FORM 10-K
                    SECURITIES AND EXCHANGE COMMISSION
                          WASHINGTON, D.C.  20549
(Mark One)

[x]    Annual  report  pursuant to Section 13 or 15(d)  of  the  Securities
       Exchange Act of 1934

For the fiscal year ended December 31, 2003

                                    OR

[ ]    Transition  report pursuant to Section 13 or 15(d) of the Securities
       Exchange Act of 1934

For the transition period from                      to

Commission File Number 0-15411

                 Southwest Royalties, Inc. Income Fund VI
                (Exact name of registrant as specified in
                    its limited partnership agreement)

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

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

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

       Securities registered pursuant to Section 12(b) of the Act:

                                   None

       Securities registered pursuant to Section 12(g) of the Act:

                      limited partnership interests

Indicate by check mark whether registrant (1) has filed 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 if disclosure of delinquent filers pursuant to  Item
405  of  Regulation S-K is not contained herein, and will not be contained,
to  the  best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K  or  any
amendment to this Form 10-K.     [x]

Indicate  by check mark whether the registrant is an accelerated filer  (as
defined in Exchange Act Rule 12b-2).     Yes     No  X

The  registrant's  outstanding  securities  consist  of  Units  of  limited
partnership  interests for which there exists no established public  market
from which to base a calculation of aggregate market value.

The  total  number of pages contained in this report is 54.   The  exhibits
begin on page 48.

<PAGE>

                            Table of Contents

Item                                                                   Page

                                  Part I

     Glossary of Oil and Gas Terms                                       3

 1.  Business                                                            5

 2.  Properties                                                          9

 3.  Legal Proceedings                                                  11

 4.  Submission of Matters to a Vote of Security Holders                11

                                 Part II

 5.  Market for Registrant's Common Equity, Related
     Stockholder Matters and Issuer Purchases of Equity Securities      12

 6.  Selected Financial Data                                            13

 7.  Management's Discussion and Analysis of
     Financial Condition and Results of Operations                      14

7A.  Quantitative and Qualitative Disclosures About Market Risk         20

 8.  Financial Statements and Supplementary Data                        21

 9.  Changes in and Disagreements with Accountants
     on Accounting and Financial Disclosure                             37

9A.  Controls and Procedures                                            37

                                 Part III

10.  Directors and Executive Officers of the Registrant                 38

11.  Executive Compensation                                             40

12.  Security Ownership of Certain Beneficial Owners and
     Management and Related Stockholder Matters                         40

13.  Certain Relationships and Related Transactions                     41

14.  Principal Accountant Fees and Services                             41

                                 Part IV

15.  Exhibits, Financial Statement Schedules and Reports
     on Form 8-K                                                        42

     Signatures                                                         46

<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 a leasehold or
working  interest agrees to assign his interest in certain specific acreage
to  an  assignee,  retaining some interest, such as an  overriding  royalty
interest,  subject  to  the drilling of one (1)  or  more  wells  or  other
specified performance by the assignee.

     Field. An area consisting of a single reservoir or multiple reservoirs
all  grouped  on  or  related to the same individual geological  structural
feature and/or stratigraphic condition.

     Mcf. One thousand cubic feet.

     Net  Profits  Interest.  An agreement whereby  the  owner  receives  a
specified  percentage of the defined net profits from a producing  property
in  exchange for consideration paid.  The net profits interest  owner  will
not otherwise participate in additional costs and expenses of the property.

     Oil. Crude oil, condensate and natural gas liquids.

     Overriding  royalty  interest. Interests that  are  carved  out  of  a
working  interest, and their duration is limited by the term of  the  lease
under which they are created.

     Present  value  and  PV-10 Value. When used with respect  to  oil  and
natural gas reserves, the estimated future net revenue to be generated from
the  production of proved reserves, determined in all material respects  in
accordance  with  the  rules and regulations of the  SEC  (generally  using
prices  and costs in effect as of the date indicated) without giving effect
to  non-property  related  expenses  such  as  general  and  administrative
expenses,  debt service and future income tax expenses or to  depreciation,
depletion  and  amortization, discounted using an annual discount  rate  of
10%.

<PAGE>

     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. Reserves that can be  expected
to  be  recovered from existing wells with existing equipment and operating
methods.

     Proved properties. Properties with proved reserves.

     Proved  oil  and gas reserves. The estimated quantities of crude  oil,
natural  gas, and natural gas liquids with geological and engineering  data
that  demonstrate  with  reasonable certainty to be recoverable  in  future
years   from  known  reservoirs  under  existing  economic  and   operating
conditions, i.e., prices and costs as of the date the estimate is made.

     Proved  undeveloped  reserves.  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

Item 1.   Business

General
Southwest   Royalties,   Inc.  Income  Fund  VI   (the   "Partnership"   or
"Registrant") was organized as a Tennessee limited partnership on  December
4,  1986.   The offering of limited partnership interests began August  25,
1986, reached minimum capital requirements on October 3, 1986 and concluded
January 29, 1987.  The Partnership has no subsidiaries.

The  Partnership  has  expended  its  capital  and  acquired  interests  in
producing oil and gas properties.  After such acquisitions, the Partnership
has  produced and marketed the crude oil and natural gas produced from such
properties.  In most cases, the Partnership purchased royalty or overriding
royalty interests and working interests in oil and gas properties that were
converted  into net profits interests or other nonoperating interests.  The
Partnership  purchased  either all or part of the  rights  and  obligations
under various oil and gas leases.

The  principal executive offices of the Partnership are located at  407  N.
Big Spring, Suite 300, Midland, Texas, 79701.  The Managing General Partner
of  the  Partnership,  Southwest Royalties,  Inc.  (the  "Managing  General
Partner")   and  its  staff  of  81  individuals,  together  with   certain
independent  consultants  used  on an "as-needed"  basis,  perform  various
services on behalf of the Partnership, including the selection of  oil  and
gas properties and the marketing of production from such properties.  H. H.
Wommack, III, Chairman, Director, President and Chief Executive Officer  of
the  Managing  General  Partner, was also  a  general  partner.   Effective
December  31,  2001, Mr. Wommack sold his general partner interest  to  the
Managing General Partner.  The Partnership has no employees.

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  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 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.

Principal Products, Marketing and Distribution
The  Partnership has acquired and holds royalty interests  and  net  profit
interests  in  oil  and  gas  properties located  in  Texas,  Illinois  and
Oklahoma. All activities of the Partnership are confined to the continental
United  States.  All oil and gas produced from these properties is sold  to
unrelated third parties in the oil and gas business.

The  revenues  generated from the Partnership's oil and gas activities  are
dependent upon the current market for oil and gas.  The prices received  by
the  Partnership for its oil production depend upon numerous factors beyond
the  Partnership's control, including competition, economic, political  and
regulatory  developments  and  competitive  energy  sources,  and  make  it
particularly difficult to estimate future prices of oil and natural gas.


<PAGE>
Following  is a table of the ratios of revenues received from oil  and  gas
production for the last three years:

                      Oil           Gas
                     -----         -----
       2003           33%           67%
       2002           48%           52%
       2001           32%           68%

As  the table indicates, the Partnership's revenue for 2003 is more heavily
from  gas  production  with  about  one-third  from  oil  production,   the
Partnership  revenues will be highly dependent upon the future  prices  and
demands for oil and gas.

Seasonality of Business
Although  the  demand for natural gas can be effected by seasonality,  with
higher  demand  in the colder winter months and in very hot summer  months,
the  Partnership has not experienced material price and volume changes  due
to  seasonality  and has been able to sell all of its natural  gas,  either
through  contracts  in place or on the spot market at the  then  prevailing
spot market price.

Customer Dependence
No  material portion of the Partnership's business is dependent on a single
purchaser,  or a very few purchasers, where the loss of one  would  have  a
material  adverse impact on the Partnership. Two purchasers  accounted  for
69%  of  the Partnership's total oil and gas production during 2003:   Duke
Energy Field Services LP for 54% and Plains Marketing LP for 15%. Contracts
for  2003 with these major purchasers cover time periods ranging from month
to  month contracts up to five-year contract periods.  Prices received from
these  major purchasers ranged from $4.73 per mcf and $29.13 per Bbl.   Two
purchasers  accounted  for  59%  of the Partnership's  total  oil  and  gas
production  during 2002:  Duke Energy Field Service LP for 42%  and  Plains
Marketing LP for 17%.  Contracts for 2002 with these major purchasers cover
time periods ranging from month to month contracts up to five-year contract
periods.  Prices received from these major purchasers ranged from $2.64 per
mcf  and  $22.88  per  Bbl.   Two  purchasers  accounted  for  68%  of  the
Partnership's total oil and gas production during 2001:  Duke Energy  Field
Services  LP for 55% and Plains Marketing LP for 13%.  Contracts  for  2001
with  these major purchasers cover time periods ranging from month to month
contracts  up  to five-year contract periods.  Prices received  from  these
major  purchasers  ranged  from $4.34 per mcf  and  $26.14  per  Bbl.   All
purchasers of the Partnership's oil and gas production are unrelated  third
parties.   In  the  event  any  of  these purchasers  were  to  discontinue
purchasing  the  Partnership's  production, the  Managing  General  Partner
believes that a substitute purchaser or purchasers could be located without
undue  delay.   No  other purchaser accounted for an  amount  equal  to  or
greater than 10% of the Partnership's sales of oil and gas production.

Competition
Because  the  Partnership has utilized all of its funds available  for  the
acquisition  of net profits or royalty interests in producing oil  and  gas
properties,  it  is  not  subject to competition from  other  oil  and  gas
property purchasers.  See Item 2, Properties.

Factors  that  may  adversely  affect the  Partnership  include  delays  in
completing  arrangements  for  the sale of production,  availability  of  a
market for production, rising operating costs of producing oil and gas  and
complying  with  applicable  water  and  air  pollution  control  statutes,
increasing  costs  and  difficulties of transportation,  and  marketing  of
competitive  fuels.   Moreover, domestic oil  and  gas  must  compete  with
imported oil and gas and with coal, atomic energy, hydroelectric power  and
other forms of energy.

Regulation

Oil  and Gas Production - The production and sale of oil and gas is subject
to  federal and state governmental regulation in several respects, such  as
existing price controls on natural gas and possible price controls on crude
oil,  regulation of oil and gas production by state and local  governmental
agencies, pollution and environmental controls and various other direct and
indirect   regulation.    Many  jurisdictions  have  periodically   imposed
limitations on oil and gas production by restricting the rate of  flow  for
oil  and  gas wells below their actual capacity to produce and by  imposing
acreage limitations for the drilling of wells.  The federal government  has
the  power  to  permit increases in the amount of oil imported  from  other
countries and to impose pollution control measures.

Various  aspects of the Partnership's oil and gas activities are  regulated
by  administrative agencies under statutory provisions of the states  where
such  activities  are  conducted and by certain  agencies  of  the  federal
government for operations on Federal leases.  The regulatory burden on  the
oil  and  gas industry increases the Partnership's cost of doing  business,
and, consequently, affects its profitability.





