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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 March 31, 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
(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 22.
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-month period
ended March 31, 2004 are not necessarily indicative of the results that
may be expected for the full year.
Southwest Royalties, Inc. Income Fund VI
Balance Sheets
March December
31, 31,
2004 2003
------ ------
(unaudit
ed)
Assets
- ---------
Current assets:
Cash and cash equivalents $ 195,181 234,954
Receivable from Managing General 245,903 189,477
Partner
Oklahoma withholding prepayment 124 124
-------- --------
----- -----
Total current assets 441,208 424,555
-------- --------
----- -----
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 6,170,46 6,143,46
0 0
-------- --------
----- -----
Net oil and gas properties 2,376,85 2,403,85
7 7
-------- --------
----- -----
$ 2,818,06 2,828,41
5 2
======= =======
Liabilities and Partners' Equity
- -------------------------------------
- ---
Asset retirement obligation $ 523,668 513,400
-------- --------
----- -----
Partners' equity:
General partner (624,891 (622,829
) )
Limited partners 2,919,28 2,937,84
8 1
-------- --------
----- -----
Total partners' equity 2,294,39 2,315,01
7 2
-------- --------
----- -----
$ 2,818,06 2,828,41
5 2
======= =======
Southwest Royalties, Inc. Income Fund VI
Statements of Operations
(unaudited)
Three Months Ended
March 31,
2004 2003
------ ------
Revenues
- -------------
Income from net profits $ 381,225 297,280
interests
Interest 462 18
Other 250 -
-------- --------
--- ---
381,937 297,298
-------- --------
--- ---
Expenses
- -------------
General and administrative 40,284 37,477
Depreciation, depletion and 27,000 28,000
amortization
Accretion of asset retirement 10,268 9,997
obligation
-------- --------
--- ---
77,552 75,474
-------- --------
--- ---
Net income before cumulative 304,385 221,824
effect
Cumulative effect of change in
accounting
principle - SFAS No. 143 - See - 116,637
Note 3
-------- --------
--- ---
Net income $ 304,385 338,461
====== ======
Net income allocated to:
Managing General Partner $ 30,438 33,846
====== ======
Limited partners $ 273,947 304,615
====== ======
Per limited partner unit $ 13.70
before cumulative effect 9.98
Cumulative effect per limited -
partner unit 5.25
-------- --------
--- ---
Per limited partner unit $ 13.70
15.23
====== ======
Southwest Royalties, Inc. Income Fund VI
Statements of Cash Flows
(unaudited)
Three Months Ended
March 31,
2004 2003
------ ------
Cash flows from operating
activities:
Cash received from income from
net profits
interests $ 307,243 112,891
Cash paid to suppliers (22,728) (17,482)
Interest received 462 18
Other 250 -
-------- --------
-- --
Net cash provided by operating 285,227 95,427
activities
-------- --------
-- --
Cash flows used in financing
activities:
Distributions to partners (325,000 (1,077)
)
-------- --------
-- --
Net (decrease) increase in cash (39,773) 94,350
and cash equivalents
Beginning of period 234,954 18,015
-------- --------
-- --
End of period $ 195,181 112,365
====== ======
Reconciliation of net income to
net
cash provided by operating
activities:
Net income $ 304,385 338,461
Adjustments to reconcile net
income to
net cash provided by operating
activities:
Depreciation, depletion and 27,000 28,000
amortization
Accretion of asset retirement 10,268 9,997
obligation
Cumulative effect of change in
accounting
principle - SFAS No. 143 - (116,637
)
Increase in receivables (73,982) (184,389
)
Increase in payables 17,556 19,995
-------- --------
-- --
Net cash provided by operating $ 285,227 95,427
activities
====== ======
Noncash investing and financing
activities:
Increase in oil and gas $ - 616,464
properties - Adoption
of SFAS No.143 ====== ======
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. 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 costs (1) 100% -
Amortization of organization costs 100% -
Property acquisition costs 100% -
Gain/loss on property disposition 90% 10%
Operating and administrative costs (2) 90% 10%
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 March 31, 2004, and for the
three months ended March 31, 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 March
31, 2004, the asset retirement obligation was $523,668. The
increase in the asset retirement obligation from January 1, 2004 is
due to accretion expense of $10,268.
Southwest Royalties, Inc. Income Fund VI
(a Tennessee limited partnership)
Notes to Financial Statements
4. Subsequent Event
Subsequent to December 31, 2003, the Managing General Partner
announced that its Board of Directors had decided to explore a merger
or sale of the stock of the Company. The Board formed a Special
Committee of independent directors to oversee the sale process.
The Special Committee retained independent financial and legal advisors
to work closely with management to implement the sale process.
On May 3, 2004, the Managing General Partner entered into a cash
merger agreement to sell all of its stock to Clayton Williams
Energy, Inc. The cash merger price is being negotiated, but is
expected to be approximately $45 per share. The transaction, which
is subject to approval by the Managing General Partner's
shareholders, is expected to close no later than May 21, 2004.
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 decline in later years based on these factors.
