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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, 2002
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)
(915) 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
The total number of pages contained in this report is 16.
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, 2001 which are found in the Registrant's Form
10-K Report for 2001 filed with the Securities and Exchange Commission.
The December 31, 2001 balance sheet included herein has been taken from the
Registrant's 2001 Form 10-K Report. Operating results for the three and
six month periods ended June 30, 2002 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,
2002 2001
--------- ------------
(unaudited)
Assets
------
Current assets:
Cash and cash equivalents $ 117,141 132,282
Receivable from Managing General Partner - 18,003
- --------- ---------
Total current assets
117,141 150,285
- --------- ---------
Oil and gas properties - using the full-
cost method of accounting 8,424,134 8,424,134
Less accumulated depreciation,
depletion and amortization
6,937,000 6,886,000
- --------- ---------
Net oil and gas properties
1,487,134 1,538,134
- --------- ---------
$
1,604,275 1,688,419
========= =========
Liabilities and Partners' Equity
--------------------------------
Current liabilities:
Distributions payable $ 2,830 2,837
Payable to Managing General Partner 30,064 -
- --------- ---------
Total current liabilities
32,894 2,837
- --------- ---------
Partners' equity:
General partners (697,192) (685,772)
Limited partners 2,268,573 2,371,354
- --------- ---------
Total partners' equity
1,571,381 1,685,582
- --------- ---------
$
1,604,275 1,688,419
========= =========
Southwest Royalties, Inc. Income Fund VI
Statements of Operations
(unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2002 2001 2002 2001
---- ---- ---- ----
Revenues
--------
Income from net profits
interests $ (7,172) 328,398 10,615 867,248
Interest 328 3,061 695 5,900
Miscellaneous settlement 581 - 581 -
------- ------- ------- -------
(6,263) 331,459 11,891 873,148
------- ------- ------- -------
Expenses
--------
General and administrative 36,966 38,963 75,092 76,321
Depreciation, depletion and
amortization 31,000 60,000 51,000 100,000
------- ------- ------- -------
67,966 98,963 126,092 176,321
------- ------- ------- -------
Net (loss) income $ (74,229) 232,496 (114,201) 696,827
======= ======= ======= =======
Net (loss) income allocated to:
Managing General Partner $ (6,681) 20,925 (10,278) 62,714
======= ======= ======= =======
General Partner $ (742) 2,325 (1,142) 6,969
======= ======= ======= =======
Limited Partners $ (66,806) 209,246 (102,781) 627,144
======= ======= ======= =======
Per limited partner unit $ (3.34) 10.46 (5.14) 31.36
======= ======= ======= =======
Southwest Royalties, Inc. Income Fund VI
Statements of Cash Flows
(unaudited)
Six Months Ended
June 30,
2002 2001
---- ----
Cash flows from operating activities:
Cash received from income from net
profits interests $ 28,892 815,483
Cash paid to suppliers (45,302) (51,386)
Interest received 695 5,900
Miscellaneous settlement 581 -
-------- --------
Net cash (used in) provided
(15,134) 769,997
-------- --------
Cash flows used in financing activities:
Distributions to partners (7) (802,034)
-------- --------
Net decrease in cash and cash equivalents (15,141) (32,037)
Beginning of period 132,282 163,762
-------- --------
End of period $ 117,141 131,725
======== ========
Reconciliation of net (loss) income to net
cash (used in) provided by operating activities:
Net (loss) income $ (114,201) 696,827
Adjustments to reconcile net (loss) income to
net cash (used in) provided by operating activities:
Depreciation, depletion and amortization 51,000 100,000
Decrease (increase) in receivables 18,277 (51,765)
Increase in payables 29,790 24,935
------- -------
Net cash (used in) provided by operating activities $ (15,134) 769,997
======= =======
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 contributions 100% -
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 June 30, 2002, and for the
three and six months ended June 30, 2002, 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 audited financial
statements for the year ended December 31, 2001.
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.
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.
Based on current conditions, management anticipates performing necessary
workovers during the next few years to enhance production. The Partnership
has the opportunity for potential increases with little decline.
Thereafter, the Partnership could possibly experience a normal decline of
9% per year.
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
involved.
The Partnership's policy for depreciation, depletion and amortization of
oil and gas properties is computed under the units of revenue method.