<PAGE>
Regulation  of  Sales  and Transportation of Natural  Gas.   Our  sales  of
natural   gas  are  affected  by  the  availability,  terms  and  cost   of
transportation.  The price and terms for access to pipeline  transportation
are  subject  to  extensive  regulation. In  recent  years,  the  FERC  has
undertaken  various initiatives to increase competition within the  natural
gas industry. As a result of initiatives like FERC Order No. 636, issued in
April  1992, the interstate natural gas transportation and marketing system
has   been  substantially  restructured  to  remove  various  barriers  and
practices  that  historically  limited non-pipeline  natural  gas  sellers,
including  producers, from effectively competing with interstate  pipelines
for  sales  to  local  distribution  companies  and  large  industrial  and
commercial  customers. The most significant provisions  of  Order  No.  636
require   that   interstate  pipelines  provide  firm   and   interruptible
transportation  service  on an open access basis  that  is  equal  for  all
natural  gas supplies. In many instances, the results of Order No. 636  and
related  initiatives  have been to substantially reduce  or  eliminate  the
interstate  pipelines' traditional role as wholesalers of  natural  gas  in
favor  of  providing  only storage and transportation services.  While  the
United  States  Court  of  Appeals upheld most of Order  No.  636,  certain
related  FERC  orders,  including  the  individual  pipeline  restructuring
proceedings,  are still subject to judicial review and may be  reversed  or
remanded in whole or in part. While the outcome of these proceedings cannot
be  predicted  with certainty, we do not believe that we will  be  affected
materially differently than its competitors.

The FERC has also announced several important transportation-related policy
statements and proposed rule changes, including a statement of policy and a
request  for  comments concerning alternatives to its traditional  cost-of-
service rate making methodology to establish the rates interstate pipelines
may  charge  for their services. A number of pipelines have  obtained  FERC
authorization  to  charge  negotiated rates as  one  such  alternative.  In
February  1997, the FERC announced a broad inquiry into issues  facing  the
natural  gas  industry to assist the FERC in establishing regulatory  goals
and  priorities in the post-Order No. 636 environment. Similarly, the Texas
Railroad Commission has been reviewing changes to its regulations governing
transportation and gathering services provided by intrastate pipelines  and
gatherers.  While the changes being considered by these federal  and  state
regulators  would affect us only indirectly, they are intended  to  further
enhance  competition in natural gas markets. We cannot predict what further
action the FERC or state regulators will take on these matters, however, we
do  not  believe  that it will be affected by any action  taken  materially
differently than other natural gas producers with which it competes.

Additional  proposals  and proceedings that might affect  the  natural  gas
industry are pending before Congress, the FERC, state commissions  and  the
courts.  The  natural  gas  industry historically  has  been  very  heavily
regulated;  therefore,  there  is  no assurance  that  the  less  stringent
regulatory  approach  recently  pursued  by  the  FERC  and  Congress  will
continue.

Oil Price Controls and Transportation Rates. Sales of crude oil, condensate
and  gas  liquids by us are not currently regulated and are made at  market
prices.  The  price  we  receive from the sale of  these  products  may  be
affected by the cost of transporting the products to market.

Environmental  and  Health Controls.  Extensive federal,  state  and  local
regulatory and common laws regulating the discharge of materials  into  the
environment  or  otherwise relating to the protection  of  the  environment
affect   our   oil  and  natural  gas  operations.  Numerous   governmental
departments issue rules and regulations to implement and enforce such laws,
which  are  often  difficult  and costly to comply  with  and  which  carry
substantial  civil and even criminal penalties for failure to comply.  Some
laws, rules and regulations relating to protection of the environment  may,
in   certain  circumstances,  impose  strict  liability  for  environmental
contamination,  rendering  a person liable for  environmental  damages  and
cleanup  costs without regard to negligence or fault on the  part  of  such
person. Other laws, rules and regulations may restrict the rate of oil  and
natural  gas production below the rate that would otherwise exist  or  even
prohibit  exploration  and production activities  in  sensitive  areas.  In
addition,  state  laws often require various forms of  remedial  action  to
prevent  pollution,  such  as  closure of inactive  pits  and  plugging  of
abandoned wells. The regulatory burden on the oil and natural gas  industry
increases  our  cost  of  doing  business  and  consequently  affects   our
profitability.  We  believe  that  we are in  substantial  compliance  with
current  applicable environmental laws and regulations and  that  continued
compliance  with  existing requirements will not have  a  material  adverse
impact on our operations. However, environmental laws and regulations  have
been subject to frequent changes over the years, and the imposition of more
stringent  requirements  could  have a material  adverse  effect  upon  our
capital  expenditures,  earnings  or competitive  position.   Additionally,
given  the  intense litigation environment in the United States,  a  threat
exists  of  lawsuits  alleging personal injury  and  property  damage  from
environmental  contamination  alleged  to  be  created  by  us  or  related
entities.   Potential  liability  in such lawsuits  can  include  not  only
compensatory, but substantial punitive damages as well.  We are  not  aware
of any such suits currently pending or threatened.

<PAGE>

The  Comprehensive Environmental Response, Compensation and  Liability  Act
("CERCLA"),  also known as the "Superfund" law, imposes liability,  without
regard  to  fault on certain classes of persons that are considered  to  be
responsible   for  the  release  of  a  "hazardous  substance"   into   the
environment. These persons include the current or former owner or  operator
of the disposal site or sites where the release occurred and companies that
disposed or arranged for the disposal of hazardous substances. Under CERCLA
such persons may be subject to joint and several liability for the costs of
investigating and cleaning up hazardous substances that have been  released
into the environment, for damages to natural resources and for the costs of
certain  health  studies.  In  addition,  companies  that  incur  liability
frequently also confront third party claims because it is not uncommon  for
neighboring landowners and other third parties to file claims for  personal
injury  and  property  damage allegedly caused by hazardous  substances  or
other  pollutants  released  into the environment  from  a  polluted  site.
Potential  liability also exists under CERCLA for natural resource  damage.
A  Natural  Resource Damage Action (NRDA) could result in  liability  being
assessed for restoration to natural resources.

The  Federal Oil Pollution Act of 1990 ("OPA") regulates the release of oil
into  water  or  other areas designated by the statute.   A  release  could
result  in  our  being  held responsible for the cost  of  remediating  the
release, OPA specified damages and natural resource damages.  The extent of
such liability could be extensive.   A release of oil in harmful quantities
or other materials into water or other specified areas could also result in
our  being held responsible under the Clean Water Act ("CWA") for the costs
of remediation, and any civil and criminal fines and penalties.

The   Federal  Solid  Waste  Disposal  Act,  as  amended  by  the  Resource
Conservation  and Recovery Act of 1976 ("RCRA"), regulates the  generation,
transportation,  storage, treatment and disposal  of  solid  and  hazardous
wastes and can require cleanup of abandoned hazardous waste disposal  sites
as  well  as  waste management areas operating facilities.  RCRA  currently
excludes drilling fluids, produced waters and other wastes associated  with
the  exploration,  development or production of oil and  natural  gas  from
regulation  as  "hazardous waste." Disposal of such non-hazardous  oil  and
natural  gas  exploration, development and production  wastes  usually  are
regulated  by state law. Other wastes handled at exploration and production
sites  or used in the course of providing well services may not fall within
this  exclusion.  Moreover,  stricter  standards  for  waste  handling  and
disposal may be imposed on the oil and natural gas industry in the  future.
From time to time legislation is proposed in Congress that would revoke  or
alter  the  current  exclusion of exploration, development  and  production
wastes  from  the RCRA definition of "hazardous wastes" thereby potentially
subjecting  such  wastes to more stringent handling, disposal  and  cleanup
requirements. If such legislation were enacted it could have a  significant
impact  on the operating costs of Southwest and Sierra, as well as the  oil
and natural gas industry and well servicing industry in general. The impact
of  future  revisions  to  environmental laws  and  regulations  cannot  be
predicted.  In addition, if our operations were to trigger regulation under
RCRA,  we could be required to satisfy certain financial criteria to ensure
financial  ability  to comply with RCRA regulations.   Proof  of  financial
responsibility  could  be required in the form of  dedicated  trust  funds,
irrevocable letters of credit, posting of bonds, etc.

The Federal Clean Water Act ("CWA") contains provisions that may result  in
the imposition of certain water pollution control requirements with respect
to water releases from our operations.  We may be required to incur certain
capital  expenditures in the next several years for water pollution control
equipment  in connection with obtaining and maintaining National  Pollutant
Discharge  Elimination Systems ("NPDES") permits.  However, we believe  our
operations  will  not  be  materially  adversely  affected  by   any   such
requirements,  and  the  requirements are  not  expected  to  be  any  more
burdensome to us than to other similarly situated companies involved in oil
and  natural  gas exploration and production activities or  well  surfacing
activities.

Our  operations are also subject to the federal Clean Air Act  ("CAA")  and
comparable state and local requirements. Amendments to the CAA were adopted
in 1990 and contain provisions that may result in the gradual imposition of
certain  pollution control requirements with respect to air emissions  from
our operations. We may be required to incur certain capital expenditures in
the  next  several years for air pollution control equipment in  connection
with  obtaining  and maintaining operating permits and  approvals  for  air
emissions.  However,  we  believe our operations  will  not  be  materially
adversely affected by any such requirements, and the requirements  are  not
expected  to be any more burdensome to us than to other similarly  situated
companies  involved  in  oil  and natural gas  exploration  and  production
activities or well servicing activities.

<PAGE>

We  maintain  insurance against "sudden and accidental" occurrences,  which
may  cover  some, but not all, of the environmental risks described  above.
Most  significantly,  the insurance we maintain will not  cover  the  risks
described above which occur over a sustained period of time. Further, there
can  be  no assurance that such insurance will continue to be available  to
cover  all  such costs or that such insurance will be available at  premium
levels  that  justify its purchase.  The occurrence of a significant  event
not  fully  insured  or indemnified against could have a  material  adverse
effect on our financial condition and operations.

Limited   partners  should  be  aware  that  the  assessment  of  liability
associated with environmental liabilities is not always correlated  to  the
value of a particular project.  Accordingly, liability associated with  the
environment under local, state, or federal regulations, particularly  clean
ups  under CERCLA, can exceed the value of our investment in the associated
site.

Regulation  of  Oil  and  Natural  Gas  Exploration  and  Production.   Our
exploration  and  production operations are subject  to  various  types  of
regulation  at  the  federal,  state and local  levels.   Such  regulations
include  requiring  permits and drilling bonds for the drilling  of  wells,
regulating the location of wells, the method of drilling and casing  wells,
and  the  surface  use and restoration of properties upon which  wells  are
drilled.    Many  states  also  have  statutes  or  regulations  addressing
conservation matters, including provisions for the utilization  or  pooling
of  oil  and natural gas properties, the establishment of maximum rates  of
production  from oil and natural gas wells and the regulation  of  spacing,
plugging and abandonment of such wells.  Some state statutes limit the rate
at which oil and natural gas can be produced from our properties.

Partnership Employees
The Partnership has no employees; however, the Managing General Partner has
a  staff of geologists, engineers, accountants, landmen and clerical  staff
who  engage in Partnership activities and operations and perform additional
services  for  the  Partnership as needed.  In  addition  to  the  Managing
General  Partner's  staff, the Partnership engages independent  consultants
such  as petroleum engineers and geologists as needed.  As of December  31,
2003,  there were 81 individuals directly employed by the Managing  General
Partner in various capacities.

Item 2.  Properties

In  determining whether an interest in a particular producing property  was
to  be  acquired, the Managing General Partner considered such criteria  as
estimated  oil  and  gas reserves, estimated cash flow  from  the  sale  of
production,  present  and  future prices of oil  and  gas,  the  extent  of
undeveloped  and  unproved reserves, the potential for secondary,  tertiary
and other enhanced recovery projects and the availability of markets.

As  of December 31, 2003, the Partnership possessed an interest in oil  and
gas properties located in Clinton and Marion Counties of Illinois; Alfalfa,
Ellis,  Garvin, Haskell, Latimer, Leflore, Logan, McClain, Noble,  Seminole
and  Woods  Counties  of Oklahoma; Brazos, Burleson, Fayette,  Lee,  Nolan,
Pecos, Upton, Ward and Winkler Counties of Texas.  These properties consist
of various interests in approximately 124 wells and units.

