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                               FORM 10-Q/A
                             AMENDMENT NO. 1


                    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, 2003

                                    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      No_X__

        The total number of pages contained in this report is 24.

<PAGE>
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.

<PAGE>
     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.

<PAGE>
                     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,  2002,  which are found in the Registrant's Form 10-K/A  Report  for
2002  filed  with the Securities and Exchange Commission.  The  December
31,  2002  balance  sheet  included  herein  has  been  taken  from  the
Registrant's 2002 Form 10-K/A Report.  Operating results for the  three-
month period ended March 31, 2003 are not necessarily indicative of  the
results that may be expected for the full year.

Introductory Note - Statement of Financial Accounting Standard No. 143
The  Partnership implemented SFAS No. 143 effective January 1, 2003 (See
Note  3) to the Partnership's financial statements.  Subsequent  to  the
filing  of  the  Partnership's  Quarterly  Report  on  Form  10-Q,   the
Partnership  discovered  an omission in the  calculation  of  the  asset
retirement liability and therefore has restated it's unaudited condensed
financial statements for the period ended March 31, 2003 as described in
Note 5 to the Partnership's financial statements.

Introductory Note - Depletion Method
During the fourth quarter of 2002, the Partnership changed its method of
providing for depletion from the units-of-revenue method to the units-of-
production  method  as described in Notes 4 and 6 to  the  Partnership's
financial statements.

This change in depletion method was applied as a cumulative effect of  a
change  in  accounting principle effective as of January 1,  2002.   The
unaudited  condensed  financial statements of the  Partnership  for  the
period  ended  March 31, 2002, included herein, have been  restated  (as
described  in  Notes 4 and 6 to the Partnership's financial  statements)
using  the new depletion method and differ from those previously  issued
in  the Partnership's Quarterly Report on Form 10-Q for the period ended
March 31, 2002.


<PAGE>
                 Southwest Royalties, Inc. Income Fund VI
                              Balance Sheets

                                           March   December
                                            31,       31,
                                           2003      2002
                                         Restated
                                          ------    ------
                                         (unaudit
                                            ed)
Assets
---------
Current assets:
 Cash and cash equivalents            $  112,364   18,015
  Receivable  from  Managing  General    250,409   86,014
Partner
                                         --------  --------
                                         ----      ----
   Total current assets                  362,773   104,029
                                         --------  --------
                                         ----      ----
Oil  and  gas properties - using  the
full-
 cost method of accounting               8,573,05  8,424,13
                                         8         4
  Less accumulated depreciation,
   depletion and amortization            6,041,46  6,481,00
                                         0         0
                                         --------  --------
                                         ----      ----
   Net oil and gas properties            2,531,59  1,943,13
                                         8         4
                                         --------  --------
                                         ----      ----
                                      $  2,894,37  2,047,16
                                         1         3
                                         =======   =======
Liabilities and Partners' Equity
-------------------------------------
---
Current   liability  -   distribution $  2,279     3,356
payable
                                         --------  --------
                                         ----      ----
Other long term liabilities              509,824   -
                                         --------  --------
                                         ----      ----
Partners' equity:
 General partners                        (616,104  (649,950
                                         )         )
 Limited partners                        2,998,37  2,693,75
                                         2         7
                                         --------  --------
                                         ----      ----
   Total partners' equity                2,382,26  2,043,80
                                         8         7
                                         --------  --------
                                         ----      ----
                                      $  2,894,37  2,047,16
                                         1         3
                                         =======   =======



<PAGE>
                 Southwest Royalties, Inc. Income Fund VI
                         Statements of Operations
                               (unaudited)

                                    Three Months Ended
                                        March 31,
                                      2003      2002
                                    Restated  Restated
                                     ------    ------
Revenues
-------------
Income    from   net    profits  $  297,280   17,787
interests
Interest                            18        367
                                    --------  --------
                                    ---       -
                                    297,298   18,154
                                    --------  --------
                                    ---       -
Expenses
-------------
General and administrative          37,477    38,126
Depreciation,   depletion   and     28,000    35,000
amortization
Accretion                           9,997     -
                                    --------  --------
                                    ---       -
                                    75,474    73,126
                                    --------  --------
                                    ---       -
Net    income   (loss)   before     221,824   (54,972)
cumulative effect

