No. 143 is required
for all companies with fiscal years beginning after June 15, 2002.
The new standard requires the Partnership to recognize a liability for
the present value of all legal obligations associated with the
retirement of tangible long-lived assets and to capitalize an equal
amount as a cost of the asset and depreciate the additional cost over
the estimated useful life of the asset. On January 1, 2003, the
Partnership recorded additional costs, net of accumulated
depreciation, of approximately $616,464, a long term liability of
approximately $499,827 and a gain of approximately $116,637 for the
cumulative effect on depreciation of the additional costs and
accretion expense on the liability related to expected abandonment
costs of its oil and natural gas producing properties. At June 30,
2004, the asset retirement obligation was $533,936. The increase in
the asset retirement obligation from January 1, 2004 is due to
accretion expense of $20,535.
Southwest Royalties, Inc. Income Fund VI
(a Tennessee limited partnership)
Notes to Financial Statements
4. Change in Control of Managing General Partner
On May 21, 2004, Clayton Williams Energy, Inc. acquired all the
outstanding common stock of Southwest Royalties Inc. through a merger.
Clayton Williams Energy, Inc. paid $57.1 million to holders of
Southwest Royalties, Inc. common stock and common stock warrants
($45.01 per share) and assumed and refinanced approximately
$113.9 million of assumed bank debt at closing.
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
General
Southwest Royalties, Inc. Income Fund VI was organized as a Tennessee
limited partnership on December 4, 1986. The offering of such limited
partnership interests began August 25, 1986 minimum capital requirements
were met October 3, 1986 and concluded January 29, 1987, with total limited
partner contributions of $10,000,000.
The Partnership was formed to acquire royalty and net profits interests in
producing oil and gas properties, to produce and market crude oil and
natural gas produced from such properties, and to distribute the net
proceeds from operations to the limited and general partners. Net revenues
from producing oil and gas properties will not be reinvested in other
revenue producing assets except to the extent that production facilities
and wells are improved or reworked or where methods are employed to improve
or enable more efficient recovery of oil and gas reserves. The economic
life of the partnership thus depends on the period over which the
Partnership's oil and gas reserves are economically recoverable.
Increases or decreases in Partnership revenues and, therefore,
distributions to partners will depend primarily on changes in the prices
received for production, changes in volumes of production sold, lease
operating expenses, enhanced recovery projects, offset drilling activities
pursuant to farm-out arrangements, sales of properties, and the depletion
of wells. Since wells deplete over time, production can generally be
expected to decline from year to year.
Well operating costs and general and administrative costs usually decrease
with production declines; however, these costs may not decrease
proportionately. Net income available for distribution to the partners is
therefore expected to fluctuate in later years based on these factors.
Oil and Gas Properties
Oil and gas properties are accounted for at cost under the full-cost
method. Under this method, all productive and nonproductive costs incurred
in connection with the acquisition, exploration and development of oil and
gas reserves are capitalized. Gain or loss on the sale of oil and gas
properties is not recognized unless significant oil and gas reserves are
sold.
Should the net capitalized costs exceed the estimated present value of oil
and gas reserves, discounted at 10%, such excess costs would be charged to
current expense. As of June 30, 2004, the net capitalized costs did not
exceed the estimated present value of oil and gas reserves.
The Partnership's interest in oil and gas properties consists of net
profits interests in proved properties located within the continental
United States. A net profits interest is created when the owner of a
working interest in a property enters into an arrangement providing that
the net profits interest owner will receive a stated percentage of the net
profit from the property. The net profits interest owner will not
otherwise participate in additional costs and expenses of the property.
The Partnership recognizes income from its net profits interest in oil and
gas property on an accrual basis, while the quarterly cash distributions of
the net profits interest are based on a calculation of actual cash received
from oil and gas sales, net of expenses incurred during that quarterly
period. If the net profits interest calculation results in expenses
incurred exceeding the oil and gas income received during a quarter, no
cash distribution is due to the Partnership's net profits interest until
the deficit is recovered from future net profits. The Partnership accrues
a quarterly loss on its net profits interest provided there is a cumulative
net amount due for accrued revenue as of the balance sheet date. As of
June 30, 2004, there were no timing differences, which resulted in a
deficit net profit interest.
