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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, 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, L.P.
             (Exact name of registrant as specified
             in its limited partnership agreement)

Tennessee                                          75-2127812
(State or other jurisdiction of            (I.R.S. Employer
incorporation or organization)            Identification No.)


                  407 N. Big Spring, Suite 300
                      Midland, Texas 79701
            (Address of principal executive offices)

                        (432) 686-9927
                (Registrant's telephone number,
                      including area code)

Indicate  by  check  mark  whether registrant (1)  has  filed  all  reports
required to be filed by Section 13 or 15(d) of the Securities Exchange  Act
of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject  to
such filing requirements for the past 90 days:

                            Yes      No  X

Indicate  by check mark whether the registrant is an accelerated filer  (as
defined in Rule 12b-2 of the Exchange Act).

                                  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
annual 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 Amendment  No.
1  to its Annual Report on Form 10-K for 2002 filed with the Securities and
Exchange  Commission on November 10, 2003.  The December 31,  2002  balance
sheet included herein has been derived from the Registrant's Amendment  No.
1  to  its Annual Report on Form 10-K for 2002.  Operating results for  the
three  and  six  month  periods ended June 30,  2003  are  not  necessarily
indicative of the results 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.

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  5  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 periods
ended  June 30, 2002, included herein, have been restated (as described  in
Notes  4  and  5 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 periods ended June  30,
2002.

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

                                         June 30,  December
                                                      31,
                                           2003      2002
                                          ------    ------
                                         (unaudit
                                            ed)
Assets
---------
Current assets:
 Cash and cash equivalents            $  132,287   18,015
  Receivable  from  Managing  General    260,665   86,014
Partner
 Distribution receivable                 205       -
                                         --------  --------
                                         ----      ----
   Total current assets                  393,157   104,029
                                         --------  --------
                                         ----      ----
Oil  and  gas properties - using  the
full-
 cost method of accounting               8,572,75  8,424,13
                                         2         4
  Less accumulated depreciation,
   depletion and amortization            6,079,46  6,481,00
                                         0         0
                                         --------  --------
                                         ----      ----
   Net oil and gas properties            2,493,29  1,943,13
                                         2         4
                                         --------  --------
                                         ----      ----
                                      $  2,886,44  2,047,16
                                         9         3
                                         =======   =======
Liabilities and Partners' Equity
-------------------------------------
---
Current   liability  -   distribution $  -         3,356
payable
                                         --------  --------
                                         ----      ----
Other long term liabilities              519,820   -
                                         --------  --------
                                         ----      ----
Partners' equity:
 General partner                         (617,668  (649,950
                                         )         )
 Limited partners                        2,984,29  2,693,75
                                         7         7
                                         --------  --------
                                         ----      ----
   Total partners' equity                2,366,62  2,043,80
                                         9         7
                                         --------  --------
                                         ----      ----
                                      $  2,886,44  2,047,16
                                         9         3
                                         =======   =======
<PAGE>
                 Southwest Royalties, Inc. Income Fund VI
                         Statements of Operations
                                (unaudited)

                                 Three Months Ended    Six Months Ended
                                      June 30,             June 30,
                                   2003      2002      2003       2002
                                           (Restate             (Restated
                                              d)                    )
                                  -----     -----      -----      -----
Revenues
-------------
Income   from  net   profits  $  331,408   (7,172)   628,687    10,615
interests
Interest                         373       328       391        695
Miscellaneous settlement         -         581       -          581
                                 --------  --------  ---------  ---------
                                 --        --        -          --
                                 331,781   (6,263)   629,078    11,891
                                 --------  --------  ---------  ---------
                                 --        --        -          --
Expenses
------------
General and administrative       49,424    36,966    86,900     75,092
Depreciation, depletion  and     38,000    38,000    66,000     73,000
amortization
Accretion      of      asset     9,997     -         19,993     -
retirement obligation
                                 --------  --------  ---------  ---------
                                 --        --        -          --
                                 97,421    74,966    172,893    148,092
                                 --------  --------  ---------  ---------
                                 --        --        -          --
Net   income  (loss)  before     234,360   (81,229)  456,185    (136,201)
cumulative effects