<PAGE>
The  Partnership, through farm-out arrangements, had two new wells come on-
line  during  2003.   Due  to  the Partnership's objective  of  maintaining
current operations without engaging in the drilling of any developmental or
exploratory  wells  except  through farm-out  arrangements,  or  additional
acquisitions  of  producing  properties, there  were  not  any  significant
changes in properties during 2002 and 2001.

During  2003, two leases were sold for approximately $300.  There  were  no
leases sold during 2002 and 2001.

Significant Properties
The  following  table  reflects the significant  properties  in  which  the
Partnership has an interest:

                            Date
                          Purchased     No. of         Proved Reserves*
           Name and          and         Wells         Oil           Gas
           Location       Interest                   (bbls)         (mcf)
        ---------------   ---------     ------      ---------      -------
          -----------      -------        --          ----          ------
        Mobil   Amacker    7/87 at        25         69,000        4,794,0
        Tippet               23%                                      00
        Upton   County,    to 100%        11         32,000        3,576,0
        Texas                net                       (1)          00(1)
                           profits
                          interests


(1)Amounts  represent  proved developed reserves from  currently  producing
zones.

*Ryder Scott Company, L.P. prepared the reserve and present value data  for
the  Partnership's existing properties as of January 1, 2004.  The  reserve
estimates  were  made  in  accordance with guidelines  established  by  the
Securities and Exchange Commission pursuant to Rule 4-10(a) of Regulation S-
X.   Such guidelines require oil and gas reserve reports be prepared  under
existing economic and operating conditions with no provisions for price and
cost escalation except by contractual arrangements.

Oil  price  adjustments were made in the individual evaluations to  reflect
oil  quality,  gathering  and transportation costs.   The  results  of  the
reserve  report as of January 1, 2004 are an average price  of  $31.26  per
barrel.

Gas  price  adjustments were made in the individual evaluations to  reflect
BTU  content,  gathering and transportation costs and  gas  processing  and
shrinkage.  The results of the reserve report as of January 1, 2004 are  an
average price of $5.31 per Mcf.

<PAGE>
As  also discussed in Part II, Item 7, Management's Discussion and Analysis
of  Financial Condition and Results of Operations, oil and gas prices  were
subject to frequent changes in 2003.

The  evaluation  of  oil and gas properties is not  an  exact  science  and
inevitably involves a significant degree of uncertainty, particularly  with
respect to the quantity of oil or gas that any given property is capable of
producing.   Estimates  of  oil and gas reserves  are  based  on  available
geological and engineering data, the extent and quality of which  may  vary
in  each  case  and,  in  certain instances, may prove  to  be  inaccurate.
Consequently,  properties may be depleted more rapidly than the  geological
and engineering data have indicated.

Unanticipated  depletion, if it occurs, will result in lower reserves  than
previously  estimated; thus an ultimately lower return for the Partnership.
Basic  changes in past reserve estimates occur annually.  As  new  data  is
gathered  during the subsequent year, the engineer must revise his  earlier
estimates.  A year of new information, which is pertinent to the estimation
of  future  recoverable volumes, is available during  the  subsequent  year
evaluation.   In applying industry standards and procedures, the  new  data
may cause the previous estimates to be revised.  This revision may increase
or  decrease the earlier estimated volumes.  Pertinent information gathered
during the year may include actual production and decline rates, production
from  offset  wells  drilled to the same geologic formation,  increased  or
decreased water production, workovers, and changes in lifting costs,  among
others.   Accordingly,  reserve  estimates are  often  different  from  the
quantities of oil and gas that are ultimately recovered.

The  Partnership has reserves, which are classified as proved developed and
proved  undeveloped.   All  of  the proved reserves  are  included  in  the
engineering reports, which evaluate the Partnership's present reserves.

Because  the  Partnership  does  not engage  in  drilling  activities,  the
development of proved undeveloped reserves is conducted pursuant  to  farm-
out  arrangements  with  the Managing General Partner  or  unrelated  third
parties.  Generally, the Partnership retains a carried interest such as  an
overriding royalty interest under the terms of a farm-out.

The  Partnership or the owners of properties in which the Partnership  owns
an  interest  can  engage  in workover projects or  supplementary  recovery
projects, for example, to extract behind the pipe reserves.  See  Part  II,
Item  7,  Management's Discussion and Analysis of Financial  Condition  and
Results of Operations.

Item 3.  Legal Proceedings

There are no material pending legal proceedings to which the Partnership is
a party.

Item 4.  Submission of Matters to a Vote of Security Holders

No  matter  was submitted to a vote of security holders during  the  fourth
quarter of 2003 through the solicitation of proxies or otherwise.

<PAGE>

                                 Part II


Item 5.  Market  for  the  Registrant's Common Equity, Related  Stockholder
         Matters and Issuer Purchases of Equity Securities

Market Information
Limited  partnership interests, or units, in the Partnership were initially
offered and sold for a price of $500.  Limited partner units are not traded
on  any  exchange  and there is no public or organized trading  market  for
them.  The Managing General Partner has become aware of certain limited and
sporadic transfers of units between limited partners and third parties, but
has no verifiable information regarding the prices at which such units have
been  transferred.   Further,  a transferee may  not  become  a  substitute
limited partner without the consent of the Managing General Partner.

After  completion of the Partnership's first full fiscal year of operations
and each year thereafter, the Managing General Partner has offered and will
continue  to  offer  to  purchase each limited partner's  interest  in  the
Partnership in accordance with the obligations set forth in the partnership
agreement. The pricing mechanism used to calculate the repurchase is  based
on tangible assets of the Partnership, plus the present value of the future
net  revenues  of proved oil and gas properties, minus liabilities  with  a
risk  factor  discount of up to one-third which may be implemented  at  the
sole  discretion  of the Managing General Partner.  However,  the  Managing
General  Partner's obligation to purchase limited partner units  under  the
partnership agreement is limited to an annual expenditure of an amount  not
in  excess  of 10% of the total limited partner units initially  subscribed
for by limited partners.

                   Issuer Purchases of Equity Securities

                                                   Maximum
                                       Total     Number (or
                                      Number
                                     of Units    Approximat
                                                      e
                                     Purchased    Value) of
                                        as          Units
                                      Part of     that May
                                     Publicly      Yet Be
               Total                 Announced    Purchased
              Number
             of Units     Average    Plans or     Under the
                           Price                    Plans
Period(1)    Purchased   Paid Per    Programs        or
                           Unit                   Programs
October 1-
   31,
   2003          9      $  173.44        -           N/A
November 1-
   30,
   2003          -             -         -           N/A
December 1-
   31,
   2003          -             -         -           N/A
  TOTALS         9      $  173.44

(1)  In April and July 2003, the Managing General Partner purchased a total
of  49 limited partner units from limited partners at an average base price
of  $182.19  per unit.  As of December 31, 2002, no limited  partner  units
were  purchased by the Managing General Partner.  In 2001, 2,009.5  limited
partner  units  were  tendered to and purchased  by  the  Managing  General
Partner  at  an  average base price of $562.21 per unit. These  repurchases
were part of the obligations under the partnership agreement.

Number of Limited Partner Interest Holders
As  of December 31, 2003 there were 667 holders of limited partner units in
the Partnership.

Distributions
Pursuant  to Article IV, Section 4.01 of the Partnership's Certificate  and
Agreement  of  Limited Partnership "Net Cash Flow" is  distributed  to  the
partners  on  a quarterly basis.  "Net Cash Flow" is defined as  "the  cash
generated  by  the  Partnership's investments  in  producing  oil  and  gas
properties,  less  (i)  General and Administrative  Costs,  (ii)  Operating
Costs,  and  (iii) any reserves necessary to meet current  and  anticipated
needs  of  the  Partnership, as determined at the sole  discretion  of  the
Managing General Partner."

<PAGE>

During  2003,  distributions  were made totaling  $750,091,  with  $675,082
distributed  to  the limited partners and $75,009 to the  general  partner.
For  the  year ended December 31, 2003, distributions of $33.75 per limited
partner   unit   were  made,  based  upon  20,000  limited  partner   units
outstanding.  There were no distributions due to a decrease in revenues  as
a  result  of  a  decline in production and gas prices for the  year  ended
December   31,  2002.   During  2001,  distributions  were  made   totaling
$1,127,395,  with  $1,014,895  distributed  to  the  limited  partners  and
$112,500  to the general partners.  For the year ended December  31,  2001,
distributions  of  $50.74 per limited partner unit were  made,  based  upon
20,000 limited partner units outstanding.

Item 6.  Selected Financial Data

The  following  selected financial data for the years  ended  December  31,
2003,  2002,  2001,  2000 and 1999 should be read in conjunction  with  the
financial statements included in Item 8:

                                   Years ended December 31,
                        2003       2002       2001      2000       1999
                       ------     ------     ------    ------     ------
Revenues            $ 1,237,71    104,701   964,152    1,435,6    830,452
                      9                                64

Net  income (loss)
before
        cumulative
effects of
        accounting    904,659     (171,77   571,669    1,215,5    523,863
changes                           5)                   73

Net income (loss)     1,021,29    358,225   571,669    1,215,5    523,863
                      6                                73

Partners' share
   of  net  income
(loss):

General partners      102,130     35,822    57,167     121,557    52,386

Limited partners      919,166     322,403   514,502    1,094,0    471,477
                                                       16

Limited partners'
 net income (loss)
per unit
 before cumulative    40.71       (7.73)    25.73      54.70      23.57
effect

Limited partners'
 net income (loss)    45.96       16.12     25.73      54.70      23.57
per unit

Limited partners'
              cash
distributions
 per unit             33.75       -         50.74      52.88      21.38

Total assets        $ 2,828,41    2,047,1   1,688,4    2,242,9    2,202,0
                      2           63        19         02         52



<PAGE>
Item 7.     Management's Discussion and Analysis of Financial Condition and
Results of Operations

General
The  Partnership was formed to acquire non-operating interests in producing
oil  and  gas  properties, to produce and market crude oil and natural  gas
produced  from  such  properties and to distribute any  net  proceeds  from
operations  to  the  general  and  limited  partners.   Net  revenues  from
producing  oil  and  gas  properties are not reinvested  in  other  revenue
producing  assets except to the extent that producing facilities and  wells
are  reworked  or  where  methods are employed to improve  or  enable  more
efficient  recovery  of oil and gas reserves.  The  economic  life  of  the
Partnership thus depends on the period over which the Partnership's oil and
gas reserves are economically recoverable.

Increases   or   decreases   in  Partnership   revenues   and,   therefore,
distributions  to partners will depend primarily on changes in  the  prices
received  for  production,  changes in volumes of  production  sold,  lease
operating  expenses, enhanced recovery projects, offset drilling activities
pursuant  to  farm-out arrangements and on 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  limited
partners has fluctuated over the past few years and is expected to  decline
in later years based on these factors.

Based  on  current conditions, development drilling and workovers  will  be
performed  during  the  years  2004 and 2005  to  enhance  production.  The
partnership  may have an increase in production volumes for the  year  2004
and  2005,  but  thereafter, the partnership will most likely  continue  to
experience  the  historical production decline, which has approximated  10%
per   year.   Accordingly,  if  commodity  prices  remain  unchanged,   the
Partnership   expects  future  earnings  to  decline  due  to   anticipated
production declines.