Critical Accounting Policies
The Partnership follows the full cost method of accounting for its oil and
gas properties. The full cost method subjects companies to quarterly
calculations of a "ceiling", or limitation on the amount of properties that
can be capitalized on the balance sheet. If the Partnership's capitalized
costs are in excess of the calculated ceiling, the excess must be written
off as an expense.
The Partnership's discounted present value of its proved oil and natural
gas reserves is a major component of the ceiling calculation, and
represents the component that requires the most subjective judgments.
Estimates of reserves are forecasts based on engineering data, projected
future rates of production and the timing of future expenditures. The
process of estimating oil and natural gas reserves requires substantial
judgment, resulting in imprecise determinations, particularly for new
discoveries. Different reserve engineers may make different estimates of
reserve quantities based on the same data. The Partnership's reserve
estimates are prepared by outside consultants. Quarterly reserve estimates
are prepared by the Managing General Partner's internal staff of engineers.
The passage of time provides more qualitative information regarding
estimates of reserves, and revisions are made to prior estimates to reflect
updated information. However, there can be no assurance that more
significant revisions will not be necessary in the future. If future
significant revisions are necessary that reduce previously estimated
reserve quantities, it could result in a full cost property writedown. In
addition to the impact of these estimates of proved reserves on calculation
of the ceiling, estimates of proved reserves are also a significant
component of the calculation of DD&A.
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 the reserves do not require judgment. The
ceiling calculation dictates that prices and costs in effect as of the last
day of the period are generally held constant indefinitely. Because the
ceiling calculation dictates that prices in effect as of the last day of
the applicable quarter are held constant indefinitely, the resulting value
is not indicative of the true fair value of the reserves. Oil and natural
gas prices have historically been cyclical and, on any particular day at
the end of a quarter, can be either substantially higher or lower than the
Partnership's long-term price forecast that is a barometer for true fair
value.
Results of Operations
A. General Comparison of the Quarters Ended June 30, 2004 and 2003
The following table provides certain information regarding performance
factors for the quarters ended June 30, 2004 and 2003:
Three Months
Ended Percenta
ge
June 30, Increase
2004 2003 (Decreas
e)
----- ----- --------
--
Average price per barrel of oil $ 37.24 31%
28.48
Average price per mcf of gas $ 5.77 17%
4.93
Oil production in barrels 4,870 6,400 (24%)
Gas production in mcf 67,325 74,800 (10%)
Income from net profits interests $ 314,554 331,408 (5%)
Partnership distributions $ 250,000 250,000 -
Limited partner distributions $ 225,000 225,000 -
Per unit distribution to limited
partners $ 11.25 -
11.25
Number of limited partner units 20,000 20,000
Revenues
The Partnership's income from net profits interests decreased to $314,554
from $331,408 for the quarters ended June 30, 2004 and 2003, respectively,
a decrease of 5%. The principal factors affecting the comparison of the
quarters ended June 30, 2004 and 2003 are as follows:
1. The average price for a barrel of oil received by the Partnership
increased during the quarter ended June 30, 2004 as compared to the
quarter ended June 30, 2003 by 31%, or $8.76 per barrel, resulting in
an increase of approximately $42,700 in income from net profits
interests. Oil sales represented 32% of total oil and gas sales during
the quarter ended June 30, 2004 as compared to 33% during the quarter
ended June 30, 2003.
The average price for an mcf of gas received by the Partnership
increased during the same period by 17%, or $.84 per mcf, resulting in
an increase of approximately $56,600 in income from net profits
interests.
The total increase in income from net profits interests due to the
change in prices received from oil and gas production is approximately
$99,300. The market price for oil and gas has been extremely volatile
over the past decade, and management expects a certain amount of
volatility to continue in the foreseeable future.
2. Oil production decreased approximately 1,530 barrels or 24% during the
quarter ended June 30, 2004 as compared to the quarter ended June 30,
2003, resulting in a decrease of approximately $43,600 in income from
net profits interests.