Cumulative effect of  change
in accounting
  principle - SFAS No. 143 -     -         -         116,637    -
See Note 3
Cumulative effect of  change
in accounting principle
   -   change  in  depletion     -         -         -          530,000
method - See Note 4
                                 --------  --------  ---------  ---------
                                 --        --        -          --
Net income (loss)             $  234,360   (81,229)  572,822    393,799
                                 ======    ======    ======     ======
Net  income (loss) allocated
to:
 Managing General Partner     $  23,436    (7,311)   57,282     35,442
                                 ======    ======    ======     ======
 General Partner              $  -         (812)     -          3,938
                                 ======    ======    ======     ======
 Limited Partners             $  210,924   (73,106)  515,540    354,419
                                 ======    ======    ======     ======
   Per  limited partner unit  $    10.55                        (6.13)
before cumulative effect                   (3.66)    20.53
    Cumulative  effects  per           -        -         5.25
limited partner unit                                            23.85
                                 --------  --------  ---------  ---------
                                 --        --        -          --
  Per limited partner unit    $    10.55
                                           (3.66)    25.78      17.72
                                 ======    ======    ======     ======
Pro  forma amounts  assuming
changes are applied
 retroactively (See Note3)
  Net  income (loss)  before  $  -         (90,426)  -          (154,595)
cumulative effect
                                 ======    ======    ======     ======
   Per  limited partner unit  $  -         (4.07)    -          (6.96)
(20,000.0)
                                 ======    ======    ======     ======
 Net income (loss)            $  -         (90,426)  -          375,405
                                 ======    ======    ======     ======
   Per  limited partner unit  $  -         (4.07)    -           16.89
(20,000.0)
                                 ======    ======    ======     ======
<PAGE>
                 Southwest Royalties, Inc. Income Fund VI
                         Statements of Cash Flows
                                (unaudited)

                                       Six Months Ended
                                           June 30,
                                        2003      2002
                                                (Restate
                                                   d)
                                        ----      ----
Cash    flows   from    operating
activities:

  Cash received from income  from
net
  profits interests                $  407,687   28,892
 Cash paid to suppliers               (40,551)  (45,302)
 Interest received                    391       695
 Miscellaneous settlement             -         581
                                      --------  --------
                                      --        --
   Net cash provided by (used in)     367,527   (15,134)
operating activities
                                      --------  --------
                                      --        --
Cash  flows provided by investing
activities:
 Sale of oil and gas properties       306       -
                                      --------  --------
                                      --        --
Cash   flows  used  in  financing
activities:
 Distributions to partners            (253,561  (7)
                                      )
                                      --------  --------
                                      --        --
Net  increase (decrease) in  cash     114,272   (15,141)
and cash equivalents

Beginning of period                   18,015    132,282
                                      --------  --------
                                      --        --
End of period                      $  132,287   117,141
                                      ======    ======
Reconciliation of net  income  to
net
   cash  provided  by  (used  in)
operating activities:

Net income                         $  572,822   393,799

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

   Depreciation,  depletion   and     66,000    73,000
amortization
  Accretion  of asset  retirement     19,993    -
obligation
  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)    decrease    in     (221,000  18,277
receivables                           )
 Increase in payables                 46,349    29,790
                                      --------  --------
                                      --        --
Net  cash  provided by (used  in)  $  367,527   (15,134)
operating activities
                                      ======    ======
Non  cash investing and financing
activities::