Critical Accounting Policies
Full cost ceiling calculations The Partnership follows the full cost method
of  accounting  for  its  oil and gas properties.   The  full  cost  method
subjects  companies to quarterly calculations of a "ceiling", or limitation
on  the  amount of properties that can be capitalized on the balance sheet.
If  the  Partnership's capitalized costs are in excess  of  the  calculated
ceiling, the excess must be written off as an expense.

The  Partnership's discounted present value of its proved oil  and  natural
gas  reserves  is  a  major  component  of  the  ceiling  calculation,  and
represents  the  component  that requires the  most  subjective  judgments.
Estimates  of  reserves are forecasts based on engineering data,  projected
future  rates  of  production and the timing of future  expenditures.   The
process  of  estimating oil and natural gas reserves  requires  substantial
judgment,  resulting  in  imprecise determinations,  particularly  for  new
discoveries.   Different reserve engineers may make different estimates  of
reserve  quantities  based  on the same data.   The  Partnership's  reserve
estimates are prepared by outside consultants.

The  passage  of  time  provides  more  qualitative  information  regarding
estimates of reserves, and revisions are made to prior estimates to reflect
updated  information.   However,  there  can  be  no  assurance  that  more
significant  revisions  will not be necessary  in  the  future.  If  future
significant  revisions  are  necessary  that  reduce  previously  estimated
reserve quantities, it could result in a full cost property writedown.   In
addition to the impact of these estimates of proved reserves on calculation
of  the  ceiling,  estimates  of proved reserves  are  also  a  significant
component of the calculation of DD&A.

While  the quantities of proved reserves require substantial judgment,  the
associated prices of oil and natural gas reserves that are included in  the
discounted  present  value of the reserves do not  require  judgment.   The
ceiling calculation dictates that prices and costs in effect as of the last
day  of  the  period are generally held constant indefinitely. Because  the
ceiling  calculation dictates that prices in effect as of the last  day  of
the  applicable quarter are held constant indefinitely, the resulting value
is  not indicative of the true fair value of the reserves.  Oil and natural
gas  prices have historically been cyclical and, on any particular  day  at
the  end of a quarter, can be either substantially higher or lower than the
Partnership's  long-term price forecast that is a barometer for  true  fair
value.

In  2002,  the  Partnership changed methods of accounting for depletion  of
capitalized  costs  from  the  units-of-revenue  method  to  the  units-of-
production method.  The newly adopted accounting principle is preferable in
the  circumstances  because the units-of-production  method  results  in  a
better  matching of the costs of oil and gas production against the related
revenue received in periods of volatile prices for production as have  been
experienced  in  recent  periods.   Additionally,  the  units-of-production
method is the predominant method used by full cost companies in the oil and
gas  industry,  accordingly, the change improves the comparability  of  the
Partnership's financial statements with its peer group.
<PAGE>
Results of Operations

A.  General Comparison of the Years Ended December 31, 2003 and 2002

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

                                                           Percenta
                                                              ge
                                 Year Ended December       Increase
                                         31,
                                   2003        2002        (Decreas
                                                              e)
                                  ------      ------       --------
                                                             ----
      Average price per       $   29.69       24.59        21%
      barrel of oil
      Average price per mcf   $    4.84        2.95        64%
      of gas
      Oil production in         21,800       26,000        (16%)
      barrels
      Gas production in mcf     275,100      235,000       17%
      Income from net         $ 1,227,589    103,085       1,091%
      profits interests
      Partnership             $ 750,091      -             100%
      distributions
      Limited partner         $ 675,082      -             100%
      distributions
      Per unit distribution   $   33.75      -             100%
      to limited partners

      Number of limited         20,000       20,000
      partner units

Revenues

The Partnership's income from net profits interests increased to $1,227,589
from $103,085 for the years ended December 31, 2003 and 2002, respectively,
an  increase of 1,091%.  The principal factors affecting the comparison  of
the years ended December 31, 2003 and 2002 are as follows:

1.  The  average  price  for a barrel of oil received  by  the  Partnership
    increased  during the year ended December 31, 2003 as compared  to  the
    year ended December 31, 2002 by 21%, or $5.10 per barrel, resulting  in
    an  increase  of  approximately $111,200 in  income  from  net  profits
    interests.  Oil sales represented 33% of total oil and gas sales during
    the  year  ended December 31, 2003 as compared to 48% during  the  year
    ended December 31, 2002.

    The  average  price  for  an  mcf of gas received  by  the  Partnership
    increased during the same period by 64%, or $1.89 per mcf, resulting in
    an  increase  of  approximately $519,900 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
    $631,100.  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 4,200 barrels or 16% during the
    year ended December 31, 2003 as compared to the year ended December 31,
    2002, resulting in a decrease of approximately $103,300 in income  from
    net profits interests.

    Gas  production  increased approximately 40,100 mcf or 17%  during  the
    same  period,  resulting  in an increase of approximately  $118,300  in
    income from net profits interests.

    The  net total increase in income from net profits interests due to the
    change  in  production is approximately $15,000.   The  primary  factor
    contributing to the reduction in oil volumes was a correction  in  2003
    of  oil sales volumes incorrectly recorded on a lease in 2001 and 2002.
    The  increase  in  gas volumes is from two new wells  drilled  in  2003
    through farm-out arrangements.

3. Other  income  in  the  amount of $8,952 for 2003  primarily  represents
   litigation  settlement  income from a class action  lawsuit,  where  two
   purchasers  were  underpaying  for  certain  types  of  oil  in  certain
   locations for the time periods of 1988-1998.

4.  Lease  operating  costs  and  production  taxes  were  39%  lower,   or
    approximately $476,000 less during the year ended December 31, 2003  as
    compared  to  the  year  ended  December  31,  2002.   Two  wells   had
    significant well work performed in 2002 resulting in high workovers and
    intangible drilling cost, partially offset by an increase in production
    taxes due to an increase in 2003 oil prices.

Costs and Expenses

Total  costs and expenses increased to $333,060 from $276,476 for the years
ended  December 31, 2003 and 2002, respectively, an increase of  20%.   The
increase  is  primarily  the result of the addition of  accretion  expense,
higher  general  and  administrative costs, and an  increase  in  depletion
expense.

1. General and administrative costs consists of independent accounting  and
   engineering  fees,  computer  services, postage,  and  Managing  General
   Partner personnel costs.  General and administrative costs increased  8%
   or  approximately  $12,600 during the year ended December  31,  2003  as
   compared to the year ended December 31, 2002.

2. Depletion expense increased to $130,000 for the year ended December  31,
   2003  from  $125,000  for the same period in 2002.  This  represents  an
   increase  of  4%.  The contributing factor to the increase in  depletion
   expense  is  in  relation to the BOE depletion rate for the  year  ended
   December 31, 2003, which was $1.92 applied to 67,650 BOE as compared  to
   $1.92 applied to 65,167 BOE for the same period in 2002.

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 December 31, 2003,  the  asset
retirement  obligation was $513,400.  The increase in the asset  retirement
obligation from January 1, 2003 is due to accretion expense of $39,008 plus
additional  wells added for $422 offset by decrease of $25,857 due  to  the
sale  of  properties.   The  pro  forma amounts  of  the  asset  retirement
obligation  as  of  December 31, 2002, 2001 and  2000,  were  approximately
$499,827,  $463,040 and $428,960, respectively.  The pro forma  amounts  of
the   asset   retirement  obligation  were  measured   using   information,
assumptions and interest rates as of the adoption date of January 1, 2003.


<PAGE>

Results of Operations

B.  General Comparison of the Years Ended December 31, 2002 and 2001

The  following  table  provides certain information  regarding  performance
factors for the years ended December 31, 2002 and 2001:

                                                           Percenta
                                                              ge
                                 Year Ended December       Increase
                                         31,
                                   2002        2001        (Decreas
                                                              e)
                                  ------      ------       --------
                                                             ----
      Average price per       $   24.59        23.37       5%
      barrel of oil
      Average price per mcf   $    2.95         3.97       (26%)
      of gas
      Oil production in         26,000       29,000        (10%)
      barrels
      Gas production in mcf     235,000      367,900       (36%)
      Income from net         $ 103,085      955,342       (89%)
      profits interests
      Partnership             $ -            1,127,395     (100%)
      distributions
      Limited partner         $ -            1,014,985     (100%)
      distributions
      Per unit distribution   $ -              50.74       (100%)
      to limited partners

      Number of limited         20,000       20,000
      partner units

Revenues

The  Partnership's income from net profits interests decreased to  $103,085
from $955,342 for the years ended December 31, 2002 and 2001, respectively,
a  decrease of 89%.  The principal factors affecting the comparison of  the
years ended December 31, 2002 and 2001 are as follows:

1.  The  average  price  for a barrel of oil received  by  the  Partnership
    increased  during the year ended December 31, 2002 as compared  to  the
    year  ended December 31, 2001 by 5%, or $1.22 per barrel, resulting  in
    an  increase  of  approximately $31,700  in  income  from  net  profits
    interests.  Oil sales represented 48% of total oil and gas sales during
    the  year  ended December 31, 2002 as compared to 32% during  the  year
    ended December 31, 2001.

    The  average  price  for  an  mcf of gas received  by  the  Partnership
    decreased during the same period by 26%, or $1.02 per mcf, resulting in
    a  decrease  of  approximately $239,700  in  income  from  net  profits
    interests.

    The  net total decrease in income from net profits interests due to the
    change  in prices received from oil and gas production is approximately
    $208,000.  The market price for oil and gas has been extremely volatile
    over  the  past  decade  and management expects  a  certain  amount  of
    volatility to continue in the foreseeable future.

<PAGE>

2.  Oil  production decreased approximately 3,000 barrels or 10% during the
    year ended December 31, 2002 as compared to the year ended December 31,
    2001,  resulting in a decrease of approximately $70,100 in income  from
    net profits interests.

    Gas  production decreased approximately 132,900 mcf or 36%  during  the
    same  period,  resulting  in  a decrease of approximately  $527,600  in
    income from net profits interests.

    The  total  decrease in income from net profits interests  due  to  the
    change  in  production is approximately $597,700.  The Partnership  per
    its  agreement does not engage in drilling activities, the  development
    of  proved reserves is conducted pursuant to farm-out arrangements with
    the Managing General Partner or unrelated third parties.  This occurred
    on  two  leases where the carried interest decreased causing a decrease
    in production during the year ended December 31, 2002.  In addition one
    of the above mentioned leases had a downhole mechanical problem and the
    second lease had a hole in the tubing that let water dump into the  pay
    zone,  pumping  equipment has been added and production  is  increasing
    daily.

3.  Lease  operating  costs  and  production  taxes  were  4%  higher,   or
    approximately $45,800 more during the year ended December 31,  2002  as
    compared  to the year ended December 31, 2001.  The increase  in  lease
    operating  expense  is  due to two leases performing  workovers  during
    2002, partially offset by a decrease in lease operating expense for one
    lease  due  to  repairs and maintenance performed  during  2001  and  a
    decrease  in  production taxes due to a decline in gas  production  and
    prices received during the year ended December 31, 2002.

Costs and Expenses

Total  costs and expenses decreased to $276,476 from $392,483 for the years
ended  December 31, 2002 and 2001, respectively, a decrease  of  30%.   The
decrease is primarily the result of lower general and administrative  costs
and depletion expense.

1. General and administrative costs consists of independent accounting  and
   engineering  fees,  computer  services, postage,  and  Managing  General
   Partner personnel costs.  General and administrative costs decreased  1%
   or  approximately  $1,000 during the year ended  December  31,  2002  as
   compared to the year ended December 31, 2001.