Gas production decreased approximately 7,475 mcf or 10% during the same
period, resulting in a decrease of approximately $36,900 in income from
net profits interests.
The total decrease in income from net profits interests due to the
change in production is approximately $80,500. Oil and gas volumes
were down due to the sale of two producing properties in 2003. Steep
production declines contributed to the decline in oil volumes.
3. Lease operating costs and production taxes were 16% higher, or
approximately $35,500 more during the quarter ended June 30, 2004 as
compared to the quarter ended June 30, 2003. The increase in lease
operating costs is the result of adding artificial lift equipment to
one well and the recompletion of another well.
Costs and Expenses
Total costs and expenses decreased to $82,870 from $97,421 for the quarters
ended June 30, 2004 and 2003, respectively, a decrease of 15%. The
decrease is the result of lower general and administrative expense and
depletion expense, partially offset by an increase in accretion expense.
1. General and administrative costs consists of independent accounting,
legal and engineering fees, computer services, postage, and Managing
General Partner personnel costs. General and administrative costs
decreased 12% or approximately $5,800 during the quarter ended June 30,
2004 as compared to the quarter ended June 30, 2003. The higher
general and administrative expense in 2003 is due to legal fees
associated with the amendments to the Partnership's December 31, 2002
Annual Report on Form 10-K and March 31, 2003 Quarterly Report on Form
10-Q.
2. Depletion expense decreased to $29,000 for the quarter ended June 30,
2004 from $38,000 for the same period in 2003. This represents a
decrease of 24%. The contributing factor to the decrease in depletion
expense is in relation to the BOE depletion rate for the quarter ended
June 30, 2004, which was $1.80 applied to 16,091 BOE as compared to
$2.01 applied to 18,867 BOE for the same period in 2003.
3. Accretion expense increased to $10,268 for the quarter ended June 30,
2004 from $9,997 for the same period in 2003. This represents an
increase of 3%.
B. General Comparison of the Six Month Periods Ended June 30, 2004 and
2003
The following table provides certain information regarding performance
factors for the six month periods ended June 30, 2004 and 2003:
Six Months
Ended Percenta
ge
June 30, Increase
2004 2003 (Decreas
e)
---- ---- --------
--
Average price per barrel of $ 34.98 16%
oil 30.08
Average price per mcf of gas $ 5.73 6%
5.39
Oil production in barrels 10,750 11,000 (2%)
Gas production in mcf 126,125 129,600 (3%)
Income from net profits $ 695,779 628,687 11%
interests
Partnership distributions $ 575,000 250,000 130%
Limited partner $ 517,500 225,000 130%
distributions
Per unit distribution to
limited
partners $ 25.88 130%
11.25
Number of limited partner 20,000 20,000
units
Revenues
The Partnership's income from net profits interests increased to $695,779
from $628,687 for the six months ended June 30, 2004 and 2003,
respectively, an increase of 11%. The principal factors affecting the
comparison of the six months ended June 30, 2004 and 2003 are as follows:
1. The average price for a barrel of oil received by the Partnership
increased during the six months ended June 30, 2004 as compared to the
six months ended June 30, 2003 by 16%, or $4.90 per barrel, resulting
in an increase of approximately $52,700 in income from net profits
interests. Oil sales represented 34% of total oil and gas sales during
the six months ended June 30, 2004 as compared to 32% during the six
months ended June 30, 2003.
The average price for a mcf of gas received by the Partnership
increased during the same period by 6%, or $.34 per mcf, resulting in
an increase of approximately $42,900 in income from net profits
interests.
The total increase in income from net profits interests due to the
change in prices received from oil and gas production is approximately
$95,600. The market price for oil and gas has been extremely volatile
over the past decade, and management expects a certain amount of
volatility to continue in the foreseeable future.
2. Oil production decreased approximately 250 barrels or 2% during the six
months ended June 30, 2004 as compared to the six months ended June 30,
2003, resulting in a decrease of approximately $7,500 in income from
net profits interests.
Gas production decreased approximately 3,475 mcf or 3% during the same
period, resulting in a decrease of approximately $18,700 in income from
net profits interests.