   Increase   in  oil   and   gas
properties - Adoption
  of SFAS No. 143                  $  616,464   -
                                      ======    ======
<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.  Revenues, costs and  expenses
    are allocated as follows:
                              Limited   General
                              Partners  Partners
                              --------  --------
Interest  income on  capital  100%      -
contributions
Oil and gas sales             90%       10%
All other revenues            90%       10%
Organization  and   offering  100%      -
costs (1)
Amortization of organization  100%      -
costs
Property acquisition costs    100%      -
Gain/loss    on     property  90%       10%
disposition
Operating and administrative  90%       10%
costs (2)
Depreciation, depletion  and
amortization
 of oil and gas properties    90%       10%
All other costs               90%       10%

         (1)All  organization  costs in excess of  3%  of  initial  capital
         contributions  will  be paid by the Managing General  Partner  and
         will  be treated as a capital contribution.  The Partnership  paid
         the  Managing  General Partner an amount equal to  3%  of  initial
         capital contributions for such organization costs.

         (2)Administrative  costs in any year which exceed  2%  of  capital
         contributions  shall be paid by the Managing General  Partner  and
         will be treated as a capital contribution.

2.   Summary of Significant Accounting Policies
     The  interim  financial information as of June 30, 2003, and  for  the
     three  and  six  months  ended June 30, 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  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
     Amendment  No. 1 to its Annual Report on Form 10-K for the year  ended
     December 31, 2002, filed with the SEC on November 10, 2003.

3.   Cumulative effect of change in accounting principle - SFAS No. 143
     On  January  1, 2003, the Partnership adopted Statement  of  Financial
     Accounting   Standards  No.  143,  Accounting  for  Asset   Retirement
     Obligations  ("SFAS No. 143").  Adoption of SFAS No. 143  is  required
     for  all  companies with fiscal years beginning after June  15,  2002.
     The new standard requires the Partnership to recognize a liability for
     the  present  value  of  all  legal obligations  associated  with  the
     retirement  of tangible long-lived assets and to capitalize  an  equal
     amount as a cost of the asset and depreciate the additional cost  over
     the  estimated  useful  life of the asset.  On January  1,  2003,  the
     Partnership    recorded   additional   costs,   net   of   accumulated
     depreciation,  of  approximately $616,464, a long  term  liability  of
     approximately  $499,827 and a gain of approximately $116,637  for  the
     cumulative  effect  on  depreciation  of  the  additional  costs   and
     accretion  expense  on  the liability related to expected  abandonment
     costs  of  its oil and natural gas producing properties.  At June  30,
     2003,  the asset retirement obligation was $519,820, and the  increase
     in  the  balance from January 1, 2003 of $19,993 is due  to  accretion
     expense.   The  pro forma amounts for the three and six  months  ended
     June  30,  2002, which are presented on the face of the statements  of
     operations, reflect the effect of retroactive application of SFAS  No.
     143.

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

                      Notes to Financial Statements

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 and six months ended  June  30,
     2003  and  2002  has  been  calculated using  the  units-of-production
     method.   The  effect of the change on the three and six months  ended
     June  30,  2002 was to decrease income before cumulative effect  of  a
     change  in accounting principle by $7,000 and $22,000 ($.32  and  $.99
     per  limited partner unit), respectively and decrease and increase net
     income  by  $7,000 and $508,000 ($.32 and $22.86 per  limited  partner
     unit), respectively.

5.   June 30, 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.

     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 and six months ended June 30, 2002.

                           Three Months Ended      Six Months Ended
                                    Previousl               Previousl
                                        y                       y
                          Restated   Reported     Restated  Reported
  Depreciation,
  depletion and
  amortization             $38,000  31,000        73,000    51,000
  Loss before cumulative  (81,229)  (74,229)      (136,201  (114,201)
  effect                                          )
Cumulative effect of
  change in
  accounting principle    -         -             530,000   -
  Net income (loss)       (81,229)  (74,229)      393,799   (114,201)
  Net income (loss)
  allocated to:
  Managing General        (7,311)   (6,681)       35,442    (10,278)
  Partner
  General partner         (812)     (742)         3,938     (1,142)
  Limited partners        (73,106)  (66,806)      354,419   (102,781)
   Income (loss) per
  limited partner
     unit before          (3.66)
  cumulative effect                 (3.34)        (6.13)    (5.14)
   Cumulative effect
  per limited
     partner unit              -         -                       -
                                                  23.85
   Net income (loss)
  per limited
     partner unit         (3.66)
                                    (3.34)        17.72     (5.14)

<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.