Under the units of revenue method, depreciation, depletion and amortization
is computed on the basis of current gross revenues from production in
relation to future gross revenues, based on current prices, from estimated
production of proved oil and gas reserves.
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, 2002, the net capitalized costs did not
exceed the estimated present value of oil and gas reserves.
Under the units of revenue method, the Partnership computes the provision
by multiplying the total unamortized cost of oil and gas properties by an
overall rate determined by dividing (a) oil and gas revenues during the
period by (b) the total future gross oil and gas revenues as estimated by
the Partnership's independent petroleum consultants. It is reasonably
possible that those estimates of anticipated future gross revenues, the
remaining estimated economic life of the product, or both could be changed
significantly in the near term due to the potential fluctuation of oil and
gas prices or production. The depletion estimate would also be affected by
this change.
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. The net profits interest is a calculated revenue interest that
burdens the underlying working interest in the property, and the net
profits interest owner is not responsible for the actual development or
production expenses incurred. Accordingly, 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.
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.
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.
The Partnership's policy for depreciation, depletion and amortization of
oil and gas properties is computed under the units of revenue method.
Under the units of revenue method, depreciation, depletion and amortization
is computed on the basis of current gross revenues from production in
relation to future gross revenues, based on current prices, from estimated
production of proved oil and gas reserves.
Results of Operations
A. General Comparison of the Quarters Ended June 30, 2002 and 2001
The following table provides certain information regarding performance
factors for the quarters ended June 30, 2002 and 2001:
Three Months
Ended Percentage
June 30, Increase
2002 2001 (Decrease)
---- ---- ----------
Average price per barrel of oil $ 24.28 26.21 (7%)
Average price per mcf of gas $ 3.06 4.45 (31%)
Oil production in barrels 6,800 7,600 (11%)
Gas production in mcf 74,600 93,400 (20%)
Income from net profits interests $ (7,172) 328,398 (102%)
Partnership distributions $ - 400,000 (100%)
Limited partner distributions $ - 360,000 (100%)
Per unit distribution to limited
partners $ - 18.00 (100%)
Number of limited partner units 20,000 20,000
Revenues
The Partnership's income from net profits interests decreased to $(7,172)
from $328,398 for the quarters ended June 30, 2002 and 2001, respectively,
a decrease of 102%. The principal factors affecting the comparison of the
quarters ended June 30, 2002 and 2001 are as follows:
1. The average price for a barrel of oil received by the Partnership
decreased during the quarter ended June 30, 2002 as compared to the
quarter ended June 30, 2001 by 7%, or $1.93 per barrel, resulting in a
decrease of approximately $13,100 in income from net profits interests.
Oil sales represented 42% of total oil and gas sales during the quarter
ended June 30, 2002 as compared to 32% during the quarter ended June
30, 2001.
The average price for an mcf of gas received by the Partnership
decreased during the same period by 31%, or $1.39 per mcf, resulting in
a decrease of approximately $103,700 in income from net profits
interests.
The total decrease in income from net profits interests due to the
change in prices received from oil and gas production is approximately
$116,800. 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 800 barrels or 11% during the
quarter ended June 30, 2002 as compared to the quarter ended June 30,
2001, resulting in a decrease of approximately $21,000 in income from
net profits interests.
Gas production decreased approximately 18,800 mcf or 20% during the
same period, resulting in a decrease of approximately $83,700 in income
from net profits interests.
The total decrease in income from net profits interests due to the
change in production is approximately $104,700. The decrease in gas
production is primarily due to downtime on one lease during the quarter
ended June 30, 2002.
3. Lease operating costs and production taxes were 64% higher, or
approximately $156,900 more during the quarter ended June 30, 2002 as
compared to the quarter ended June 30, 2001. The increase in lease
operating expense is due to a workover and maintenance being performed
on one lease during the quarter ended June 30, 2002.
Costs and Expenses
Total costs and expenses decreased to $67,966 from $98,963 for the quarters
ended June 30, 2002 and 2001, respectively, a decrease of 31%. The
decrease is the result of lower depletion expense and general and
administrative 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 decreased 5%
or approximately $2,000 during the quarter ended June 30, 2002 as
compared to the quarter ended June 30, 2001.