Cumulative effect of change  in
accounting
 principle - SFAS No. 143 - See     116,637   -
Note 3
Cumulative effect of change  in
accounting principle
 - change in depletion method -     -         530,000
See Note 4
                                    --------  --------
                                    ---       -
Net income                       $  338,461   475,028
                                    ======    =====
Net income allocated to:

 Managing General Partner        $  33,846    42,753
                                    ======    =====
 General partner                 $  -         4,750
                                    ======    =====
 Limited partners                $  304,615   427,525
                                    ======    =====
    Per  limited  partner  unit  $    9.98     (2.47)
before cumulative effect
     Cumulative   effects   per       5.25     23.85
limited partner unit
                                    --------  --------
                                    ---       -
  Per limited partner unit       $   15.23     21.38
                                    ======    =====
Pro   forma  amounts   assuming
changes are applied
 retroactively (See Note 3):
   Net   income  (loss)  before  $  -         (64,169)
cumulative effect
                                    ======    =====
    Per  limited  partner  unit  $  -         (2.89)
(20,000.0)
                                    ======    =====
 Net income                      $  -         465,831
                                    ======    =====
    Per  limited  partner  unit  $  -         20.96
(20,000.0)
                                    ======    =====
<PAGE>
                 Southwest Royalties, Inc. Income Fund VI
                         Statements of Cash Flows
                               (unaudited)

                                      Three Months Ended
                                          March 31,
                                        2003      2002
                                      Restated  Restated
                                       ------    ------
Cash    flows   from    operating
activities:

  Cash received from income  from
net profits
  interests                        $  112,891   8,221
 Cash paid to suppliers               (17,482)  (24,057)
 Interest received                    18        367
                                      --------  --------
                                      --        --
   Net cash provided by (used in)     95,427    (15,469)
operating activities
                                      --------  --------
                                      --        --
Cash   flows  used  in  financing
activities:

 Distributions to partners            (1,077)   (7)
                                      --------  --------
                                      --        --
Net  increase (decrease) in  cash     94,350    (15,476)
and cash equivalents

 Beginning of period                  18,015    132,282
                                      --------  --------
                                      --        --
 End of period                     $  112,365   116,806
                                      ======    ======
Reconciliation of net  income  to
net
    cash  provided  by  operating
activities:

Net income                         $  338,461   475,028

Adjustments   to  reconcile   net
income to
  net cash provided by (used  in)
operating activities:

   Depreciation,  depletion   and     28,000    35,000
amortization
 Accretion                            9,997     -
  Cumulative effect of change  in
accounting
  principle - SFAS No. 143            (116,637  -
                                      )
  Cumulative effect of change  in
accounting
  principle - change in depletion     -         (530,000
method                                          )
 Increase in receivables              (184,389  (9,566)
                                      )
 Increase in payables                 19,995    14,069
                                      --------  --------
                                      --        --
Net  cash  provided by (used  in)  $  95,427    (15,469)
operating activities
                                      ======    ======
Noncash  investing and  financing
activities:

   Increase   in  oil   and   gas  $  616,464   -
properties - Adoption
  of SFAS No.143                      ======    ======
<PAGE>
                 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 and
    H.  H.  Wommack,  III, as the individual general partner.  Effective
    December 31, 2001, Mr. Wommack sold his general partners interest to
    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, 2003, and for the
     three   months  ended  March  31,  2003,  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/A 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/A for the  year
     ended December 31, 2002.

<PAGE>

                 Southwest Royalties, Inc. Income Fund VI
                    (a Tennessee limited partnership)

                      Notes to Financial Statements

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,  2003,  the asset retirement obligation was $509,824,  and  the
     increase  in the balance from January 1, 2003 of $9,997 is  due  to
     accretion  expense.   The pro forma amounts for  the  three  months
     ended  March  31,  2002, which are presented on  the  face  of  the
     statements   of  operations,  reflect  the  effect  of  retroactive
     application of SFAS No. 143.