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.

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, 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
June  30,  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 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  estimating  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  may  not be 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.

<PAGE>
Results of Operations

A.  General Comparison of the Quarters Ended June 30, 2003 and 2002

The  following  table  provides certain information  regarding  performance
factors for the quarters ended June 30, 2003 and 2002:

                                         Three Months
                                            Ended         Percenta
                                                             ge
                                           June 30,       Increase
                                        2003      2002    (Decreas
                                                             e)
                                       -----     -----    --------
                                                             --
Average price per barrel of oil    $  28.48               17%
                                                24.28
Average price per mcf of gas       $   4.93               61%
                                                3.06
Oil production in barrels             6,400     6,800     (6%)
Gas production in mcf                 74,800    74,600    -
Income from net profits interests  $  331,408   (7,172)   4,721%
Partnership distributions          $  250,000   -         100%
Limited partner distributions      $  225,000   -         100%
Per unit distribution to limited
 partners                          $  11.25          -    100%
Number of limited partner units       20,000    20,000

Revenues

The  Partnership's income from net profits interests increased to  $331,408
from  $(7,172) for the quarters ended June 30, 2003 and 2002, respectively,
an  increase of 4,721%.  The principal factors affecting the comparison  of
the quarters ended June 30, 2003 and 2002 are as follows:

1.  The  average  price  for a barrel of oil received  by  the  Partnership
    increased  during the quarter ended June 30, 2003 as  compared  to  the
    quarter  ended June 30, 2002 by 17%, or $4.20 per barrel, resulting  in
    an  increase  of  approximately $26,900  in  income  from  net  profits
    interests.  Oil sales represented 33% of total oil and gas sales during
    the  quarter ended June 30, 2003 as compared to 42% during the  quarter
    ended June 30, 2002.

    The  average  price  for  an  mcf of gas received  by  the  Partnership
    increased during the same period by 61%, or $1.87 per mcf, resulting in
    an  increase  of  approximately $139,900 in  income  from  net  profits
    interests.

    The  total  increase in income from net profits interests  due  to  the
    change  in prices received from oil and gas production is approximately
    $166,800.  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.

<PAGE>
2.  Oil  production decreased approximately 400 barrels or  6%  during  the
    quarter  ended June 30, 2003 as compared to the quarter ended June  30,
    2002,  resulting in a decrease of approximately $9,700 in  income  from
    net profits interests.

    Gas  production increased approximately 200 mcf or less than 1%  during
    the  same  period,  resulting in an increase of approximately  $600  in
    income from net profits interests.

    The  net total decrease in income from net profits interests due to the
    change in production is approximately $9,100.

3.  Lease  operating  costs  and  production  taxes  were  45%  lower,   or
    approximately $180,800 less during the quarter ended June 30,  2003  as
    compared  to  the quarter ended June 30, 2002.  The decrease  in  lease
    operating expense is due to workover and maintenance performed  on  one
    lease during the quarter ended June 30, 2003.

Costs and Expenses

Total costs and expenses increased to $97,421 from $74,966 for the quarters
ended  June  30,  2003  and 2002, respectively, an increase  of  30%.   The
increase  is  the result of higher general and administrative  expense  and
accretion expense.

