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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 September 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
                  (Exact name of registrant as specified
                   in its limited partnership agreement)

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

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

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

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

                            Yes __X__ No _____

Indicate  by  check  mark whether 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  nine month periods ended September 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 September 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 September
30, 2002.

<PAGE>

                 Southwest Royalties, Inc. Income Fund VI
                              Balance Sheets

                                         Septembe  December
                                           r 30,      31,
                                           2003      2002
                                          ------    ------
                                         (unaudit
                                            ed)
Assets
---------
Current assets:
 Cash and cash equivalents            $  201,050   18,015
  Receivable  from  Managing  General    194,105   86,014
Partner
                                         --------  --------
                                         ----      ----
   Total current assets                  395,155   104,029
                                         --------  --------
                                         ----      ----
Oil  and  gas properties - using  the
full-
 cost method of accounting               8,547,31  8,424,13
                                         7         4
  Less accumulated depreciation,
   depletion and amortization            6,116,46  6,481,00
                                         0         0
                                         --------  --------
                                         ----      ----
   Net oil and gas properties            2,430,85  1,943,13
                                         7         4
                                         --------  --------
                                         ----      ----
                                      $  2,826,01  2,047,16
                                         2         3
                                         =======   =======
Liabilities and Partners' Equity
-------------------------------------
---
Current   liability  -   distribution $  -         3,356
payable
                                         --------  --------
                                         ----      ----
Other long term liabilities              503,893   -
                                         --------  --------
                                         ----      ----
Partners' equity:
 General partner                         (622,119  (649,950
                                         )         )
 Limited partners                        2,944,23  2,693,75
                                         8         7
                                         --------  --------
                                         ----      ----
   Total partners' equity                2,322,11  2,043,80
                                         9         7
                                         --------  --------
                                         ----      ----
                                      $  2,826,01  2,047,16
                                         2         3
                                         =======   =======

<PAGE>

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

                                  Three Months Ended    Nine Months
                                                           Ended
                                    September 30,      September 30,
                                   2003       2002     2003    2002
                                            (Restate          (Restat
                                               d)               ed)
                                   ----       ----     ----    ----
Revenues
-------------
Income from net profits        $ 292,321    3,430     921,00  14,046
interests                                             8
Interest                         379        322       770     1,017
Miscellaneous settlement         -          -         -       581
                                 ---------  --------  ------  -------
                                 -          --        ----    ---
                                 292,700    3,752     921,77  15,644
                                                      8
                                 ---------  --------  ------  -------
                                 -          --        ----    ---
Expenses
------------
General and administrative       40,611     38,469    127,51  113,562
                                                      1
Depreciation, depletion and      37,000     24,000    103,00  97,000
amortization                                          0
Accretion of asset retirement    9,508      -         29,501  -
obligation
                                 ---------  --------  ------  -------
                                 -          --        ----    ---
                                 87,119     62,469    260,01  210,562
                                                      2
                                 ---------  --------  ------  -------
                                 -          --        ----    ---
Net income (loss) before         205,581    (58,717)  661,76  (194,91
cumulative effects                                    6       8)

Cumulative effect of change in
accounting
 principle - SFAS No. 143 -      -          -         116,63  -
See Note 3                                            7
Cumulative effect of change in
accounting principle
 - change in depletion method    -          -         -       530,000
- See Note 4
                                 ---------  --------  ------  -------
                                 -          --        ----    ---
Net income (loss)              $ 205,581    (58,717)  778,40  335,082
                                                      3
                                 ======     ======    ======  ======
Net income (loss) allocated
to:

Managing General Partner       $ 20,558     (5,872)   77,840  33,508
                                 ======     ======    ======  ======
Limited Partners               $ 185,023    (52,845)  700,56  301,574
                                                      3
                                 ======     ======    ======  ======
 Per limited partner unit      $    9.25      (2.64)  29.78   (8.77)
before cumulative effect
 Cumulative effect per limited         -          -    5.25    23.85
partner unit
                                 ---------  --------  ------  -------
                                 -          --        ----    ---
 Per limited partner unit      $    9.25      (2.64)  35.03    15.08
                                 ======     ======    ======  ======
Pro forma amounts assuming
change is applied
 retroactively (See Note 3):
 Net income (loss) before      $ -          (67,913)  -       (222,50
cumulative effect                                             8)
                                 ======     ======    ======  ======
  Per limited partner unit     $ -            (3.05)  -       (10.01)
(20,000.0)
                                 ======     ======    ======  ======
 Net income (loss)             $ -          (67,913)  -       (307,49
                                                              2)
                                 ======     ======    ======  ======
  Per limited partner unit     $ -            (3.05)  -       13.84
(20,000.0)
                                 ======     ======    ======  ======