2. Depletion expense decreased to $125,000 for the year ended December  31,
   2002  from  $240,000  for the same period in 2001.   This  represents  a
   decrease  of  48%.   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 2002 depletion  expense  by
   $34,000  and increase 2002 net income by $496,000.  See Note  4  of  the
   notes to the Partnership's financial statements.

    The  major  factor  in  the decrease in depletion expense  between  the
    comparative periods was the increase in the price of oil and  gas  used
    to determine the Partnership's reserves for January 1, 2003 as compared
    to  2002,  which provided more economically recoverable proved reserves
    at  January 1, 2003 which caused the depletion rate per equivalent unit
    produced  to  decline.  Also, as discussed above, the total  equivalent
    units produced in 2002 declined from 2001.

<PAGE>

C.  Revenue and Distribution Comparison

Partnership net income for the years ended December 31, 2003, 2002 and 2001
was   $1,021,296,   $358,225   and  $571,669,  respectively.    Partnership
distributions  for the years ended December 31, 2003, 2002  and  2001  were
$750,091,   $0   and  $1,127,395,  respectively.   These  differences   are
indicative  of the changes in oil and gas prices, production and properties
during 2003, 2002 and 2001.

The  sources  for  the  2003 distributions of $750,091  were  oil  and  gas
operations  of  approximately  $970,200 and  the  change  in  oil  and  gas
properties   of   approximately  $300,  resulting  in   excess   cash   for
contingencies or subsequent distributions.  There were no distributions for
2002.   The sources for the 2001 distributions of $1,127,395 were  oil  and
gas operations of approximately $1,095,000, with the balance from available
cash on hand at the beginning of the period.

Total  distributions during the year ended December 31, 2003 were  $750,091
of  which  $675,082 was distributed to the limited partners and $75,009  to
the  general partner.  The per unit distribution to limited partners during
the  same period was $33.75.  There were no distributions due to a decrease
in  revenues as a result of a decline in production and gas prices for  the
year  ended  December 31, 2002.  Total distributions during the year  ended
December  31,  2001 were $1,127,395 of which $1,014,895 was distributed  to
the  limited partners and $112,500 to the general partners.  The  per  unit
distribution to limited partners during the same period was $50.74.

Cumulative cash distributions of $18,203,945 have been made to the  general
and  limited  partners as of December 31, 2003.  As of December  31,  2003,
$16,399,259 or $819.96 per limited partner unit has been distributed to the
limited partners, representing a 100% return of capital and a 64% return on
capital contributed.

Liquidity and Capital Resources
The  primary source of cash is from operations, the receipt of income  from
net profits 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
$970,200   in  2003  compared  to  $(114,800)  in  2002  and  approximately
$1,094,700 in 2001.

Cash  flows  provided  by investing activities were approximately  $300  in
2003.   There  were  no cash flows provided by investing activities  during
2002  and  2001. The principal source of the 2003 cash flow from  investing
activities was the sales of oil and gas properties.

Cash  flows  (used in) provided by financing activities were  approximately
$(753,600)  in 2003 compared to $500 in 2002 and approximately $(1,126,200)
in  2001.   The  only use in financing activities was the distributions  to
partners.

As  of  December  31, 2003, the Partnership had approximately  $424,600  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.


<PAGE>

Liquidity - Managing General Partner
As  of  December 31, 2003, the Managing General Partner is in violation  of
several covenants pertaining to their Amended and Restated Revolving Credit
Agreement  due  June  1, 2006 and their Senior Second Lien  Secured  Credit
Agreement  due  October  15,  2008.  Due to the  covenant  violations,  the
Managing  General  Partner is in default under their Amended  and  Restated
Revolving  Credit  Agreement  and the Senior  Second  Lien  Secured  Credit
Agreement,  and all amounts due under these agreements have been classified
as  a current liability on the Managing General Partner's balance sheet  at
December 31, 2003.  The significant working capital deficit and debt  being
in default at December 31, 2003, raise substantial doubt about the Managing
General Partner's ability to continue as a going concern.

Subsequent  to  December 31, 2003, the Board of Directors of  the  Managing
General  Partner announced its decision to explore a merger,  sale  of  the
stock  or  other transaction involving the Managing General  Partner.   The
Board  has  formed a Special Committee of independent directors to  oversee
the   sales  process.   The  Special  Committee  has  retained  independent
financial  and  legal advisors to work closely with the management  of  the
Managing General Partner to implement the sales process.  There can  be  no
assurance  that a sale of the Managing General Partner will be  consummated
or what terms, if consummated, the sale will be on.

Recent Accounting Pronouncements
The  EITF is considering two issues related to the reporting of oil and gas
mineral  rights.  Issue No. 03-O, "Whether Mineral Rights Are  Tangible  or
Intangible Assets," is whether or not mineral rights are intangible  assets
pursuant  to  SFAS  No.  141,  "Business  Combinations."  Issue  No.  03-S,
"Application of SFAS No. 142, Goodwill and Other Intangible Assets, to  Oil
and  Gas  Companies,"  is, if oil and gas drilling  rights  are  intangible
assets,  whether  those  assets  are  subject  to  the  classification  and
disclosure provisions of SFAS No. 142.  The Partnership classifies the cost
of oil and gas mineral rights as properties and equipment and believes that
this is consistent with oil and gas accounting and industry practice.   The
disclosures required by SFAS Nos. 141 and 142 would be made in the notes to
the  financial  statements. There would be no effect on  the  statement  of
income  or  cash  flows as the intangible assets related  to  oil  and  gas
mineral rights would continue to be amortized under the full cost method of
accounting.

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk

The  Partnership  is  not a party to any derivative or embedded  derivative
instruments.


<PAGE>

Item 8.   Financial Statements and Supplementary Data

                      Index to Financial Statements

                                                                       Page

Independent Auditors' Report                                            22

Balance Sheets                                                          23

Statements of Operations                                                24

Statement of Changes in Partners' Equity                                25

Statements of Cash Flows                                                26

Notes to Financial Statements                                           27

<PAGE>










                       INDEPENDENT AUDITORS' REPORT

The Partners
Southwest Royalties, Inc. Income Fund VI
(A Tennessee Limited Partnership):


We  have  audited  the accompanying balance sheets of Southwest  Royalties,
Inc.  Income Fund VI (the "Partnership") as of December 31, 2003 and  2002,
and  the related statements of operations, changes in partners' equity  and
cash  flows  for each of the years in the three year period ended  December
31,  2003.   These  financial  statements are  the  responsibility  of  the
Partnership's management.  Our responsibility is to express an  opinion  on
these financial statements based on our audits.

We  conducted  our  audits in accordance with auditing standards  generally
accepted in the United States of America.  Those standards require that  we
plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement.  An audit  includes
examining, on a test basis, evidence supporting the amounts and disclosures
in  the  financial  statements.   An  audit  also  includes  assessing  the
accounting principles used and significant estimates made by management, as
well  as  evaluating  the  overall financial  statement  presentation.   We
believe that our audits provide a reasonable basis for our opinion.

In  our opinion, the financial statements referred to above present fairly,
in  all  material respects, the financial position of Southwest  Royalties,
Inc. Income Fund VI as of December 31, 2003 and 2002 and the results of its
operations  and  its cash flows for each of the years  in  the  three  year
period  ended  December  31, 2003 in conformity with  generally  accounting
principles generally accepted in the United States of America.

As discussed in Note 4 to the financial statements, the Partnership changed
its method of computing depletion in 2002.  Also, as discussed in Note 3 to
the  financial statements, the Partnership changed its method of accounting
for asset retirement obligations as of January 1, 2003.







                                                  KPMG LLP



Midland, Texas
March 19, 2004, except as to Note 9, which is as of May 3, 2004

<PAGE>


                 Southwest Royalties, Inc. Income Fund VI
                    (a Tennessee limited partnership)
                              Balance Sheets
                        December 31, 2003 and 2002


                                           2003      2002
                                          ------    ------
Assets
---------
Current assets:
 Cash and cash equivalents            $  234,954   18,015
  Receivable  from  Managing  General    189,477   86,014
Partner
 Oklahoma withholding prepayment         124       -
                                         --------  --------
                                         -----     -----
   Total current assets                  424,555   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            6,143,46  6,481,00
                                         0         0
                                         --------  --------
                                         -----     -----
   Net oil and gas properties            2,403,85  1,943,13
                                         7         4
                                         --------  --------
                                         -----     -----
                                      $  2,828,41  2,047,16
                                         2         3
                                         =======   =======
Liabilities and Partners' Equity
-------------------------------------
---

Current   liability  -   distribution $  -         3,356
payable
                                         --------  --------
                                         -----     -----

Asset retirement obligation              513,400   -
                                         --------  --------
                                         -----     -----

Partners' equity:
 General partner                         (622,829  (649,950
                                         )         )
 Limited partners                        2,937,84  2,693,75
                                         1         7
                                         --------  --------
                                         -----     -----
   Total partners' equity                2,315,01  2,043,80
                                         2         7
                                         --------  --------
                                         -----     -----
                                      $  2,828,41  2,047,16
                                         2         3
                                         =======   =======









                  The accompanying notes are an integral
                   part of these financial statements.

<PAGE>
                 Southwest Royalties, Inc. Income Fund VI
                    (a Tennessee limited partnership)
                         Statements of Operations
               Years ended December 31, 2003, 2002 and 2001

                                     2003      2002      2001
                                    ------    ------    ------
Revenues
-------------
   Income   from  net   profits $  1,227,58  103,085   955,342
interests                          9
 Interest                          1,178     1,137     8,810
 Other                             8,952     479       -
                                   --------  --------  --------
                                   -----     ---       ---
                                   1,237,71  104,701   964,152
                                   9
                                   --------  --------  --------
                                   -----     ---       ---
Expenses
-------------
 General and administrative        164,052   151,476   152,483
  Accretion of asset retirement    39,008    -         -
obligation
  Depreciation,  depletion  and    130,000   125,000   240,000
amortization
                                   --------  --------  --------
                                   -----     ---       ---
                                   333,060   276,476   392,483
                                   --------  --------  --------
                                   -----     ---       ---
Net    income   (loss)   before
cumulative effects
 of accounting changes             904,659   (171,775  571,669
                                             )

Cumulative effect of change  in
accounting
 principle - SFAS No. 143 - See    116,637   -         -
Note 3
Cumulative effect of change  in
accounting principle
 - change in depletion method -    -         530,000   -
See Note 4
                                   --------  --------  --------
                                   -----     ---       ---
Net income                      $  1,021,29  358,225   571,669
                                   6
                                   =======   ======    ======
Net income allocated to:

 Managing General Partner       $  102,130   35,822    51,450
                                   =======   ======    ======
 General partner                $  -         -         5,717
                                   =======   ======    ======
 Limited partners               $  919,166   322,403   514,502
                                   =======   ======    ======
    Per  limited  partner  unit $    40.71    (7.73)     25.73
before cumulative effect
     Cumulative   effects   per       5.25    23.85    -
limited partner unit
                                   --------  --------  --------
                                   -----     ---       ---
  Per limited partner unit      $    45.96    16.12      25.73
                                   =======   ======    ======
Pro   forma  amounts   assuming
changes are applied
  retroactively (See Note 3 and
4 for details):
  Net  income before cumulative $  -         (208,562  592,589
effects                                      )
                                   ======     ======   ======
    Per  limited  partner  unit $       -     (9.39)    26.67
(20,000.0 units)
                                   ======     ======   ======




                  The accompanying notes are an integral
                   part of these financial statements.
<PAGE>
                 Southwest Royalties, Inc. Income Fund VI
                    (a Tennessee limited partnership)
                 Statement of Changes in Partners' Equity
               Years ended December 31, 2003, 2002 and 2001


                           General   Limited
                           Partner   Partners   Total
                           --------  --------  --------
                             ---      -----

Balance   at  December  $  (630,439  2,871,74  2,241,30
31, 2000                   )         7         8

 Net income                57,167    514,502   571,669

 Distributions             (112,500  (1,014,8  (1,127,3
                           )         95)       95)
                           --------  --------  --------
                           -----     -----     -----
Balance   at  December     (685,772  2,371,35  1,685,58
31, 2001                   )         4         2

 Net income                35,822    322,403   358,225

 Distributions             -         -         -
                           --------  --------  --------
                           -----     -----     -----
Balance   at  December     (649,950  2,693,75  2,043,80
31, 2002                   )         7         7

 Net income                102,130   919,166   1,021,29
                                               6

 Distributions             (75,009)  (675,082  (750,091
                                     )         )
                           --------  --------  --------
                           -----     -----     -----
Balance   at  December  $  (622,829  2,937,84  2,315,01
31, 2003                   )         1         2
                           =======   =======   =======






















                  The accompanying notes are an integral
                   part of these financial statements.