4.    Cumulative effect of change in accounting principle  -  change  in
depletion method
     In  the fourth quarter of 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.  The Partnership adopted the units-
     of-production  method through the recording of a cumulative  effect
     of  a  change  in  accounting principle in the amount  of  $530,000
     effective  as of January 1, 2002.  The Partnership's depletion  for
     the  three months ended March 31, 2003 and 2002 has been calculated
     using the units-of-production method.  The effect of the change  on
     the three months ended March 31, 2002 was to decrease income before
     cumulative  effect of a change in accounting principle  by  $15,000
     ($.68 per limited partner unit) and increase net income by $515,000
     ($23.17 per limited partner unit).

<PAGE>

                 Southwest Royalties, Inc. Income Fund VI
                    (a Tennessee limited partnership)

                      Notes to Financial Statements

5.   March 31, 2003 Restatement
     On  January 1, 2003, the Partnership adopted Statement of Financial
     Accounting Standards No. 143 as described in Note 3.

     Subsequent to the issuance of the Partnership's Quarterly Report on
     Form  10-Q  for  the  three  months  ended  March  31,  2003,   the
     Partnership  determined  that  it did  not  properly  discount  the
     estimated future plugging liability to its present value.

     This change in the calculation used to determine the amount of  the
     Partnership's  asset  retirement  liability  under  SFAS  No.   143
     resulted  in  a  decrease in the Partnership's previously  reported
     other  long term liability of $572,948 from $1,082,772 to  $509,824
     as of March 31, 2003 and did not effect the Partnership's 2003 cash
     flows from operations, investing or financing activities.

     The change had the following effects on the Statement of Operations
     for  the three months ended March 31, 2003.  (Periods prior to 2003
     were not affected by the change).

                                        Restated      Previously
                                                       Reported
     Accretion                        $9,997         21,231
     Income before cumulative effect  221,824        217,590
   Cumulative effect of change in     116,637        (770,128)
     accounting principle
     Net income (loss)                338,461        (552,538)
     Net income (loss) allocated
     to:
     Managing General Partner         33,846         (55,254)
     General partner                  -              -
     Limited partners                 304,615        (497,284)
       Income (loss) per limited
     partner unit before
         cumulative effect            9.98           (24.86)
       Cumulative effect per          5.25           -
     limited partner unit
       Net income (loss) per          15.23          (24.86)
     limited partner unit

                 Southwest Royalties, Inc. Income Fund VI
                    (a Tennessee limited partnership)

                      Notes to Financial Statements

6.   March 31, 2002 Restatement
     During  the  fourth  quarter of 2002, the Partnership  changed  its
     method  of providing for depletion from the units-of-revenue method
     to the units-of-production method as described in Note 4.

     Subsequent to the issuance of the Partnership's Quarterly Report on
     Form  10-Q  for  the  three  months  ended  March  31,  2003,   the
     Partnership  determined that the above change in accounting  method
     should  have been adopted by the Partnership as a cumulative effect
     of  a  change  in accounting principle effective as of  January  1,
     2002.   The  Partnership had previously applied the change  in  the
     method  of  providing for depletion prospectively as of October  1,
     2002.

     This  change  in  the  method used to implement  the  Partnership's
     change  in the manner in which it determines depletion resulted  in
     an  increase in the Partnership's previously reported net  oil  and
     gas  properties  of $496,000 from $1,447,134 to  $1,943,134  as  of
     December  31, 2002 and did not effect the Partnership's  2002  cash
     flows from operations, investing or financing activities.

     The change had the following effects on the Statement of Operations
     for the three months ended March 31, 2002.