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

                                                    Nine Months Ended
                                                      September 30,
                                                     2003       2002
                                                              (Restated
                                                                  )
                                                     ----       ----
          Cash flows from operating activities
          Cash received from income from net    $  748,132    55,591
          profits interests
          Cash paid to suppliers                   (62,726)   (71,992)
          Interest received                        770        1,017
          Miscellaneous settlement                 -          581
                                                   ---------  ---------
                                                   -          -
           Net cash provided by (used in)          686,176    (14,803)
          operating activities
                                                   ---------  ---------
                                                   -          -
          Cash flows provided by investing
          activities:
          Sale of oil and gas properties           306        -
                                                   ---------  ---------
                                                   -          -
          Cash flows used in financing
          activities
          Distributions to partners                (503,447)  (7)
                                                   ---------  ---------
                                                   -          -
           Net increase (decrease) in cash and     183,035    (14,810)
          cash equivalents

          Beginning of period                      18,015     132,282
                                                   ---------  ---------
                                                   -          -
          End of period                         $  201,050    117,472
                                                   ======     ======
          Reconciliation of net income to net
          cash
          provided by (used in) operating
          activities
          Net income                            $  778,403    335,082

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

          Depreciation, depletion and              103,000    97,000
          amortization
          Accretion of asset retirement            29,501     -
          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 receivables       (172,871)  41,545
          Increase in payables                     64,780     41,570
                                                   ---------  ---------
                                                   -          -
          Net cash provided by (used in)        $  686,176    (14,803)
          operating activities
                                                   ======     ======
          Noncash investing and financing
          activities:
          Increase in oil and properties -
          Adoption
           of SFAS No. 143                      $  616,464    -
                                                   ======     ======
          Increase in oil and gas properties -
          SFAS No. 143
           additional wells from farm-out       $  422        -
          arrangements
                                                   ======     ======
          Decrease in oil and gas properties -
          SFAS No. 143
           sale of property                     $  (25,857)   -
                                                   ======     ======
<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 September 30, 2003,  and  for
     the  three  and  nine months ended September 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 September
     30,  2003, the asset retirement obligation was $503,893.  The increase
     in  the  asset retirement obligation from January 1, 2003  is  due  to
     accretion  expense  of $29,501 plus additional wells  added  for  $422
     offset by decrease of $25,857 due to the sale of properties.  The  pro
     forma  amounts for the three and nine months ended September 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 nine months ended  September
     30,  2003  and  2002 has been calculated using the units-of-production
     method.   The effect of the change on the three and nine months  ended
     September 30, 2002 was to decrease income before cumulative effect  of
     a change in accounting principle by $6,000 and $28,000 ($.27 and $1.26
     per  limited partner unit), respectively and decrease and increase net
     income  by  $6,000 and $502,000 ($.27 and $22.59 per  limited  partner
     unit), respectively.

5.   September 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 nine months ended September 30, 2002.

                           Three Months Ended      Nine Months Ended
                                    Previousl               Previousl
                                        y                       y
                          Restated   Reported     Restated  Reported
  Depreciation,
  depletion and
  amortization             $24,000  18,000        97,000    69,000
  Loss before cumulative  (58,717)  (52,717)      (194,918  (166,918)
  effect                                          )
Cumulative effect of
  change in
  accounting principle    -         -             530,000   -
  Net income (loss)       (58,717)  (52,717)      335,082   (166,918)
  Net income (loss)
  allocated to:
  Managing General        (5,872)   (5,272)       33,508    (16,692)
  Partner
  Limited partners        (52,845)  (47,445)      301,574   (150,226)
   Income (loss) per
  limited partner
     unit before          (2.64)
  cumulative effect                 (2.37)        (8.77)    (7.51)
   Cumulative effect
  per limited
     partner unit              -         -                       -
                                                  23.85
   Net income (loss)
  per limited
     partner unit         (2.64)
                                    (2.37)        15.08     (7.51)