1.  General  and  administrative costs consists of independent  accounting,
    legal  and  engineering fees, computer services, postage, and  Managing
    General  Partner  personnel costs.  General  and  administrative  costs
    increased  34% or approximately $12,500 during the quarter  ended  June
    30,  2003 as compared to the quarter ended June 30, 2002.  The increase
    in  general  and  administrative expense  is  due  to  an  increase  in
    independent accounting review and audit fees and legal fees  associated
    with  the  amendments  to the Partnership's December  31,  2002  Annual
    Report on Form 10-K and March 31, 2003 Quarterly Report on Form 10-Q.

2.  Depletion  expense remained unchanged for the quarter  ended  June  30,
    2003  compared  to the same period in 2002.  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 June 30, 2002  by
    $7,000 and decrease net income for the three months ended June 30, 2002
    by $7,000.

<PAGE>
B.   General  Comparison of the Six Month Periods Ended June 30,  2003  and
2002

The  following  table  provides certain information  regarding  performance
factors for the six month periods ended June 30, 2003 and 2002:

                                     Six Months
                                       Ended         Percenta
                                                        ge
                                      June 30,       Increase
                                   2003      2002    (Decreas
                                                        e)
                                   ----      ----    --------
                                                        --
Average price per barrel  of  $    30.08             37%
oil                                        22.02
Average price per mcf of gas  $     5.39             106%
                                           2.62
Oil production in barrels        11,000    13,100    (16%)
Gas production in mcf            129,600   147,200   (12%)
Income   from  net   profits  $  628,687   10,615    5,823%
interests
Partnership distributions     $  250,000   -         100%
Limited              partner  $  225,000   -         100%
distributions
Per  unit  distribution   to
limited
 partners                     $    11.25        -    100%
Number  of  limited  partner     20,000    20,000
units

Revenues

The  Partnership's income from net profits interests increased to  $628,687
from $10,615 for the six months ended June 30, 2003 and 2002, respectively,
an  increase of 5,823%.  The principal factors affecting the comparison  of
the six months ended June 30, 2003 and 2002 are as follows:

1.  The  average  price  for a barrel of oil received  by  the  Partnership
    increased during the six months ended June 30, 2003 as compared to  the
    six  months ended June 30, 2002 by 37%, or $8.06 per barrel,  resulting
    in  an  increase  of approximately $88,700 in income from  net  profits
    interests.  Oil sales represented 32% of total oil and gas sales during
    the  six  months ended June 30, 2003 as compared to 43% during the  six
    months ended June 30, 2002.

    The  average  price  for  a  mcf  of gas received  by  the  Partnership
    increased  during the same period by 106%, or $2.77 per mcf,  resulting
    in  an  increase of approximately $359,000 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
    $447,700.  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 2,100 barrels or 16% during the
    six months ended June 30, 2003 as compared to the six months ended June
    30,  2002,  resulting in a decrease of approximately $46,200 in  income
    from net profits interests.

    Gas  production  decreased approximately 17,600 mcf or 12%  during  the
    same period, resulting in a decrease of approximately $46,100 in income
    from net profits interests.

    The  total  decrease in income from net profits interests  due  to  the
    change  in  production is approximately $92,300.  The decrease  in  oil
    production is in connection with a change in estimate.  The Partnership
    was  receiving production in error on a well that we did  not  have  an
    interest, the production belonged to another well on a different  lease
    that the Partnership owned a very small interest of the production.

3.  Lease  operating  costs  and  production  taxes  were  40%  lower,   or
    approximately $263,100 less during the six months ended June  30,  2003
    as  compared  to the six months ended June 30, 2002.  The  decrease  in
    lease  operating expense is due to a workover and maintenance performed
    on one lease during the six months ended June 30, 2003.

Costs and Expenses

Total  costs and expenses increased to $172,893 from $148,092 for  the  six
months ended June 30, 2003 and 2002, respectively, an increase of 17%.  The
increase  is the result of a higher general and administrative expense  and
accretion expense, partially offset by a decrease in depletion expense.