<PAGE>

                 Southwest Royalties, Inc. Income Fund VI
                    (a Tennessee limited partnership)
                         Statements of Cash Flows
               Years ended December 31, 2003, 2002 and 2001

                                      2003      2002      2001
                                     ------    ------    ------
Cash   flows   from   operating
activities:
 Cash received from net profits  $  1,121,73  34,721    1,237,44
interests                           5                   0
  Cash paid to Managing General
Partner
   for administrative fees  and
general
  and administrative overhead       (161,661  (151,123  (151,578
                                    )         )         )
 Interest received                  1,178     1,137     8,810
 Miscellaneous settlement           8,952     479       -
                                    --------  --------  --------
                                    ------    -----     ------
   Net  cash provided by  (used     970,204   (114,786  1,094,67
in) operating activities                      )         2
                                    --------  --------  --------
                                    ------    -----     ------
Cash   provided  by   investing
activities:
 Sale of oil and gas properties     306       -         -
                                    --------  --------  --------
                                    ------    -----     ------
Cash  (used  in)  provided   by
financing activities:
 Distributions to partners          (753,571  519       (1,126,1
                                    )                   52)
                                    --------  --------  --------
                                    ------    -----     ------
  Net  increase  (decrease)  in     216,939   (114,267  (31,480)
cash and cash equivalents                     )

 Beginning of year                  18,015    132,282   163,762
                                    --------  --------  --------
                                    ------    -----     ------
 End of year                     $  234,954   18,015    132,282
                                    ========  =======   ========
Reconciliation of net income to
net
  cash  provided by  (used  in)
operating activities:

Net income                       $  1,021,29  358,225   571,669
                                    6

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

  Depreciation,  depletion  and     130,000   125,000   240,000
amortization
  Accretion of asset retirement     39,008    -         -
obligation
 Cumulative effect of change in     (116,637  (530,000  -
accounting principle                )         )
    (Increase)   decrease    in     (105,854  (68,364)  282,098
receivables                         )
 Increase in payables               2,391     353       905
                                    --------  --------  --------
                                    ------    -----     ------
Net  cash provided by (used in)  $  970,204   (114,786  1,094,67
operating activities                          )         2
                                    ========  =======   ========
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-    $  422       -         -
out arrangements
                                    ========  =======   ========
 Decrease in oil and gas
properties - SFAS No. 143
  sale of property               $  (25,857)  -         -
                                    ========  =======   ========
                  The accompanying notes are an integral
                   part of these financial statements.
<PAGE>
                 Southwest Royalties, Inc. Income Fund VI
                    (a Tennessee limited partnership)

                      Notes to Financial Statements

1.  Organization
          Southwest Royalties, Inc. Income Fund VI was organized under  the
    laws of the state of Tennessee on December 4, 1986, for the purpose  of
    acquiring  producing oil and gas properties and to produce  and  market
    crude  oil and natural gas produced from such properties for a term  of
    50  years, unless terminated at an earlier date as provided for in  the
    Partnership  Agreement.   The  Partnership  sells  its  oil   and   gas
    production to a variety of purchasers with the prices it receives being
    dependent  upon  the  oil and gas economy.  Southwest  Royalties,  Inc.
    serves as the Managing General Partner and H. H. Wommack, III, was  the
    individual  general partner.  Effective December 31, 2001, Mr.  Wommack
    sold  his  general  partner interest to the Managing  General  Partner.
    Revenues, costs and expenses are allocated as follows:

                                                    Limite  General
                                                       d
                                                    Partne  Partner
                                                      rs       s
                                                    ------  -------
                                                     -----   -----
             Interest     income    on     capital   100%      -
             contributions
             Oil and gas sales                        90%     10%
             All other revenues                       90%     10%
             Organization and offering costs (1)     100%      -
             Amortization of organization costs      100%      -
             Property acquisition costs              100%      -
             Gain/loss on property disposition        90%     10%
             Operating  and  administrative  costs    90%     10%
             (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

    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.

    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.  In applying the units-of-revenue  method
    for  the year ended December 31, 2001, we have not excluded royalty and
    net  profit interest payments from gross revenues as all of our royalty
    and  net  profit interests have been purchased and capitalized  to  the
    depletion  basis of our proved oil and gas properties.  As of  December
    31,  2003, 2002 and 2001, the net capitalized costs did not exceed  the
    estimated present value of oil and gas reserves.

    The  Partnership's interest in oil and gas properties consists  of  net
    profits  interests in proved properties located within the  continental
    United States.  A net profits interest is created when the owner  of  a
    working  interest  in  a property enters into an arrangement  providing
    that the net profits interest owner will receive a stated percentage of
    the  net profit from the property.  The net profits interest owner will
    not  otherwise  participate in additional costs  and  expenses  of  the
    property.

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

                      Notes to Financial Statements

2.  Summary of Significant Accounting Policies - continued

    Oil and Gas Properties - continued
   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 December 31, 2003,  there
   were  no  timing  differences, which resulted in a  deficit  net  profit
   interest.

    Estimates and Uncertainties
    The  preparation of financial statements in conformity  with  generally
    accepted  accounting principles requires management to  make  estimates
    and  assumptions  that  affect  the  reported  amounts  of  assets  and
    liabilities and disclosure of contingent assets and liabilities at  the
    date  of  the financial statements and the reported amounts of revenues
    and  expenses during the reporting period.  The Partnerships  depletion
    calculation and full cost ceiling test for oil and gas properties  uses
    oil  and gas reserve estimates, which are inherently imprecise.  Actual
    results could differ from those estimates.

         Syndication Costs
          Syndication costs are accounted for as a reduction of partnership
    equity.

    Environmental Costs
    The  Partnership  is  subject to extensive  federal,  state  and  local
    environmental  laws and regulations.  These laws, which are  constantly
    changing, regulate the discharge of materials into the environment  and
    may  require  the  Partnership to remove or mitigate the  environmental
    effects  of the disposal or release of petroleum or chemical substances
    at   various   sites.   Environmental  expenditures  are  expensed   or
    capitalized  depending on their future economic benefit.  Costs,  which
    improve a property as compared with the condition of the property  when
    originally  constructed  or acquired and costs,  which  prevent  future
    environmental contamination are capitalized.  Expenditures that  relate
    to  an  existing condition caused by past operations and that  have  no
    future economic benefits are expensed.  Liabilities for expenditures of
    a  non-capital nature are recorded when environmental assessment and/or
    remediation is probable, and the costs can be reasonably estimated.

    Revenue Recognition
    We  recognize  oil  and gas sales when delivery to  the  purchaser  has
    occurred  and  title has transferred.  This occurs when production  has
    been delivered to a pipeline or transport vehicle.

    Gas Balancing
    The  Partnership  utilizes  the sales method  of  accounting  for  gas-
    balancing  arrangements.  Under this method the Partnership  recognizes
    sales  revenue on all gas sold.  As of December 31, 2003 and 2002,  the
    Partnership was under produced by 4,075 and 6,237 mcf of gas.

<PAGE>

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

                      Notes to Financial Statements

2.  Summary of Significant Accounting Policies - continued

    Income Taxes
    No   provision  for  income  taxes  is  reflected  in  these  financial
    statements, since the tax effects of the Partnership's income  or  loss
    are passed through to the individual partners.

    In   accordance  with  the  requirements  of  Statement  of   Financial
    Accounting  Standards  No.  109, "Accounting  for  Income  Taxes",  the
    Partnership's tax basis in its net oil and gas properties  at  December
    31, 2003 and 2002 is $1,996,474 and $1,460,128, respectively, less than
    that  shown  on  the  accompanying Balance Sheets  in  accordance  with
    generally accepted accounting principles.

    Cash and Cash Equivalents
    For purposes of the statements of cash flows, the Partnership considers
    all  highly liquid debt instruments purchased with a maturity of  three
    months  or less to be cash equivalents.  The Partnership maintains  its
    cash at one financial institution.

    Number of Limited Partner Units
    As  of  December  31,  2003, 2002 and 2001, there were  20,000  limited
    partner units outstanding held by 667, 669 and 669 partners.

    Concentrations of Credit Risk
    The  Partnership  is subject to credit risk through trade  receivables.
    Although  a  substantial  portion of its debtors'  ability  to  pay  is
    dependent  upon the oil and gas industry, credit risk is minimized  due
    to a large customer base.  All partnership revenues are received by the
    Managing  General Partner and subsequently remitted to the  partnership
    and  all  expenses  are  paid  by  the  Managing  General  Partner  and
    subsequently reimbursed by the partnership.

    Fair Value of Financial Instruments
    The  carrying amount of cash and accounts receivable approximates  fair
    value due to the short maturity of these instruments.

    Net Income (loss) per limited partnership unit
    The  net  income (loss) per limited partnership unit is  calculated  by
    using the number of outstanding limited partnership units.

    Recent Accounting Pronouncements
   The  EITF is considering two issues related to the reporting of oil  and
   gas  mineral  rights.  Issue  No.  03-O,  "Whether  Mineral  Rights  Are
   Tangible  or  Intangible Assets," is whether or not mineral  rights  are
   intangible  assets  pursuant to SFAS No. 141,  "Business  Combinations."
   Issue  No.  03-S,  "Application of SFAS  No.  142,  Goodwill  and  Other
   Intangible  Assets,  to  Oil and Gas Companies,"  is,  if  oil  and  gas
   drilling rights are intangible assets, whether those assets are  subject
   to  the  classification and disclosure provisions of SFAS No. 142.   The
   Partnership  classifies  the  cost of oil  and  gas  mineral  rights  as
   properties and equipment and believes that this is consistent  with  oil
   and  gas accounting and industry practice.  The disclosures required  by
   SFAS  Nos.  141  and  142 would be made in the notes  to  the  financial
   statements. There would be no effect on the statement of income or  cash
   flows  as  the  intangible assets related to oil and gas mineral  rights
   would   continue  to  be  amortized  under  the  full  cost  method   of
   accounting.