The total decrease in income from net profits interests due to the
change in production is approximately $26,200.
3. Lease operating costs and production taxes were 1% higher, or
approximately $2,100 more during the six months ended June 30, 2004 as
compared to the six months ended June 30, 2003.
Costs and Expenses
Total costs and expenses decreased to $160,421 from $172,893 for the six
months ended June 30, 2004 and 2003, respectively, a decrease of 7%. The
decrease is the result of a lower depletion expense and general and
administrative expense, partially offset by an increase in accretion
expense.
1. General and administrative costs consists of independent accounting,
legal and engineering fees, computer services, postage, and Managing
General Partner personnel costs. General and administrative costs
decreased 3% or approximately $3,000 during the six months ended June
30, 2004 as compared to the six months ended June 30, 2003. The higher
general and administrative expense in 2003 is due to legal fees
associated with the amendments to the Partnership's December 31, 2002
Annual Report on Form 10-K and March 31, 2003 Quarterly Report on Form
10-Q.
2. Depletion expense decreased to $56,000 for the six months ended June
30, 2004 from $66,000 for the same period in 2003. This represents a
decrease of 15%. The contributing factor to the decrease in depletion
expense is in relation to the BOE depletion rate for the six months
ended June 30, 2004, which was $1.76 applied to 31,771 BOE as compared
to $2.02 applied to 32,600 BOE for the same period in 2003.
3. Accretion expense increased to $20,535 for the six months ended June
30, 2004 from $19,993 for the same period in 2003. This represents an
increase of 3%.
Liquidity and Capital Resources
The primary source of cash is from operations, the receipt of income from
interests in oil and gas properties. The Partnership knows of no material
change, nor does it anticipate any such change.
Cash flows provided by operating activities were approximately $511,842 in
the six months ended June 30, 2004 as compared to approximately $367,500 in
the six months ended June 30, 2003.
There were no cash flows provided by investing activities in the six months
ended June 30, 2004. Cash flows provided by investing activities were
approximately $300 in the six months ended June 30, 2003.
Cash flows used in financing activities were approximately $575,000 in the
six months ended June 30, 2004 as compared to approximately $253,600 in the
six months ended June 30, 2003. The only use in financing activities was
the distributions to partners.
Total distributions during the six months ended June 30, 2004 were $575,000
of which $517,500 was distributed to the limited partners and $57,500 to
the general partner. The per unit distribution to limited partners during
the six months ended June 30, 2004 was $25.88. Total distributions during
the six months ended June 30, 2003 were $250,000 of which $225,000 was
distributed to the limited partners and $25,000 to the general partner. The
per unit distribution to limited partners during the six months ended June
30, 2003 was $11.25.
The sources for the 2004 distributions of $575,000 were oil and gas
operations of approximately $511,800, with the balance from available cash
on hand at the beginning of the period. The sources for the 2003
distributions of $250,000 were oil and gas operations of approximately
$367,500 and the change in oil and gas properties of approximately $300,
resulting in excess cash for contingencies or subsequent distributions.
Cumulative cash distributions of $18,778,945 have been made to the general
and limited partners. As of June 30, 2004, $16,916,759 or $845.84 per
limited partner unit has been distributed to the limited partners,
representing a 100% return of the capital and a 69% return on capital
contributed.
As of June 30, 2004, the Partnership had approximately $462,600 in working
capital. The Managing General Partner knows of no unusual contractual
commitments. Although the partnership held many long-lived properties at
inception, because of the restrictions on property development imposed by
the partnership agreement, the Partnership cannot develop its non-producing
properties, if any. Without continued development, the producing reserves
continue to deplete. Accordingly, as the Partnership's properties have
matured and depleted, the net cash flows from operations for the
partnership has steadily declined, except in periods of substantially
increased commodity pricing. Maintenance of properties and administrative
expenses for the Partnership are increasing relative to production. As the
properties continue to deplete, maintenance of properties and
administrative costs as a percentage of production are expected to continue
to increase.