1.  General  and  administrative costs consists of independent  accounting,
    legal  and  engineering fees, computer services, postage, and  Managing
    General  Partner  personnel costs.  General  and  administrative  costs
    increased 16% or approximately $11,800 during the six months ended June
    30,  2003  as  compared to the six months ended  June  30,  2002.   The
    increase in general and administrative expense is due to an increase in
    independent accounting review and audit fees and legal fees  associated
    with  the  amendments  to the Partnership's December  31,  2002  Annual
    Report on Form 10-K and March 31, 2003 Quarterly Report on Form 10-Q.

2.  Depletion  expense decreased to $66,000 for the six months  ended  June
    30,  2003 from $73,000 for the same period in 2002.  This represents  a
    decrease  of  10%.   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 six
    months  ended June 30, 2002 by $22,000 and increase net income for  the
    six months ended June 30, 2002 by $508,000.  The contributing factor to
    the  decrease in depletion expense is in relation to the BOE  depletion
    rate for the six months ended June 30, 2003, which was $2.02 applied to
    32,600  BOE  as compared to $1.94 applied to 37,633 BOE  for  the  same
    period.

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  June  30,  2003,  the  asset
retirement  obligation was $519,820, and the increase in the  balance  from
January  1,  2003 of $19,993 is due to accretion expense.   The  pro  forma
amounts  for  the  three  and six months ended June  30,  2002,  which  are
presented  on the face of the statements of operations, reflect the  effect
of retroactive application of SFAS No. 143.

<PAGE>
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
$367,500 in the six months ended June 30, 2003 as compared to approximately
$(15,100) in the six months ended June 30, 2002.  The primary source of the
2003 cash flows from operating activities was profitable operations.

Cash flows provided by investing activities were approximately $300 in  the
six  months  ended June 30, 2003 compared to none in the six  months  ended
June  30,  2002.  The principle source of the 2003 cash flow from investing
activities was the sale of an oil and gas property.

Cash flows used in financing activities were approximately $253,600 in  the
six  months  ended June 30, 2003 compared to no distributions  in  the  six
months  ended June 30, 2002. The only use in financing activities  was  the
distributions to partners.

Total distributions during the six months ended June 30, 2003 were $250,000
of  which  $225,000 was distributed to the limited partners and $25,000  to
the  general partner. The per unit distribution to limited partners  during
the six months ended June 30, 2003 was $11.25.  There were no material cash
flows  used  in financing activities during the six months ended  June  30,
2002.

The  sources  for  the  2003 distributions of $250,000  were  oil  and  gas
operations  of  approximately  $367,500 and  the  change  in  oil  and  gas
properties   of   approximately  $300,  resulting  in   excess   cash   for
contingencies or subsequent distributions.

Since  inception of the Partnership, cumulative monthly cash  distributions
of  $17,703,854  have  been made to the partners.  As  of  June  30,  2003,
$15,949,177 or $797.46 per limited partner unit has been distributed to the
limited  partners,  representing a 100% return of the  capital  and  a  59%
return on capital contributed.

As  of June 30, 2003, the Partnership had approximately $393,200 in working
capital.   The  Managing  General Partner knows of no  unusual  contractual
commitments.   Although the partnership held many long-lived properties  at
inception,  because of the restrictions on property development imposed  by
the partnership agreement, the Partnership cannot develop its non producing
properties, if any.  Without continued development, the producing  reserves
continue  to  deplete.  Accordingly, as the Partnership's  properties  have
matured  and  depleted,  the  net  cash  flows  from  operations  for   the
partnership  has  steadily  declined, except in  periods  of  substantially
increased  commodity pricing.  Maintenance of properties and administrative
expenses for the Partnership are increasing relative to production.  As the
properties   continue   to   deplete,   maintenance   of   properties   and
administrative costs as a percentage of production are expected to continue
to increase.

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,  the
Managing General Partner 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.

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.