                                        Restated      Previously
                                                       Reported
     Depreciation, depletion and      $35,000        20,000
     amortization
     Income (loss) before cumulative  (54,972)       (39,972)
     effect
   Cumulative effect of change in     530,000        -
     accounting principle
     Net income (loss)                475,028        (39,972)
     Net income (loss) allocated
     to:
     Managing General Partner         42,753         (3,597)
     General partner                  4,750          (400)
     Limited partners                 427,525        (35,975)
       Income (loss) per limited
     partner unit before
         cumulative effect            (2.47)         (1.80)
       Cumulative effect per          23.85          -
     limited partner unit
       Net income (loss) per          21.38          (1.80)
     limited partner unit


<PAGE>
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.

Based on current conditions, development drilling and workovers will  be
performed  during  the  years 2003 and 2004 to enhance  production.  The
partnership may have an increase in production volumes for the year 2003
and  2004,  but thereafter, the partnership will most likely  experience
the historical production decline, which has approximated 10% 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.

In  the  fourth  quarter  of 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.  The  effect  of
this  change in method was to increase depletion expense for  the  three
months  ended March 31, 2002 by $15,000 and increase net income for  the
three  months ended March 31, 2002 by $515,000.  See Note 4 of the notes
to the Partnership's financial statements.

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, 2003, the net  capitalized
costs  did  not  exceed  the estimated present  value  of  oil  and  gas
reserves.


<PAGE>
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, 2003, 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  on  an  annual basis prepared  by  outside  consultants.
Quarterly  reserves  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  the  fourth  quarter  of 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.  The  effect  of
this  change in method was to increase depletion expense for  the  three
months  ended March 31, 2002 by $15,000 and increase net income for  the
three months ended March 31, 2002 by $515,000.
<PAGE>
Results of Operations

A.  General Comparison of the Quarters Ended March 31, 2003 and 2002

The  following table provides certain information regarding  performance
factors for the quarters ended March 31, 2003 and 2002:

                          Three Months
                             Ended         Percenta
                                              ge
                           March 31,       Increase
                         2003      2002    (Decreas
                                              e)
                        -----     -----    --------
                                              --
Average price  per  $   32.30              65%
barrel of oil                    19.58
Average price  per  $    6.01              178%
mcf of gas                       2.16
Oil production  in     4,600     6,300     (27%)
barrels
Gas production  in     54,800    72,600    (25%)
mcf
Income  from   net  $  297,280   17,787    1,571%
profits interests
Partnership         $  -         -         -
distributions
Limited    partner  $  -         -         -
distributions
Per           unit
distribution    to
limited
 partners           $  -         -         -
Number  of limited     20,000    20,000
partner units

Revenues

The  Partnership's  income  from  net  profits  interests  increased  to
$297,280  from $17,787 for the quarters ended March 31, 2003  and  2002,
respectively,  an  increase of 1,571%.  The principal factors  affecting
the  comparison  of the quarters ended March 31, 2003 and  2002  are  as
follows:

1.  The  average  price for a barrel of oil received by the  Partnership
    increased during the quarter ended March 31, 2003 as compared to the
    quarter ended March 31, 2002 by 65%, or $12.72 per barrel, resulting
    in  an  increase of approximately $58,500 in income from net profits
    interests.   Oil sales represented 31% of total oil  and  gas  sales
    during  the  quarter ended March 31, 2003 as compared to 44%  during
    the quarter ended March 31, 2002.

    The  average  price  for an mcf of gas received by  the  Partnership
    increased  during  the  same  period by  178%,  or  $3.85  per  mcf,
    resulting  in an increase of approximately $211,000 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 $269,500.  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.

<PAGE>
2.  Oil  production decreased approximately 1,700 barrels or 27%  during
    the  quarter  ended March 31, 2003 as compared to the quarter  ended
    March 31, 2002, resulting in a decrease of approximately $33,300  in
    income from net profits interests.

    Gas  production decreased approximately 17,800 mcf or 25% during the
    same  period,  resulting in a decrease of approximately  $38,400  in
    income from net profits interests.