<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 September 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
September 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 September 30, 2003 and 2002

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

                                         Three Months
                                            Ended         Percenta
                                                             ge
                                        September 30,     Increase
                                        2003      2002    (Decreas
                                                             e)
                                       -----     -----    --------
                                                             --
Average price per barrel of oil    $  29.62               9%
                                                27.08
Average price per mcf of gas       $   4.52               47%
                                                3.07
Oil production in barrels             5,300     6,500     (18%)
Gas production in mcf                 78,900    40,400    95%
Income from net profits interests  $  292,321   3,430     8,422%
Partnership distributions          $  250,091   -         100%
Limited partner distributions      $  225,082   -         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  $292,321
from   $3,430  for  the  quarters  ended  September  30,  2003  and   2002,
respectively,  an increase of 8,422%.  The principal factors affecting  the
comparison  of  the  quarters ended September 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 September 30, 2003 as  compared  to
    the  quarter  ended  September 30, 2002 by 9%,  or  $2.54  per  barrel,
    resulting  in an increase of approximately $13,500 in income  from  net
    profits  interests.  Oil sales represented 31% of  total  oil  and  gas
    sales  during the quarter ended September 30, 2003 as compared  to  59%
    during the quarter ended September 30, 2002.

    The  average  price  for  an  mcf of gas received  by  the  Partnership
    increased during the same period by 47%, or $1.45 per mcf, resulting in
    an  increase  of  approximately $114,400 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
    $127,900.  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 1,200 barrels or 18% during the
    quarter  ended  September 30, 2003 as compared  to  the  quarter  ended
    September 30, 2002, resulting in a decrease of approximately $32,500 in
    income from net profits interests.

    Gas  production  increased approximately 38,500 mcf or 95%  during  the
    same  period,  resulting  in  a increase of approximately  $118,200  in
    income from net profits interests.

    The  net total increase in income from net profits interests due to the
    change in production is approximately $85,700.  Gas production increase
    is  from  two  wells  drilled  due  to farmout  arrangements  and  work
    performed on another well.

3.  Lease  operating  costs  and  production  taxes  were  25%  lower,   or
    approximately $75,000 less during the quarter ended September 30,  2003
    as  compared to the quarter ended September 30, 2002.  The decrease  in
    lease operating costs is due to workovers performed on two wells in the
    third quarter of 2002.

Costs and Expenses

Total costs and expenses increased to $87,119 from $62,469 for the quarters
ended  September 30, 2003 and 2002 respectively, an increase  of  39%.  The
increase  is  the  result  of  the addition of  accretion  expense,  higher
depletion expense and general and administrative expense.

1.  General and administrative costs consists of independent accounting and
    engineering  fees,  computer services, postage,  and  Managing  General
    Partner personnel costs.  General and administrative costs increased 6%
    or  approximately $2,100 during the quarter ended September 30, 2003 as
    compared to the quarter ended September 30, 2002.

2.  Depletion  expense increased to $37,000 for the quarter ended September
    30, 2003 from $24,000 for the same period in 2002.  This represents  an
    increase  of  54%.   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 September 30, 2002 by $6,000 and decrease net income
    for  the three months ended September 30, 2002 by $6,000(See Note 4  of
    the notes to the financial statements).  The contributing factor to the
    increase in depletion expense is in relation to the BOE depletion  rate
    for  the  quarter ended September 30, 2003, which was $2.01 applied  to
    18,450  BOE  as compared to $1.81 applied to 13,233 BOE  for  the  same
    period.