In  May  2003, the FASB issued Statement of Financial Accounting  Standards
No.150,  Accounting for Certain Financial Instruments with  Characteristics
of  both  Liabilities  and  Equity  ("SFAS  150").   SFAS  150  establishes
standards  for  how  an  issuer classifies and measures  certain  financial
instruments  with  characteristics of  both  liabilities  and  equity.   It
requires that an issuer classify a financial instrument that is within  the
scope of SFAS 150 as a liability (or an asset in some circumstances).  Many
of those instruments were previously classified as equity.  The application
of  SFAS 150 is not expected to have a material effect on the Partnership's
consolidated  financial  statements.   This  Statement  is  effective   for
financial  instruments entered into or modified after  May  31,  2003,  and
otherwise  is  effective  at  the beginning of  the  first  interim  period
beginning after June 15, 2003.

<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:

               31.1 Rule 13a-14(a)/15d-14(a) Certification
31.2 Rule 13a-14(a)/15d-14(a) Certification
               32.1 Certification of Chief Executive Officer
Pursuant to 18 U.S.C. Section
                  1350, as
                  adopted  Pursuant  to Section 906 of  the  Sarbanes-Oxley
                  Act of 2002
               32.2 Certification of Chief Financial Officer Pursuant to
 18 U.S.C. Section
                  1350, as
                  adopted Pursuant to Section 906 of the Sarbanes-Oxley Act
               of 2002

          (b) Reports on Form 8-K:

               No  reports on Form 8-K were filed during the quarter  ended
               June 30, 2003.
<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>
                    SECTION 302 CERTIFICATION                Exhibit 31.1


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

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

2.Based  on my knowledge, this report does not contain any untrue statement
  of  a  material fact or omit to state a material fact necessary  to  make
  the  statements  made,  in light of the circumstances  under  which  such
  statements  were made, not misleading with respect to the period  covered
  by this report;

3.Based  on  my  knowledge, the financial statements, and  other  financial
  information  included  in  this report, fairly present  in  all  material
  respects  the financial condition, results of operations and  cash  flows
  of the registrant as of, and for, the periods presented in this report;

4.The  registrant's other certifying officer(s) and I are  responsible  for
  establishing  and  maintaining disclosure  controls  and  procedures  (as
  defined  in  Exchange  Act  Rules 13a-15(e) and  15-15(e))  and  internal
  control  over financial reporting (as defined in Exchange Act Rules  13a-
  15(f) and 15d-15(f) for the registrant and have:

  a)Designed  such  disclosure  controls and  procedures,  or  caused  such
     disclosure   controls  and  procedures  to  be  designed   under   our
     supervision,  to  ensure  that material information  relating  to  the
     registrant, including its consolidated subsidiaries, is made known  to
     us  by others within those entities, particularly during the period in
     which this report is being prepared;

  b)Designed  such  internal control over financial  reporting,  or  caused
     such  internal  control over financial reporting to be designed  under
     our   supervision,  to  provide  reasonable  assurance  regarding  the
     reliability  of financial reporting and the preparation  of  financial
     statements for external purposes in accordance with generally accepted
     accounting principles;

  c)Evaluated  the  effectiveness of the registrant's  disclosure  controls
     and  procedures and presented in this report our conclusions about the
     effectiveness of the disclosure controls and procedures, as of the end
     of the period covered by this report based on such evaluation; and

  d)Disclosed  in  this  report  any change in  the  registrant's  internal
     control over financial reporting that occurred during the registrant's
     most recent fiscal quarter (the registrant's fourth fiscal quarter  in
     the  case  of  an annual report) that has materially affected,  or  is
     reasonably  likely  to  materially affect, the  registrant's  internal
     control over financial reporting; and

5.The  registrant's other certifying officer(s) and I have disclosed, based
  on  our  most  recent  evaluation  of  internal  control  over  financial
  reporting,  to  the  registrant's auditors and  the  audit  committee  of
  registrant's  board  of directors (or persons performing  the  equivalent
  functions):

  a)All  significant deficiencies and material weaknesses in the design  or
     operation   of  internal  controls  over  financial  reporting   which
     reasonably  likely  to  adversely affect the registrant's  ability  to
     record, process, summarize and report financial information; and

  b)Any  fraud, whether or not material, that involves management or  other
     employees  who  have  a significant role in the registrant's  internal
     controls over financial reporting.