   Depletion Policy
   In  2002, the Partnership changed methods of accounting for depletion of
   capitalized  costs  from the units-of-revenue method  to  the  units-of-
   production method. (See Note 4)

<PAGE>

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

                      Notes to Financial Statements

3.  Cumulative effect of change in accounting principle - SFAS No. 143
    On  January  1,  2003, the Partnership adopted Statement  of  Financial
    Accounting   Standards  No.  143,  Accounting  for   Asset   Retirement
    Obligations ("SFAS No. 143").  Adoption of SFAS No. 143 is required for
    all companies with fiscal years beginning after June 15, 2002.  The new
    standard  requires  the Partnership to recognize a  liability  for  the
    present  value of all legal obligations associated with the  retirement
    of  tangible long-lived assets and to capitalize an equal amount  as  a
    cost of the asset and depreciate the additional cost over the estimated
    useful life of the asset.  On January 1, 2003, the Partnership recorded
    additional  costs,  net of accumulated depreciation,  of  approximately
    $616,464, a long term liability of approximately $499,827 and a gain of
    approximately $116,637 for the cumulative effect on depreciation of the
    additional  costs  and  accretion expense on the liability  related  to
    expected  abandonment  costs  of  its oil  and  natural  gas  producing
    properties.  At December 31, 2003, the asset retirement obligation  was
    $513,400.  The increase in the asset retirement obligation from January
    1,  2003  is due to accretion expense of $39,008 plus additional  wells
    added  for  $422  offset by decrease of $25,857  due  to  the  sale  of
    properties.   The pro forma amounts of the asset retirement  obligation
    as  of  December 31, 2002, 2001 and 2000, were approximately  $499,827,
    $463,040  and  $428,960, respectively.  The pro forma  amounts  of  the
    asset   retirement   obligation   were  measured   using   information,
    assumptions  and interest rates as of the adoption date of  January  1,
    2003.

                                     2002      2001
                                    ------    ------
Pro   forma  amounts   assuming
change is applied
 retroactively:
  Net  income before cumulative
effect
    for   change  in  depletion $  (208,562  537,589
method                             )
                                    ======   ======
    Per  limited  partner  unit $   (9.39)    24.19
(20,000.0 units)
                                    ======   ======
 Net income                     $  321,438   537,589
                                    ======   ======
    Per  limited  partner  unit $    14.46    24.19
(20,000.0 units)
                                    ======   ======

4.   Cumulative  effect  of a change in accounting principle  -  change  in
depletion method
    In 2002, the Partnership changed methods of accounting for depletion of
    capitalized  costs from the units-of-revenue method  to  the  units-of-
    production   method.   The  newly  adopted  accounting   principle   is
    preferable in the circumstances because the units-of-production  method
    results  in  a  better matching of the costs of oil and gas  production
    against the related revenue received in periods of volatile prices  for
    production  as  have been experienced in recent periods.  Additionally,
    the  units-of-production method is the predominant method used by  full
    cost  companies  in the oil and gas industry, accordingly,  the  change
    improves  the  comparability of the Partnership's financial  statements
    with  its  peer group.  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 years ended 2003 and 2002
    has  been calculated using the units-of-production method and 2001  has
    not been restated.  The pro forma amounts for 2001, which are presented
    below,  reflect the effect of retroactive application of the  units-of-
    production  method.   See  Note 11 for the effects  of  the  change  in
    depletion method on the individual quarters of 2002.

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

                      Notes to Financial Statements

4.    Cumulative  effect of a change in accounting principle  -  change  in
depletion method - continued

                                     2001

                                    ------
Pro   forma  amounts   assuming
change is applied
 retroactively:
 Net income                     $  626,669
                                   ======
    Per  limited  partner  unit $   28.20
(20,000.0 units)
                                   ======

5. Liquidity - Managing General Partner
    As  of  December 31, 2003, the Managing General Partner is in violation
    of several covenants pertaining to their Amended and Restated Revolving
    Credit  Agreement due June 1, 2006 and their Senior Second Lien Secured
    Credit Agreement due October 15, 2008.  Due to the covenant violations,
    the  Managing  General Partner is in default under  their  Amended  and
    Restated Revolving Credit Agreement and the Senior Second Lien  Secured
    Credit Agreement, and all amounts due under these agreements have  been
    classified  as  a  current liability on the Managing General  Partner's
    balance  sheet  at December 31, 2003.  The significant working  capital
    deficit  and  debt  being  in  default  at  December  31,  2003,  raise
    substantial  doubt  about  the Managing General  Partner's  ability  to
    continue as a going concern.

    Subsequent to December 31, 2003, the Board of Directors of the Managing
    General Partner announced its decision to explore a merger, sale of the
    stock or other transaction involving the Managing General Partner.  The
    Board  has  formed  a  Special Committee of  independent  directors  to
    oversee   the  sales  process.   The  Special  Committee  has  retained
    independent  financial  and legal advisors to  work  closely  with  the
    management  of  the  Managing General Partner to  implement  the  sales
    process.  There can be no assurance that a sale of the Managing General
    Partner  will  be consummated or what terms, if consummated,  the  sale
    will be on.

6.  Commitments and Contingent Liabilities
    After  completion  of  the  Partnership's first  full  fiscal  year  of
    operations  and each year thereafter, the Managing General Partner  has
    offered  and will continue to offer to purchase each limited  partner's
    interest  in the Partnership.  The pricing mechanism used to  calculate
    the repurchase is based on tangible assets of the Partnership, plus the
    present  value  of  the  future net revenues  of  proved  oil  and  gas
    properties, minus liabilities with a risk factor discount of up to one-
    third  which may be implemented at the sole discretion of the  Managing
    General Partner.  However, the Managing General Partner's obligation to
    purchase  limited partner units is limited to an annual expenditure  of
    an  amount  not  in  excess of 10% of the total limited  partner  units
    initially subscribed for by limited partners.


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

                      Notes to Financial Statements

6.  Commitments and Contingent Liabilities - continued
    The  Partnership  is  subject  to  various  federal,  state  and  local
    environmental  laws  and  regulations, which  establish  standards  and
    requirements for protection of the environment.  The Partnership cannot
    predict the future impact of such standards and requirements, which are
    subject  to  change  and  can  have  retroactive  effectiveness.    The
    Partnership  continues  to  monitor  the  status  of  these  laws   and
    regulations.

    As  of December 31, 2003, the Partnership has not been fined, cited  or
    notified of any environmental violations and management is not aware of
    any  unasserted violations, which would have a material adverse  effect
    upon capital expenditures, earnings or the competitive position in  the
    oil  and  gas  industry.  However, the Managing  General  Partner  does
    recognize by the very nature of its business, material costs  could  be
    incurred  in  the  near  term  to  bring  the  Partnership  into  total
    compliance.  The amount of such future expenditures is not determinable
    due  to  several factors, including the unknown magnitude  of  possible
    contaminations, the unknown timing and extent of the corrective actions
    which may be required, the determination of the Partnership's liability
    in proportion to other responsible parties and the extent to which such
    expenditures  are  recoverable from insurance or indemnifications  from
    prior owners of the Partnership's properties.

7.  Related Party Transactions
    A  significant  portion  of the oil and gas  properties  in  which  the
    Partnership  has  an  interest are operated by and purchased  from  the
    Managing  General Partner.  As provided for in the operating  agreement
    for  each respective oil and gas property in which the Partnership  has
    an interest, the operator is paid an amount for administrative overhead
    attributable  to  operating  such  properties,  with  such  amounts  to
    Southwest  Royalties, Inc. as operator approximating  $83,000,  $98,600
    and  $105,000,  for the years ended December 31, 2003, 2002  and  2001,
    respectively.  The amounts for administrative overhead attributable  to
    operating the partnerships properties has been deducted from gross  oil
    and  gas  revenues  in  the determination of net  profit  interest.  In
    addition,  the  Managing  General  Partner  and  certain  officers  and
    employees  may have an interest in some of the properties in which  the
    Partnership also participates.

    Southwest  Royalties,  Inc., the Managing  General  Partner,  was  paid
    $144,000  during  2003,  2002 and 2001, as an  administrative  fee  for
    indirect   general   and   administrative   overhead   expenses.    The
    administrative fees are included in general and administrative  expense
    on the statement of operations.

    Receivables  from  Southwest  Royalties,  Inc.,  the  Managing  General
    Partner,  of  approximately $189,500 and $86,000 are from oil  and  gas
    production,  net of lease operating costs and production taxes,  as  of
    December 31, 2003 and 2002, respectively.

8.  Major Customers
    No  material  portion of the Partnership's business is dependent  on  a
    single purchaser, or a very few purchasers, where the loss of one would
    have  a  material  adverse impact on the Partnership.   Two  purchasers
    accounted  for  69% of the Partnership's total oil and  gas  production
    during  2003:   Duke  Energy  Field Services  LP  for  54%  and  Plains
    Marketing  LP  for  15%.   Two purchasers  accounted  for  59%  of  the
    Partnership's  total oil and gas production during 2002:   Duke  Energy
    Field  Service  LP  for  42%  and Plains Marketing  LP  for  17%.   Two
    purchasers  accounted for 68% of the Partnership's total  oil  and  gas
    production  during 2001:  Duke Energy Field Services  LP  for  55%  and
    Plains  Marketing LP for 13%.  All purchasers of the Partnership's  oil
    and  gas production are unrelated third parties.  In the event  any  of
    these  purchasers  were  to  discontinue purchasing  the  Partnership's
    production,  the  Managing General Partner believes that  a  substitute
    purchaser or purchasers could be located without undue delay.  No other
    purchaser accounted for an amount equal to or greater than 10%  of  the
    Partnership's sales of oil and gas production.

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

                      Notes to Financial Statements

9.  Subsequent Event
    Subsequent to December 31, 2003, the Managing General Partner announced
    that its Board of Directors had decided to explore a merger or sale  of
    the  stock  of  the Company.  The Board formed a Special  Committee  of
    independent  directors  to  oversee  the  sale  process.   The  Special
    Committee  retained independent financial and legal  advisors  to  work
    closely with management to implement the sale process.

    On May 3, 2004, the Managing General Partner entered into a cash merger
    agreement  to  sell all of its stock to Clayton Williams  Energy,  Inc.
    The  cash  merger  price is being negotiated, but  is  expected  to  be
    approximately  $45  per share.  The transaction, which  is  subject  to
    approval by the Managing General Partner's shareholders, is expected to
    close no later than May 21, 2004.

10. Estimated Oil and Gas Reserves (unaudited)
    The  Partnership's  interest  in proved oil  and  gas  reserves  is  as
    follows:

                                Oil       Gas
                               (bbls)    (mcf)
                              --------  --------
                                ----     -----
Total Proved -

January 1, 2001               388,000   5,622,00
                                        0

      Revisions of  previous  (221,000  114,000
estimates                     )
     Production               (29,000)  (368,000
                                        )
                              --------  --------
                              ----      ------
December 31, 2001             138,000   5,368,00
                                        0

      Revisions of  previous  86,000    (725,000
estimates                               )
     Production               (26,000)  (235,000
                                        )
                              --------  --------
                              ----      ------
December 31, 2002             198,000   4,408,00
                                        0

      Sales  of reserves  in  (3,000)   (13,000)
place
      Revisions of  previous  12,000    1,129,00
estimates                               0
     Production               (22,000)  (275,000
                                        )
                              --------  --------
                              ----      ------
December 31, 2003             185,000   5,249,00
                                        0
                              =======   ========
Proved developed reserves -
December 31, 2001             98,000    5,017,00
                                        0
                              =======   ========
December 31, 2002             161,000   4,067,00
                                        0
                              =======   ========
December 31, 2003             138,000   4,018,00
                                        0
                              =======   ========

    All  of  the  Partnership's reserves are located within the continental
    United States.