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

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

                                    Nine Months
                                       Ended         Percenta
                                                        ge
                                   September 30,     Increase
                                   2003      2002    (Decreas
                                                        e)
                                   ----      ----    --------
                                                        --
Average price per barrel  of  $    29.93             26%
oil                                        23.70
Average price per mcf of gas  $     5.06             86%
                                           2.72
Oil production in barrels        16,300    19,600    (17%)
Gas production in mcf            208,500   187,600   11%
Income   from  net   profits  $  921,008   14,046    6,457%
interests
Partnership distributions     $  500,091   -         100%
Limited              partner  $  450,082   -         100%
distributions
Per  unit  distribution   to
limited
 partners                     $    22.50        -    100%
Number  of  limited  partner     20,000    20,000
units

Revenues

The  Partnership's income from net profits interests increased to  $921,008
from  $14,046  for  the  nine months ended September  30,  2003  and  2002,
respectively,  an increase of 6,457%.  The principal factors affecting  the
comparison  of  the nine months ended September 30, 2003 and  2002  are  as
follows:

1.  The  average  price  for a barrel of oil received  by  the  Partnership
    increased  during the nine months ended September 30, 2003 as  compared
    to  the  nine  months ended September 30, 2002 by  26%,  or  $6.23  per
    barrel,  resulting in an increase of approximately $101,500  in  income
    from net profits interests.  Oil sales represented 32% of total oil and
    gas  sales during the nine months ended September 30, 2003 as  compared
    to 48% during the nine months ended September 30, 2002.

    The  average  price  for  an  mcf of gas received  by  the  Partnership
    increased during the same period by 86%, or $2.34 per mcf, resulting in
    an  increase  of  approximately $487,900 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
    $589,400.  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 3,300 barrels or 17% during the
    nine  months  ended September 30, 2003 as compared to the  nine  months
    ended  September  30,  2002, resulting in a decrease  of  approximately
    $78,200 in income from net profits interests.

    Gas  production  increased approximately 20,900 mcf or 11%  during  the
    same  period,  resulting  in an increase of  approximately  $56,800  in
    income from net profits interests.

    The  net total decrease in income from net profits interests due to the
    change in production is approximately $21,400.  Gas production increase
    is from two wells drilled due to farmout arrangements.

3.  Lease  operating  costs  and  production  taxes  were  35%  lower,   or
    approximately $338,200 less during the nine months ended September  30,
    2003  as  compared to the nine months ended September  30,  2002.   The
    decrease in lease operating costs is due to workovers performed on  two
    properties in 2002.

Costs and Expenses

Total  costs and expenses increased to $260,012 from $210,562 for the  nine
months ended September 30, 2003 and 2002, respectively, an increase of 23%.
The  increase  is  the result of the addition of accretion expense,  higher
depletion expense and general and administrative costs.

1.  General and administrative costs consists of independent accounting and
    engineering  fees,  computer services, postage,  and  Managing  General
    Partner  personnel costs.  General and administrative  costs  increased
    12% or approximately $13,900 during the nine months ended September 30,
    2003  as  compared to the nine months ended September  30,  2002.   The
    increase in general and administrative expense is due to an increase in
    independent accounting review and audit fees.

2.  Depletion  expense  increased to $103,000 for  the  nine  months  ended
    September  30,  2003 from $97,000 for the same period  in  2002.   This
    represents  an  increase of 6%.  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 nine months ended September 30, 2002 by  $28,000  and
    increase  net income for the nine months ended September  30,  2002  by
    $502,000(See  Note  4 of the notes to the financial  statements).   The
    contributing factor to the increase in depletion expense is in relation
    to the BOE depletion rate for the nine months ended September 30, 2003,
    which  was $2.02 applied to 51,050 BOE as compared to $1.91 applied  to
    50,867 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 September 30, 2003,  the  asset
retirement  obligation was $503,893.  The increase in the asset  retirement
obligation from January 1, 2003 is due to accretion expense of $29,501 plus
additional  wells added for $422 offset by decrease of $25,857 due  to  the
sale  of  properties.  The pro forma amounts for the three and nine  months
ended September 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
$686,200  in  the  nine  months ended September 30,  2003  as  compared  to
approximately $(14,800) in the nine months ended September 30,  2002.   The
primary  source  of  the  2003  cash flow  from  operating  activities  was
operations.