Date:  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 V

<PAGE>
                    SECTION 302 CERTIFICATION                Exhibit 31.2


I, Bill E. Coggin, certify that:

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

2.Based  on my knowledge, this report does not contain any untrue statement
  of  a  material fact or omit to state a material fact necessary  to  make
  the  statements  made,  in light of the circumstances  under  which  such
  statements  were made, not misleading with respect to the period  covered
  by this report;

3.Based  on  my  knowledge, the financial statements, and  other  financial
  information  included  in  this report, fairly present  in  all  material
  respects  the financial condition, results of operations and  cash  flows
  of the registrant as of, and for, the periods presented in this report;

4.The  registrant's other certifying officer(s) and I are  responsible  for
  establishing  and  maintaining disclosure  controls  and  procedures  (as
  defined  in  Exchange  Act  Rules 13a-15(e) and  15-15(e))  and  internal
  control  over financial reporting (as defined in Exchange Act Rules  13a-
  15(f) and 15d-15(f) for the registrant and have:

  a)Designed  such  disclosure  controls and  procedures,  or  caused  such
     disclosure   controls  and  procedures  to  be  designed   under   our
     supervision,  to  ensure  that material information  relating  to  the
     registrant, including its consolidated subsidiaries, is made known  to
     us  by others within those entities, particularly during the period in
     which this report is being prepared;

  b)Designed  such  internal control over financial  reporting,  or  caused
     such  internal  control over financial reporting to be designed  under
     our   supervision,  to  provide  reasonable  assurance  regarding  the
     reliability  of financial reporting and the preparation  of  financial
     statements for external purposes in accordance with generally accepted
     accounting principles;

  c)Evaluated  the  effectiveness of the registrant's  disclosure  controls
     and  procedures and presented in this report our conclusions about the
     effectiveness of the disclosure controls and procedures, as of the end
     of the period covered by this report based on such evaluation; and

  d)Disclosed  in  this  report  any change in  the  registrant's  internal
     control over financial reporting that occurred during the registrant's
     most recent fiscal quarter (the registrant's fourth fiscal quarter  in
     the  case  of  an annual report) that has materially affected,  or  is
     reasonably  likely  to  materially affect, the  registrant's  internal
     control over financial reporting; and

5.The  registrant's other certifying officer(s) and I have disclosed, based
  on  our  most  recent  evaluation  of  internal  control  over  financial
  reporting,  to  the  registrant's auditors and  the  audit  committee  of
  registrant's  board  of directors (or persons performing  the  equivalent
  functions):

  a)All  significant deficiencies and material weaknesses in the design  or
     operation   of  internal  controls  over  financial  reporting   which
     reasonably  likely  to  adversely affect the registrant's  ability  to
     record, process, summarize and report financial information; and

  b)Any  fraud, whether or not material, that involves management or  other
     employees  who  have  a significant role in the registrant's  internal
     controls over financial reporting.


Date:  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 TOExhibit 32.1
                          19 U.S.C. SECTION 1350,
                          AS ADOPTED PURSUANT TO
               SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002


      In  connection with the Quarterly Report of Southwest Royalties, Inc.
Income  Fund VI, Limited Partnership (the "Company") on Form 10-Q  for  the
period  ending  June  30,  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 TOExhibit 32.2
                          19 U.S.C. SECTION 1350,
                          AS ADOPTED PURSUANT TO
               SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002


      In  connection with the Quarterly Report of Southwest Royalties, Inc.
Income  Fund VI, Limited Partnership (the "Company") on Form 10-Q  for  the
period  ending  June  30,  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

<PAGE>