2. Depletion expense decreased to $31,000 for the quarter ended June 30,
2002 from $60,000 for the same period in 2001. This represents a
decrease of 48%. Depletion is calculated using the units of revenue
method of amortization based on a percentage of current period gross
revenues to total future gross oil and gas revenues, as estimated by
the Partnership's independent petroleum consultants. The contributing
factor to the decrease in depletion expense between the comparative
periods was the decrease in oil and gas revenues received by the
Partnership during 2002 as compared to 2001.
B. General Comparison of the Six Month Periods Ended June 30, 2002 and
2001
The following table provides certain information regarding performance
factors for the six month periods ended June 30, 2002 and 2001:
Six Months
Ended Percentage
June 30, Increase
2002 2001 (Decrease)
---- ---- ----------
Average price per barrel of oil $ 22.02 26.71 (18%)
Average price per mcf of gas $ 2.62 5.43 (52%)
Oil production in barrels 13,100 15,300 (14%)
Gas production in mcf 147,200 180,700 (19%)
Income from net profits interests $ 10,615 867,248 (99%)
Partnership distributions $ - 802,395 (100%)
Limited partner distributions $ - 722,395 (100%)
Per unit distribution to limited
partners $ - 36.12 (100%)
Number of limited partner units 20,000 20,000
Revenues
The Partnership's income from net profits interests decreased to $10,615
from $867,248 for the six months ended June 30, 2002 and 2001,
respectively, a decrease of 99%. The principal factors affecting the
comparison of the six months ended June 30, 2002 and 2001 are as follows:
1. The average price for a barrel of oil received by the Partnership
decreased during the six months ended June 30, 2002 as compared to the
six months ended June 30, 2001 by 18%, or $4.69 per barrel, resulting
in a decrease of approximately $61,400 in income from net profits
interests. Oil sales represented 43% of total oil and gas sales during
the six months ended June 30, 2002 as compared to 29% during the six
months ended June 30, 2001.
The average price for a mcf of gas received by the Partnership
decreased during the same period by 52%, or $2.81 per mcf, resulting in
a decrease of approximately $413,600 in income from net profits
interests.
The total decrease in income from net profits interests due to the
change in prices received from oil and gas production is approximately
$475,000. 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 2,200 barrels or 14% during the
six months ended June 30, 2002 as compared to the six months ended June
30, 2001, resulting in a decrease of approximately $58,800 in income
from net profits interests.
Gas production decreased approximately 33,500 mcf or 19% during the
same period, resulting in a decrease of approximately $181,900 in
income from net profits interests.
The total decrease in income from net profits interests due to the
change in production is approximately $240,700. The decrease in gas
production is primarily due to downtime on one lease during the six
months ended June 30, 2002.
3. Lease operating costs and production taxes were 27% higher, or
approximately $140,400 more during the six months ended June 30, 2002
as compared to the six months ended June 30, 2001. The increase in
lease operating expense is due to a workover and maintenance being
performed on one lease during the six months ended June 30, 2002.
Costs and Expenses
Total costs and expenses decreased to $126,092 from $176,321 for the six
months ended June 30, 2002 and 2001, respectively, a decrease of 28%. The
decrease is the result of lower depletion expense and general and
administrative 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 decreased 2%
or approximately $1,200 during the six months ended June 30, 2002 as
compared to the six months ended June 30, 2001.
2. Depletion expense decreased to $51,000 for the six months ended June
30, 2002 from $100,000 for the same period in 2001. This represents a
decrease of 49%. Depletion is calculated using the units of revenue
method of amortization based on a percentage of current period gross
revenues to total future gross oil and gas revenues, as estimated by
the Partnership's independent petroleum consultants. The contributing
factor to the decrease in depletion expense between the comparative
periods was the decrease in oil and gas revenues received by the
Partnership during 2002 as compared to 2001.
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 (used in) provided by operating activities were approximately
$(15,100) in the six months ended June 30, 2002 as compared to
approximately $770,000 in the six months ended June 30, 2001. The primary
use of the 2002 cash flow from operating activities was operations.
Cash flows used in financing activities were approximately none in the six
months ended June 30, 2002 as compared to approximately $802,000 in the six
months ended June 30, 2001. The only use in financing activities was the
distributions to partners.