Managing General Partner
On May 21, 2004, Clayton Williams Energy, Inc. acquired all the outstanding
common stock of Southwest Royalties Inc. through a merger. Clayton
Williams Energy, Inc. paid $57.1 million to holders of Southwest Royalties,
Inc. common stock and common stock warrants ($45.01 per share) and assumed
and refinanced approximately $113.9 million of assumed bank debt at
closing.
Recent Accounting Pronouncements
The EITF is considering two issues related to the reporting of oil and gas
mineral rights. Issue No. 03-O, "Whether Mineral Rights Are Tangible or
Intangible Assets," is whether or not mineral rights are intangible assets
pursuant to SFAS No. 141, "Business Combinations." Issue No. 03-S,
"Application of SFAS No. 142, Goodwill and Other Intangible Assets, to Oil
and Gas Companies," is, if oil and gas drilling rights are intangible
assets, whether those assets are subject to the classification and
disclosure provisions of SFAS No. 142. The Partnership classifies the cost
of oil and gas mineral rights as properties and equipment and believes that
this is consistent with oil and gas accounting and industry practice. The
staff of the FASB has issued a proposed position clarifying that SFAS No.
142 does not supersede the balance sheet classification and disclosure for
drilling and mineral rights of oil and gas producing entities within the
scope of FASB No. 19. If SFAS No. 142 is determined to apply to oil and
gas companies, the Partnership may be required to make certain
reclassifications within property and equipment on the balance sheet, and
additional disclosures may be required. There would be no effect on the
statement of income or cash flows as the intangible assets related to oil
and gas mineral rights would continue to be amortized under the full cost
method of accounting.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
The Partnership is not a party to any derivative
or embedded derivative instruments.
Disclosure Controls and Procedures
As of the six months ended June 30, 2004, L. Paul Latham, President and
Chief Executive Officer of the Managing General Partner, and Mel G. Riggs,
Vice President and Chief Financial Officer of the Managing General Partner,
evaluated the effectiveness of the Partnership's disclosure controls and
procedures. Based on their evaluation, they believe that:
The disclosure controls and procedures of the Partnership were
effective in ensuring that information required to be disclosed by the
Partnership in the reports it files or submits under the Exchange Act
was recorded, processed, summarized and reported within the time
periods specified in the SEC's rules and forms; and
The disclosure controls and procedures of the Partnership were
effective in ensuring that material information required to be
disclosed by the Partnership in the report it filed or submitted under
the Exchange Act was accumulated and communicated to the Managing
General Partner's management, including its Chief Executive Officer
and Chief Financial Officer, as appropriate to allow timely decisions
regarding required disclosure.
Internal Control Over Financial Reporting
There has not been any change in the Partnership's internal control over
financial reporting that occurred during the six months ended June 30, 2004
that has materially affected, or is reasonably likely to materially affect,
internal control over financial reporting.
PART II. - OTHER INFORMATION
Item 1. Legal Proceedings
None
Item 2. Changes in Securities
None
Item 3. Defaults Upon Senior Securities
None
Item 4. Submission of Matter to a Vote of Security Holders
None
Item 5. Other Information
None
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits:
31.1 Rule 13a-14(a)/15d-14(a) Certification
31.2 Rule 13a-14(a)/15d-14(a) Certification
32.1 Certification of Chief Executive Officer
Pursuant to 18 U.S.C. Section
1350, as
adopted Pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002
32.2 Certification of Chief Financial Officer
Pursuant to 18 U.S.C. Section
1350, as
adopted Pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002
(b) Reports on Form 8-K:
The Partnership filed an 8-K on June 3, 2004 under Item 1
"Changes in Control of Registrant" and Item 7 "Financial
Statements, Pro forma Financial Information and 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.
SOUTHWEST ROYALTIES, INC.
INCOME FUND VI,
a Tennessee limited partnership
By: Southwest Royalties, Inc.