    The  total decrease in income from net profits interests due to  the
    change in production is approximately $71,700.  The decrease in  oil
    production  is  in connection with a change in estimate,  which  the
    Partnership did not have an interest in a well, but another well  on
    a  different  lease owned a very small interest of  the  production.
    The  decrease  in  gas production is primarily  due  to  a  farm-out
    arrangement during 2002 with the Managing General Partner, in  which
    the  Partnership retained a smaller interest.  This same lease  also
    experiences gas balancing.

3.  Lease  operating  costs  and production taxes  were  31%  lower,  or
    approximately $82,300 less during the quarter ended March  31,  2003
    as  compared  to the quarter ended March 31, 2002.  The decrease  in
    lease operating expense is due mainly to a workover performed on one
    lease  during the quarter ended March 31, 2002, partially offset  by
    an  increase  in production taxes due to an increase in revenues  in
    relation to prices.

Costs and Expenses

Total  costs  and  expenses increased to $75,474 from  $73,126  for  the
quarters ended March 31, 2003 and 2002, respectively, an increase of 3%.
The increase is a direct result of the accretion expense associated with
our long term liability related to expected abandonment costs of our oil
and  natural gas properties, partially offset by a decrease  in  general
and administrative expense and 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
    decreased  2% or approximately $600 during the quarter  ended  March
    31, 2003 as compared to the quarter ended March 31, 2002.

2.  Depletion  expense decreased to $28,000 for the quarter ended  March
    31,  2003 from $35,000 for the same period in 2002.  This represents
    a  decrease  of 20%.  In the fourth quarter of 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.  The  effect
    of  this change in method was to increase depletion expense for  the
    three months ended March 31, 2002 by $15,000 and increase net income
    for  the  three  months  ended March  31,  2002  by  $515,000.   The
    contributing  factor  to  the decrease in depletion  expense  is  in
    relation  to the BOE depletion rate for the quarter ended March  31,
    2003,  which  was $2.06 applied to 13,733 BOE as compared  to  $1.89
    applied to 18,400 BOE for the same period.

<PAGE>

Cumulative effect of change in accounting principle

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, 2003, the asset retirement  obligation  was
$509,824, and the increase in the balance from January 1, 2003 of $9,997
is due to accretion expense.  The pro forma amounts for the three months
ended  March 31, 2002, which are presented on the face of the statements
of operations, reflect the effect of retroactive application of SFAS No.
143.

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 (used in) operating activities were approximately
$95,400 in the quarter ended March 31, 2003 as compared to approximately
$(15,500)  in the quarter ended March 31, 2002.  The primary  source  of
the 2003 cash flows from operating activities was profitable operations.

Cash flows used in financing activities were approximately $1,100 in the
quarter ended March 31, 2003.  There were no material cash flows used in
financing activities in the quarter ended March 31, 2002.

There were no distributions during the quarter ended March 31, 2003  and
2002.

Since   inception   of   the   Partnership,  cumulative   monthly   cash
distributions  of  $17,453,854 have been made to the  partners.   As  of
March 31, 2003, $15,724,177 or $786.21 per limited partner unit has been
distributed to the limited partners, representing a 100% return  of  the
capital and a 57% return on capital contributed.

As  of  March  31, 2003, the Partnership had approximately  $360,500  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.

The  Managing  General  Partner  has examined  various  alternatives  to
address   the   issue  of  depleting  producing  reserves.    Continuing
operations exposes the partnership to an inevitable decline in operating
results  and  distributions of cash.  Liquidating the partnership  would
result in immediate realization of cash for limited partners, but prices
paid  by purchasers of Partnership property in liquidation would  likely
include  a  substantial discount for risks and uncertainties  of  future
cash  flows, as well as any development risks.  After reviewing  various
alternatives, we initiated a plan to merge the Partnership and 20  other
limited  partnerships with and into the Managing  General  Partner.   On
October  17,  2002,  the Managing General Partner filed  a  Registration
Statement  on  form  S-4  with the Securities  and  Exchange  Commission
relating to this proposed merger.  There is no assurance, however,  that
this merger will be consummated.