There were no material cash flows used in financing activities during the
six months ended June 30, 2002. Total distributions during the six months
ended June 30, 2001 were $802,395 of which $722,395 was distributed to the
limited partners and $80,000 to the general partners. The per unit
distribution to limited partners during the six months ended June 30, 2001
was $36.12.
The sources for the 2001 distributions of $802,395 were oil and gas
operations of approximately $770,000, with the balance from available cash
on hand at the beginning of the period.
Since inception of the Partnership, cumulative monthly cash distributions
of $17,453,854 have been made to the partners. As of June 30, 2002,
$15,724,177 or $786.21 per limited partner unit has been distributed to the
limited partners, representing a 157% return of the capital contributed.
As of June 30, 2002, the Partnership had approximately $84,200 in working
capital. The Managing General Partner knows of no unusual contractual
commitments and believes the revenues generated from operations are
adequate to meet the needs of the Partnership.
Liquidity - MD&A
The Partnership accrued an oil and gas revenue receivable (included in the
payable to the Managing General Partner) of $152,138 at June 30, 2002, and
recognized a net loss in the second quarter of 2002 on an accrual basis for
its net profits interest in oil and gas properties. Cash distributions of
the net profits interest are based on actual cash received from the
underlying oil and gas properties, net of expenses incurred during that
quarterly period. Accordingly, if the net profits interest calculation
results in expenses incurred exceeding the oil and gas income received
during a quarter no net cash is due to the Partnership's net profits
interest until the deficit is recovered from future net profits. Future
cash distributions to the Partnership are dependent on a positive quarterly
net profits calculation on the underlying properties, which differs from
the calculation on an accrual basis.
The Partnership's wells have been depleting over its life and production
has experienced declines from year to year, while costs have not always
decreased proportionately. This economic decline coupled with the
fluctuation of prices has caused the Partnership to experience periodic net
losses. Because the Partnership is a net profit interest, this situation
can cause the Partnership to generate a payable to the Managing General
Partner. If the Partnership should continue to experience this economic
decline thereby creating net losses and increasing the payable, the
Managing General Partner may have to consider dissolution and termination
steps according to the Partnership Agreement.
Recent Accounting Pronouncements
The FASB has issued Statement No. 143 "Accounting for Asset Retirement
Obligations" which establishes requirements for the accounting of removal-
type costs associated with asset retirements. The standard is effective
for fiscal years beginning after June 15, 2002, with earlier application
encouraged. The Managing General Partner is currently assessing the impact
on the partnerships financial statements.
On October 3, 2001, the FASB issued Statements No. 144 "Accounting for the
Impairment or Disposal of Long-Lived Assets." This pronouncement
supercedes FAS 121 "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed" and eliminates the requirement of
Statement 121 to allocate goodwill to long-lived assets to be tested for
impairment. The provisions of this statement are effective for financial
statements issued for fiscal years beginning after December 15, 2001, and
interim periods within those fiscal years. The Managing General Partner
believes that the impact from SFAS No. 144 on the Partnerships financial
position and results of operation should not be significantly different
from that of SFAS No. 121.
In April 2002, FASB issued SFAS No. 145, "Rescission of SFAS No. 4, 44, and
64, Amendment of SFAS No. 13, and Technical Corrections." This Statement
rescinds SFAS No. 4, "Reporting Gains and Losses from Extinguishment of
Debt", and an amendment of that Statement, SFAS No. 64, "Extinguishments of
Debt Made to Satisfy Sinking-Fund Requirements". This Statement also
rescinds or amends other existing authoritative pronouncements to make
various technical corrections, clarify meanings, or describe their
applicability under changed conditions. This standard is effective for
fiscal years beginning after May 15, 2002. The Managing General Partner
believes that the adoption of this statement will not have a significant
impact on the Partnerships financial statements.
In July 2002, FASB issued SFAS No. 146 "Accounting for Costs Associated
with Exit or Disposal Activities" which establishes requirements for
financial accounting and reporting for costs associated with exit or
disposal activities. This standard is effective for exit or disposal
activities initiated after December 31, 2002. The Managing General Partner
is currently assessing the impact of this statement on the Partnerships'
future financial statements.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
The Partnership is not a party to any derivative or
embedded derivative instruments.
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) Reports on Form 8-K:
No reports on Form 8-
K were filed during the quarter ended June 30, 2002.
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: August 14, 2002