Based on current conditions, development drilling and workovers will be
performed during the years 2004 and 2005 to enhance production. The
partnership may have an increase in production volumes for the year 2004
and 2005, but thereafter, the partnership will most likely continue to
experience the historical production decline, which has approximated 10%
per year. Accordingly, if commodity prices remain unchanged, the
Partnership expects future earnings to decline due to anticipated
production declines.
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.
In 2002, the Partnership changed methods of accounting for depletion of
capitalized costs from the units-of-revenue method to the units-of-
production method. The newly adopted accounting principle is preferable
in the circumstances because the units-of-production method results in a
better matching of the costs of oil and gas production against the
related revenue received in periods of volatile prices for production as
have been experienced in recent periods. Additionally, the units-of-
production method is the predominant method used by full cost companies
in the oil and gas industry, accordingly, the change improves the
comparability of the Partnership's financial statements with its peer
group.
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 March 31, 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 March 31, 2004, there were no timing
differences, which resulted in a deficit net profit interest.
Critical Accounting Policies
Full cost ceiling calculations 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.
In 2002, the Partnership changed methods of accounting for depletion of
capitalized costs from the units-of-revenue method to the units-of-
production method. The newly adopted accounting principle is preferable
in the circumstances because the units-of-production method results in a
better matching of the costs of oil and gas production against the
related revenue received in periods of volatile prices for production as
have been experienced in recent periods. Additionally, the units-of-
production method is the predominant method used by full cost companies
in the oil and gas industry, accordingly, the change improves the
comparability of the Partnership's financial statements with its peer
group.
Results of Operations
A. General Comparison of the Quarters Ended March 31, 2004 and 2003
The following table provides certain information regarding performance
factors for the quarters ended March 31, 2004 and 2003:
Three Months
Ended Percenta
ge
March 31, Increase
2004 2003 (Decreas
e)
----- ----- --------
--
Average price per $ 33.10 2%
barrel of oil 32.30
Average price per $ 5.67 (6%)
mcf of gas 6.01
Oil production in 5,880 4,600 28%
barrels
Gas production in 58,800 54,800 7%
mcf
Income from net $ 381,225 297,280 28%
profits interests
Partnership $ 325,000 - 100%
distributions
Limited partner $ 292,500 - 100%
distributions
Per unit
distribution to
limited
partners $ 14.63 - 100%
Number of limited 20,000 20,000
partner units
Revenues
The Partnership's income from net profits interests increased to
$381,225 from $297,280 for the quarters ended March 31, 2004 and 2003,
respectively, an increase of 28%. The principal factors affecting the
comparison of the quarters ended March 31, 2004 and 2003 are as follows:
1. The average price for a barrel of oil received by the Partnership
increased during the quarter ended March 31, 2004 as compared to the
quarter ended March 31, 2003 by 2%, or $.80 per barrel, resulting in
an increase of approximately $4,700 in income from net profits
interests. Oil sales represented 37% of total oil and gas sales
during the quarter ended March 31, 2004 as compared to 31% during
the quarter ended March 31, 2003.
The average price for an mcf of gas received by the Partnership
decreased during the same period by 6%, or $.34 per mcf, resulting
in a decrease of approximately $20,000 in income from net profits
interests.
The net total decrease in income from net profits interests due to
the change in prices received from oil and gas production is
approximately $15,300. 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 increased approximately 1,280 barrels or 28% during
the quarter ended March 31, 2004 as compared to the quarter ended
March 31, 2003, resulting in an increase of approximately $41,300 in
income from net profits interests.
Gas production increased approximately 4,000 mcf or 7% during the
same period, resulting in an increase of approximately $24,000 in
income from net profits interests.
The total increase in income from net profits interests due to the
change in production is approximately $65,300. Oil production
during the first quarter 2003 was adjusted in connection with a
change in estimate. The Partnership was receiving revenue on a well
in which they did not have an interest, but owned a very small
interest on another well on a different lease.
3. Lease operating costs and production taxes were 19% lower, or
approximately $33,400 less during the quarter ended March 31, 2004
as compared to the quarter ended March 31, 2003. The higher lease
operating costs in 2003 were the result of adding artificial lift
equipment to a well.
Costs and Expenses
Total costs and expenses increased to $77,552 from $75,474 for the
quarters ended March 31, 2004 and 2003, respectively, an increase of 3%.
The increase is a direct result of the increase in accretion expense
associated with our long term liability related to expected abandonment
costs of our oil and natural gas properties and general and
administrative expense, partially offset by a decrease in depletion
expense.
1. General and administrative costs consists of independent accounting
and engineering fees, computer services, postage, and Managing
General Partner personnel costs. General and administrative costs
increased 7% or approximately $2,800 during the quarter ended March
31, 2004 as compared to the quarter ended March 31, 2003. The
increase in general and administrative costs is due primarily to an
increase of $1,660 in quarterly accounting review fees.
2. Depletion expense decreased to $27,000 for the quarter ended March
31, 2004 from $28,000 for the same period in 2003. This represents
a decrease of 4%. The contributing factor to the decrease in
depletion expense is in relation to the BOE depletion rate for the
quarter ended March 31, 2004, which was $1.72 applied to 15,680 BOE
as compared to $2.04 applied to 13,733 BOE for the same period in
2003.