Managing General Partner
By: /s/ Mel G. Riggs
Mel G. Riggs
Vice President and Chief Financial Officer
Date: August 12, 2004
SECTION 302 CERTIFICATION Exhibit 31.1
I, L. Paul Latham, certify that:
1. I have reviewed this quarterly
report on Form 10-Q of Southwest Royalties, Inc. Income Fund VI
2.Based on my knowledge, this report does not contain any untrue statement
of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered
by this report;
3.Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material
respects the financial condition, results of operations and cash flows
of the registrant as of, and for, the periods presented in this report;
4.The registrant's other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the
registrant and have:
a)Designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to
us by others within those entities, particularly during the period in
which this report is being prepared;
b)Evaluated the effectiveness of the registrant's disclosure controls
and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
c)Disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the registrant's
most recent fiscal quarter (the registrant's fourth fiscal quarter in
the case of an annual report) that has materially affected, or is
reasonably likely to materially affect, the registrant's internal
control over financial reporting; and
5.The registrant's other certifying officer(s) and I have disclosed, based
on our most recent evaluation of internal control over financial
reporting, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent
functions):
a)All significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which
reasonably likely to adversely affect the registrant's ability to
record, process, summarize and report financial information; and
b)Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
control over financial reporting.
Date: August 12, 2004 /s/ L. Paul Latham
L. Paul Latham
President and Chief Executive Officer
of Southwest Royalties, Inc., the
Managing General Partner of
Southwest Royalties, Inc. Income Fund VI
SECTION 302 CERTIFICATION Exhibit 31.2
I, Mel G. Riggs, certify that:
1. I have reviewed this quarterly
report on Form 10-Q of Southwest Royalties, Inc. Income Fund VI
2.Based on my knowledge, this report does not contain any untrue statement
of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered
by this report;
3.Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material
respects the financial condition, results of operations and cash flows
of the registrant as of, and for, the periods presented in this report;
4.The registrant's other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the
registrant and have:
a)Designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to
us by others within those entities, particularly during the period in
which this report is being prepared;
b)Evaluated the effectiveness of the registrant's disclosure controls
and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
c)Disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the registrant's
most recent fiscal quarter (the registrant's fourth fiscal quarter in
the case of an annual report) that has materially affected, or is
reasonably likely to materially affect, the registrant's internal
control over financial reporting; and
5.The registrant's other certifying officer(s) and I have disclosed, based
on our most recent evaluation of internal control over financial
reporting, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent
functions):
a)All significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which
reasonably likely to adversely affect the registrant's ability to
record, process, summarize and report financial information; and
b)Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
control over financial reporting.
Date: August 12, 2004 /s/ Mel G. Riggs
Mel G. Riggs
Vice President and Chief Financial
Officer of
Southwest Royalties, Inc., the
Managing General Partner of
Southwest Royalties, Inc. Income Fund VI
CERTIFICATION PURSUANT TOExhibit 32.1
19 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of Southwest Royalties, Inc.
Income Fund VI, Limited Partnership (the "Company") on Form 10-Q for the
period ending June 30, 2004 as filed with the Securities and Exchange
Commission on the date hereof (the "Report"), I, L. Paul Latham, Chief
Executive Officer of the Managing General Partner of the Company, certify,
pursuant to 18 U.S.C. 1350, as adopted pursuant to 906 of the Sarbanes-
Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of section 13(a) or
15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all
material respects, the financial condition and
results of operation of the
Company.
Date: August 12, 2004
/s/ L. Paul Latham
L. Paul Latham
President and Chief Executive Officer
of Southwest Royalties, Inc., the
Managing General Partner of
Southwest Royalties, Inc. Income Fund VI
CERTIFICATION PURSUANT TOExhibit 32.2
19 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of Southwest Royalties, Inc.
Income Fund VI, Limited Partnership (the "Company") on Form 10-Q for the
period ending June 30, 2004 as filed with the Securities and Exchange
Commission on the date hereof (the "Report"), I, Mel G. Riggs, Chief
Financial Officer of the Managing General Partner of the Company, certify,
pursuant to 18 U.S.C. 1350, as adopted pursuant to 906 of the Sarbanes-
Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of section 13(a) or
15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all
material respects, the financial condition and
results of operation of the
Company.
Date: August 12, 2004
/s/ Mel G. Riggs
Mel G. Riggs
Vice President and Chief Financial Officer of
Southwest Royalties, Inc., the
Managing General Partner of
Southwest Royalties, Inc. Income Fund VI