<PAGE>

Liquidity - Managing General Partner
The  Managing  General Partner has a highly leveraged capital  structure
with approximately $124.0 million of principal due between December  31,
2002  and December 31, 2004.  The Managing General Partner is constantly
monitoring  its  cash  position and its ability to  meet  its  financial
obligations  as  they  become due, and in this  effort,  is  continually
exploring  various  strategies for addressing  its  current  and  future
liquidity  needs.   The Managing General Partner regularly  pursues  and
evaluates  recapitalization  strategies  and  acquisition  opportunities
(including opportunities to engage in mergers, consolidations  or  other
business combinations) and at any given time may be in various stages of
evaluating such opportunities.

Based  on  current  production, commodity  prices  and  cash  flow  from
operations, the Managing General Partner has adequate cash flow to  fund
debt  service, developmental projects and day to day operations, but  it
is not sufficient to build a cash balance which would allow the Managing
General  Partner  to  meet its debt principal maturities  scheduled  for
2004.   Therefore the Managing General Partner is currently  seeking  to
renegotiate  the terms of its obligations, including extending  maturity
dates,  or to engage new lenders or equity investors in order to satisfy
its financial obligations maturing in 2004.

There  can  be  no  assurance that the Managing General  Partner's  debt
restructuring  efforts will be successful.  In the event  these  efforts
are  unsuccessful, the Managing General Partner would need  to  look  to
other  alternatives to meet its debt obligations, including  potentially
selling its assets.  There can be no assurance, however, that the  sales
of  assets can be successfully accomplished on terms acceptable  to  the
Managing General Partner.  Please see the Partnership's Quarterly Report
on  Form  10-Q for the quarterly period ended September 30, 2003,  which
will  be  filed with the Commission on or before November 14, 2003,  for
updated  information on the liquidity of the Managing  General  Partner.
The liquidity of the Managing General Partner, however, does not have  a
material  impact on the operations of the Partnership.  The  partnership
agreement  of  the Partnership allows the limited partners  to  elect  a
successor managing general partner to continue Partnership operations.

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.   This  statement  has  been  adopted  by   the
partnership  effective  January  1,  2003.   The  transition  adjustment
resulting  from  the  adoption of SFAS No. 143 has been  reported  as  a
cumulative effect of a change in accounting principle

In  April  2003,  the  FASB  issued Statement  of  Financial  Accounting
Standards  No.  149,  Amendment  of  Statement  No.  133  on  Derivative
Instruments  and  Hedging Activities ("SFAS No.  149").   SFAS  No.  149
amendments  require  that contracts with comparable  characteristics  be
accounted  for  similarly,  clarifies when a contract  with  an  initial
investment meets the characteristic of a derivative and clarifies when a
derivative  requires special reporting in the statement of  cash  flows.
SFAS  No. 149 is effective for hedging relationships designated and  for
contracts  entered  into or modified after June  30,  2003,  except  for
provisions  that relate to SFAS No. 133 Statement Implementation  Issues
that  have  been effective for fiscal quarters prior to June  15,  2003,
should  be  applied in accordance with their respective effective  dates
and  certain provisions relating to forward purchases or sales of  when-
issued  securities or other securities that do not yet exist, should  be
applied  to  existing  contracts as well as new contracts  entered  into
after  June  30,  2003.   Assessment by  the  Managing  General  Partner
revealed this pronouncement to have no impact on the partnership.

<PAGE>
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

(a)  Evaluation  of  Disclosure  Controls  and  Procedures.   The  chief
executive  officer  and  chief financial officer  of  the  Partnership's
managing general partner have evaluated the effectiveness of the  design
and  operation  of the Partnership's disclosure controls and  procedures
(as  defined in Exchange Act Rule 13a-14(c)) as of a date within 90 days
of  the  filing date of this quarterly report. Based on that evaluation,
the  chief  executive officer and chief financial officer have concluded
that  the Partnership's disclosure controls and procedures are effective
to  ensure that material information relating to the Partnership and the
Partnership's  consolidated subsidiaries is made known to such  officers
by  others  within these entities, particularly during the  period  this
quarterly  report  was  prepared, in order  to  allow  timely  decisions
regarding required disclosure.