Cash flows provided by investing activities were approximately $300 in  the
nine months ended September 30, 2003.  There were no cash flows provided by
investing  activities  in the nine months ended September  30,  2002.   The
principle  source of the 2003 cash flow from investing activities  was  the
sales of oil and gas properties.

Cash flows used in financing activities were approximately $503,400 in  the
nine months ended September 30, 2003 as compared to approximately $7 in the
nine months ended September 30, 2002.  The only use in financing activities
was the distributions to partners.

Total  distributions during the nine months ended September 30,  2003  were
$500,091  of  which  $450,082 was distributed to the limited  partners  and
$50,009  to  the  general partners.  The per unit distribution  to  limited
partners during the nine months ended September 30, 2003 was $22.50.  There
were no distributions during the nine months ended September 30, 2002.

The  sources  for  the  2003 distributions of $500,091  were  oil  and  gas
operations  of  approximately  $686,200 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  cash  distributions  of
$17,953,945  have  been made to the partners.  As of  September  30,  2003,
$16,174,259 or $808.71 per limited partner unit has been distributed to the
limited  partners,  representing a 100% return of the  capital  and  a  62%
return on capital contributed.

As  of  September  30, 2003, the Partnership had approximately  395,200  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. Currently the Managing General Partner is evaluating
whether or not to continue to pursue the proposed merger.


<PAGE>
Liquidity - Managing General Partner
In  previous  reports  the Partnership provided that the  Managing  General
Partner  had  $124.0  million  of principal  scheduled  to  mature  between
December 31, 2002 and December 31, 2004.  Subsequent to September 30,  2003
the   Managing  General  Partner  refinanced  the  majority  of  its   debt
obligations and currently has $71.7 million in debt scheduled to mature  on
June  1, 2006 and $40.0 million in debt scheduled to mature on October  15,
2008.   The  Managing General Partner believes that it  has  adequate  cash
flows to meet its debt principal maturities scheduled for 2004.

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   senior
management of the Partnership's Managing General Partner is responsible for
establishing and maintaining a system of disclosure controls and procedures
(as defined in Rule 13a-14 and 15d-14 under the Securities Exchange Act  of
1934 (the "Exchange Act")) designed to ensure that information required  to
be  disclosed  by the Partnership in the reports that it files  or  submits
under  the  Exchange Act is recorded, processed, summarized  and  reported,
within   the  time  periods  specified  in  the  Securities  and   Exchange
Commission's rules and forms.  Disclosure controls and procedures  include,
without  limitation,  controls  and  procedures  designed  to  ensure  that
information required to be disclosed by the issuer in the reports  that  it
files or submits under the Exchange Act is accumulated and communicated  to
the  issuer's  management,  including its principal  executive  officer  of
officers  and principal financial officer or officers, or person performing
similar  functions,  as  appropriate to allow  timely  decisions  regarding
required disclosure.

In  accordance  with Exchange Act Rules 13a-15 and 15d-15, the  Partnership
carried  out  an evaluation, with the participation of the Chief  Executive
Officer  and  Chief Financial Officer of the Managing General  Partner,  as
well as other key members of the Managing General Partner's management,  of
the  effectiveness of the Partnership's disclosure controls and  procedures
as  of  the  end  of  the  period covered by this report.   Based  on  that
evaluation,  the  Managing General Partner's Chief  Executive  Officer  and
Chief   Financial  Officer  concluded  that  the  Partnership's  disclosure
controls and procedures were effective, as of the end of the period covered
by  this  report, to provide reasonable assurance that information required
to  be disclosed in the Partnership's reports filed or submitted under  the
Exchange  Act  is recorded, processed, summarized and reported  within  the
time  periods  specified in the Securities and Exchange Commission's  rules
and forms.

(b)  Changes in Internal Controls.  There have not been any changes in  the
Partnership's  internal  controls over financial  reporting  identified  in
connection  with  the evaluation described above that occurred  during  the
Partnership's  last  fiscal  quarter that has materially  affected,  or  is
reasonably  likely  to  materially affect,  these  internal  controls  over
financial reporting.


<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)  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,  Executive  Vice
                                   President
                                        and Chief Financial Officer

Date:     November 14, 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 14, 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 14, 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 September 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 14, 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 September 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 14, 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>