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 March 31, 2004, the asset retirement obligation was
$523,668. The increase in the asset retirement obligation from January
1, 2004 is due to accretion expense of $10,268.
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 $285,200
in the quarter ended March 31, 2004 as compared to approximately $95,400
in the quarter ended March 31, 2003.
Cash flows used in financing activities were approximately $325,000 in
the quarter ended March 31, 2004 as compared to approximately $1,100 in
the quarter ended March 31, 2003. The only use in financing activities
was the distributions to partners.
Total distributions during the quarter ended March 31, 2004 were
$325,000 of which $292,500 was distributed to the limited partners and
$32,500 to the general partner. The per unit distribution to limited
partners during the quarter ended March 31, 2004 was $14.63. There were
no distributions during the quarter ended March 31, 2003.
The source for the 2004 distributions of $325,000 was oil and gas
operations of approximately $285,200, with the balance from available
cash on hand at the beginning of the period.
Cumulative cash distributions of $18,528,945 have been made to the
general and limited partners. As of March 31, 2004, $16,691,759 or
$834.59 per limited partner unit has been distributed to the limited
partners, representing a 100% return of the capital and a 67% return on
capital contributed.
As of March 31, 2004, the Partnership had approximately $441,200 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.
Liquidity - Managing General Partner
As of December 31, 2003, the Managing General Partner is in violation of
several covenants pertaining to their Amended and Restated Revolving
Credit Agreement due June 1, 2006 and their Senior Second Lien Secured
Credit Agreement due October 15, 2008. Due to the covenant violations,
the Managing General Partner is in default under their Amended and
Restated Revolving Credit Agreement and the Senior Second Lien Secured
Credit Agreement, and all amounts due under these agreements have been
classified as a current liability on the Managing General Partner's
balance sheet at December 31, 2003. The significant working capital
deficit and debt being in default at December 31, 2003, raise
substantial doubt about the Managing General Partner's ability to
continue as a going concern.
Subsequent to December 31, 2003, the Board of Directors of the Managing
General Partner announced its decision to explore a merger, sale of the
stock or other transaction involving the Managing General Partner. The
Board has formed a Special Committee of independent directors to oversee
the sales process. The Special Committee has retained independent
financial and legal advisors to work closely with the management of the
Managing General Partner to implement the sales process. There can be
no assurance that a sale of the Managing General Partner will be
consummated or what terms, if consummated, the sale will be on.
On May 3, 2004, the Managing General Partner entered into a cash merger
agreement to sell all of its stock to Clayton Williams Energy, Inc. The
cash merger price is being negotiated, but is expected to be
approximately $45 per share. The transaction, which is subject to
approval by the Managing General Partner's shareholders, is expected to
close no later than May 21, 2004.
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 disclosures required by
SFAS Nos. 141 and 142 would be made in the notes to the financial
statements. 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.
Item 4. Controls and Procedures
Disclosure Controls and Procedures
As of the three months ended March 31, 2004, H.H. Wommack, III,
President and Chief Executive Officer of the Managing General Partner,
and Bill E. Coggin, Executive 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 President and
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 three months ended March
31, 2004 that has materially affected, or is reasonably likely to
materially affect, it 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:
No reports on Form 8-K were filed during the
quarter for which this report is filed.
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/ Bill E. Coggin
-------------------------------------
- --
Bill E. Coggin, Vice President
and Chief Financial Officer
Date: May 14, 2004
SECTION 302 CERTIFICATION Exhibit 31.1
I, H.H. Wommack, III, 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 15-15(e)) and
internal control over financial reporting (as defined in Exchange Act
Rules 13a-15(f) and 15d-15(f) 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)Designed such internal control over financial reporting, or caused
such internal control over financial reporting to be designed under
our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally
accepted accounting principles;
c)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
d)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 controls 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 controls over financial reporting.
Date: May 14, 2004 /s/ H. H. Wommack, III
H. H. Wommack, III
Chairman, 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, Bill E. Coggin, 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 15-15(e)) and
internal control over financial reporting (as defined in Exchange Act
Rules 13a-15(f) and 15d-15(f) 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)Designed such internal control over financial reporting, or caused
such internal control over financial reporting to be designed under
our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally
accepted accounting principles;
c)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
d)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 controls 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 controls over financial reporting.
Date: May 14, 2004 /s/ Bill E. Coggin
Bill E. Coggin
Executive 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, L.P. (the "Company") on Form 10-Q for the period
ending March 31, 2004 as filed with the Securities and Exchange
Commission on the date hereof (the "Report"), I, H.H. Wommack, III,
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: May 14, 2004
/s/ H.H. Wommack, III
H. H. Wommack, III
Chairman, President, Director 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, L.P. (the "Company") on Form 10-Q for the period
ending March 31, 2004 as filed with the Securities and Exchange
Commission on the date hereof (the "Report"), I, Bill E. Coggin, 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: May 14, 2004
/s/ Bill E. Coggin
Bill E. Coggin
Executive Vice President
and Chief Financial Officer of
Southwest Royalties, Inc., the
Managing General Partner of
Southwest Royalties, Inc. Income Fund VI