(b)  Changes  in Internal Controls.  There have not been any significant
changes in the Partnership's internal controls or in other factors  that
could  significantly affect these controls subsequent  to  the  date  of
their evaluation.


<PAGE>
                       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:

                     99.1  Certification pursuant to 18  U.S.C.  Section
               1350
               99.2 Certification pursuant to 18 U.S.C. Section 1350

               (b)  Reports on Form 8-K:

                     No  reports  on  Form  8-K were  filed  during  the
               quarter for which this report is filed.
<PAGE>
                                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:  November 12, 2003

<PAGE>

                             CERTIFICATIONS


          I, H.H. Wommack, III, certify that:

          1.   I have reviewed this quarterly report on Form 10-Q/A of Southwest
Royalties, Inc. Income Fund VI;

          2.   Based on my knowledge, this quarterly 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 quarterly report;

          3.   Based on my knowledge, the financial statements, and other
financial information included in this quarterly 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 quarterly report;

          4.   The registrant's other certifying officers and I are responsible
for  establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant  and
we have:

          a)   designed such disclosure controls and procedures 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 quarterly report
          is being prepared;

          b)   evaluated the effectiveness of the registrant's
 disclosure controls
          and procedures as of a date within 90 days prior to the filing date of
          this quarterly report (the "Evaluation Date"); and

          c)   presented in this quarterly report our conclusions about the
          effectiveness of the disclosure controls and procedures based on our
          evaluation as of the Evaluation Date;

          5.   The registrant's other certifying officers and I have disclosed,
based  on  our most recent evaluation, 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 in the design or
operation of internal
          controls which could adversely affect the registrant's ability to
          record, process, summarize and report financial
data and have identified
          for the registrant's auditors any material weaknesses in internal
          controls; 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; and

          6.   The registrant's other certifying officers
and I have indicated in
this  quarterly report whether or not there were significant changes  in
internal  controls  or in other factors that could significantly  affect
internal  controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant deficiencies
and material weaknesses.

Date:  November 12, 2003



/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

<PAGE>
                             CERTIFICATIONS


          I, Bill E. Coggin, certify that:

          1.   I have reviewed this quarterly report on Form 10-Q/A of Southwest
     Royalties, Inc. Income Fund VI;

          2.   Based on my knowledge, this quarterly 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 quarterly report;

          3.   Based on my knowledge, the financial statements, and other
     financial information included in this quarterly 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 quarterly report;

          4.   The registrant's other certifying officers and I are responsible
     for establishing and maintaining disclosure controls and procedures (as
     defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
     we have:

          a)   designed such disclosure controls and procedures 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 quarterly report
          is being prepared;

          b)   evaluated the effectiveness of the registrant's
 disclosure controls
          and procedures as of a date within 90 days prior to the filing date of
          this quarterly report (the "Evaluation Date"); and

          c)   presented in this quarterly report our conclusions about the
          effectiveness of the disclosure controls and procedures based on our
          evaluation as of the Evaluation Date;

          5.   The registrant's other certifying officers and I have disclosed,
     based on our most recent evaluation, 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 in the design or
operation of internal
          controls which could adversely affect the registrant's ability to
          record, process, summarize and report financial
 data and have identified
          for the registrant's auditors any material weaknesses in internal
          controls; 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; and

          6.   The registrant's other certifying officers and I
have indicated in
     this quarterly report whether or not there were significant
changes in
     internal controls or in other factors that could significantly
 affect
     internal controls subsequent to the date of our most
recent evaluation,
     including any corrective actions with regard to s
ignificant deficiencies
     and material weaknesses.

Date:  November 12, 2003



/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

<PAGE>
                        CERTIFICATION PURSUANT TO
                         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/A
for  the  period ending March 31, 2003 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:  November 12, 2003




/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

<PAGE>

                        CERTIFICATION PURSUANT TO
                         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/A
for  the  period ending March 31, 2003 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:  November 12, 2003




/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

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