<PAGE>

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

                      Notes to Financial Statements

10. Estimated Oil and Gas Reserves (unaudited) - continued

    *Ryder Scott Company, L.P. prepared the reserve and present value  data
    for  the Partnership's existing properties as of January 1, 2004.   The
    reserve  estimates were made in accordance with guidelines  established
    by  the Securities and Exchange Commission pursuant to Rule 4-10(a)  of
    Regulation S-X.  Such guidelines require oil and gas reserve reports be
    prepared  under  existing  economic and operating  conditions  with  no
    provisions   for  price  and  cost  escalation  except  by  contractual
    arrangements.

   Oil  price  adjustments  were  made in  the  individual  evaluations  to
   reflect  oil  quality, gathering and transportation costs.  The  results
   of  the  reserve  report as of January 1, 2004, 2003  and  2002  are  an
   average price of $31.26, $29.47 and $18.50 per barrel.

    Gas  price  adjustments  were  made in the  individual  evaluations  to
    reflect  BTU  content,  gathering  and  transportation  costs  and  gas
    processing  and  shrinkage.  The results of the reserve  report  as  of
    January 1, 2004, 2003 and 2002 are an average price of $5.31, $4.36 and
    $2.14 per Mcf.

    The  evaluation of oil and gas properties is not an exact  science  and
    inevitably  involves a significant degree of uncertainty,  particularly
    with  respect to the quantity of oil or gas that any given property  is
    capable  of producing.  Estimates of oil and gas reserves are based  on
    available  geological and engineering data, the extent and  quality  of
    which may vary in each case and, in certain instances, may prove to  be
    inaccurate.  Consequently, properties may be depleted more rapidly than
    the geological and engineering data have indicated.

    Unanticipated  depletion, if it occurs, will result in  lower  reserves
    than  previously  estimated; thus an ultimately lower  return  for  the
    Partnership.   Basic changes in past reserve estimates occur  annually.
    As  new data is gathered during the subsequent year, the engineer  must
    revise  his  earlier  estimates.  A year of new information,  which  is
    pertinent to the estimation of future recoverable volumes, is available
    during  the subsequent year evaluation.  In applying industry standards
    and  procedures,  the new data may cause the previous estimates  to  be
    revised.   This revision may increase or decrease the earlier estimated
    volumes.

    The  Partnership has reserves, which are classified as proved developed
    and proved undeveloped.  All of the proved reserves are included in the
    engineering reports, which evaluate the Partnership's present reserves.

    Because  the  Partnership does not engage in drilling  activities,  the
    development  of  proved undeveloped reserves is conducted  pursuant  to
    farm-out  arrangements with the Managing General Partner  or  unrelated
    third  parties.  Generally, the Partnership retains a carried  interest
    such as an overriding royalty interest under the terms of a farm-out.

<PAGE>

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

                      Notes to Financial Statements

10. Estimated Oil & Gas Reserves (unaudited) - continued
    The  standardized measure of discounted future net cash flows  relating
    to  proved oil and gas reserves at December 31, 2003, 2002 and 2001  is
    presented below:

                            2003      2002      2001
                           ------    ------    ------
Future cash inflows    $  33,658,0  25,032,0  14,068,0
                          00        00        00
Production,
development
    and   abandonment     8,608,00  7,063,00  4,299,00
costs                     0         0         0
                          --------  --------  --------
                          ------    ------    ------
Future net cash flows     25,050,0  17,969,0  9,769,00
                          00        00        0
10%  annual  discount
for
  estimated timing of
cash
 flows                    13,629,0  9,795,00  5,238,00
                          00        0         0
                          --------  --------  --------
                          ------    ------    -----
Standardized  measure
of
   discounted  future
net cash
 flows                 $  11,421,0  8,174,00  4,531,00
                          00        0         0
                          ========  ========  ========

     The  principal  sources  of  change in  the  standardized  measure  of
     discounted  future  net cash flows for the years  ended  December  31,
     2003, 2002 and 2001 are as follows:

                            2003      2002      2001
                            ----      ----      ----
Sales of oil and  gas
produced,
  net  of  production  $  (1,228,0  (103,000  (955,000
costs                     00)       )         )
Changes in prices and
production
 costs                    1,679,00  4,041,00  (16,948,
                          0         0         000)
Changes  in estimated
future
 development cost         -         23,000    -
Changes of production
rates
 (timing) and others      (151,000  (466,000  (1,136,0
                          )         )         00)
Sales of minerals  in     (18,000)  -         -
place
Revisions of previous
 quantities estimates     2,148,00  (305,000  (891,000
                          0         )         )
Accretion of discount     817,000   453,000   2,224,00
                                              0
Discounted future net
cash flows -
 Beginning of year        8,174,00  4,531,00  22,237,0
                          0         0         00
                          --------  --------  --------
                          ------    ----      ------
 End of year           $  11,421,0  8,174,00  4,531,00
                          00        0         0
                          ========  =======   ========

     Future  net cash flows were computed using year-end prices  and  costs
     that  related  to existing proved oil and gas reserves  in  which  the
     Partnership has mineral interests.


<PAGE>

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

                      Notes to Financial Statements

11.  Selected Quarterly Financial Results - (unaudited)

                                             Quarter
                              --------------------------------------
                              --------------------------------------
                                                -
                               First     Second    Third     Fourth
                               ------   --------  -------   --------
                                          ---                  -
2003:
 Total revenues             $ 297,298   331,781   292,700   315,940
 Total expenses               75,474    97,421    87,119    73,046
  Net income (loss) before
cumulative effect
     of   a   change    in    221,824   234,360   205,581   242,894
accounting principle
 Cumulative effect of SFAS    116,637   -         -         -
No. 143
                              --------  --------  --------  --------
                              ----      ----      ----      ----
 Net income (loss)          $ 338,461   234,360   205,581   242,894
                              =======   =======   =======   =======
Per  limited partner  unit
amounts:
  Net income (loss) before
cumulative effect
     of   a   change    in  $   9.98
accounting principle                    10.55     9.25      10.93
 Cumulative effect of SFAS      5.25         -         -         -
No. 143
                              --------  --------  --------  --------
                              ----      ----      ----      ----
 Net income (loss)          $  15.23
                                        10.55     9.25      10.93
                              =======   =======   =======   =======

     As  discussed  in Note 4, in 2002 the Partnership changed  methods  of
     accounting  for  depletion  of capitalized costs  from  the  units-of-
     revenue  method to the units-of-production method.  The 2002 quarterly
     financial  results  presented below reflect the  change  in  depletion
     method effective as of January 1, 2002.

                                             Quarter
                              --------------------------------------
                              --------------------------------------
                                                -
                               First     Second    Third     Fourth
                               ------   --------  -------   --------
                                          ---                  -
2002:
 Total revenues             $ 18,154    (6,263)   3,752     89,058
 Total expenses               73,126    74,966    62,469    65,915
                              --------  --------  --------  --------
                              ----      ----      ----      ----
   Income  (loss)   before
cumulative effect of
   a  change in accounting    (54,972)  (81,229)  (58,717)  23,143
principle
   Cumulative  effect   on
prior years (to
   December 31,  2001)  of
changing to a
     different   depletion    530,000   -         -         -
method
                              --------  --------  --------  --------
                              ----      ----      ----      ----
 Net income (loss)          $ 475,028   (81,229)  (58,717)  23,143
                              =======   =======   =======   =======
  Per limited partner unit
amounts:
   Income  (loss)   before
cumulative effect of a
    change  in  accounting  $ (2.48)
principle                               (3.66)    (2.64)    1.05
   Cumulative  effect   on
prior years (to
   December 31,  2001)  of
changing to a
     different   depletion     23.85         -         -         -
method
                              --------  --------  --------  --------
                              ----      ----      ----      ----
Net income (loss)           $  21.37
                                        (3.66)    (2.64)    1.05
                              =======   =======   =======   =======
<PAGE>

Item 9.                                  Changes in and Disagreements  With
          Accountants on Accounting and Financial Disclosure

None

Item 9A.  Controls and Procedures

Disclosure Controls and Procedures
As  of  the year ended December 31, 2003, H.H. Wommack, III, President  and
Chief  Executive  Officer  of the Managing General  Partner,  and  Bill  E.
Coggin,  Executive  Vice  President and  Chief  Financial  Officer  of  the
Managing  General Partner, evaluated the effectiveness of the Partnership's
disclosure  controls  and  procedures.  Based  on  their  evaluation,  they
believe that:

     The  disclosure  controls  and  procedures  of  the  Partnership  were
     effective in ensuring that information required to be disclosed by the
     Partnership in the reports it files or submits under the Exchange  Act
     was  recorded,  processed,  summarized and reported  within  the  time
     periods specified in the SEC's rules and forms; and

     The  disclosure  controls  and  procedures  of  the  Partnership  were
     effective  in  ensuring  that  material  information  required  to  be
     disclosed by the Partnership in the report it filed or submitted under
     the  Exchange  Act was accumulated and communicated  to  the  Managing
     General  Partner's  management,  including  its  President  and  Chief
     Executive Officer and Chief Financial Officer, as appropriate to allow
     timely decisions regarding required disclosure.

Internal Control Over Financial Reporting
There  has  not been any change in the Partnership's internal control  over
financial reporting that occurred during the year ended December  31,  2003
that has materially affected, or is reasonably likely to materially affect,
it internal control over financial reporting.

<PAGE>

                                 Part III

Item 10.  Directors and Executive Officers of the Registrant

Management of the Partnership is provided by Southwest Royalties, Inc.,  as
Managing  General Partner.  The names, ages, offices, positions and  length
of  service of the directors and executive officers of Southwest Royalties,
Inc.  are  set  forth below.  Each director and executive  officer  of  the
Managing General Partner serves for a term of one year.

         Name               Age               Position
-----------------------     ---     -----------------------------
----------------------      --      -----------------------------
H. H. Wommack, III          48      Chairman   of   the    Board,
                                    President, Director
                                    and Chief Executive Officer
James N. Chapman(1)         41      Director
William P. Nicoletti(2)     58      Director
Joseph J. Radecki,  Jr.     45      Director
(2)
Richard D. Rinehart(1)      68      Director
John M. White(2)            48      Director
Herbert  C. Williamson,     55      Director
III(1)
Bill E. Coggin              49      Executive Vice President  and
                                    Chief Financial Officer
J. Steven Person            45      Vice President, Marketing

(1)  Member of the Compensation Committee

(2)  Member of the Audit Committee

H.  H.  Wommack, III has served as Chairman of the Board, President,  Chief
Executive Officer and a director since Southwest's founding in 1983.  Since
1997  Mr.  Wommack  has  served as President, Chief Executive  Officer  and
Chairman of SRH, Southwest's former parent and current holder of 10% of its
voting  share capital.  SRH holds an equity investment in Southwest and  in
Basic  Energy Services.  Since 1997 Mr. Wommack has served as  chairman  of
the  board  of directors of Midland Red Oak Realty, Inc.  Midland  Red  Oak
Realty  owns  and  manages  commercial real  estate  properties,  including
shopping centers and office buildings, in secondary real estate markets  in
the Southwestern United States.  From 1997 until December 2000, Mr. Wommack
served as chairman of the board of directors of Basic Energy Services, Inc.
and  since  December  2000  has continued to  serve  on  Basic's  board  of
directors.  Basic provides certain well services for oil and gas companies.
Prior to Southwest's formation, Mr. Wommack was a self-employed independent
oil  and  gas  producer engaged in the purchase and  sale  of  royalty  and
working  interests in oil and gas leases and the drilling  of  wells.   Mr.
Wommack graduated from the University of North Carolina at Chapel Hill  and
received his law degree from the University of Texas.

James  N. Chapman has served as director since April 19, 2002.  Mr. Chapman
is  associated  with  Regiment Capital Advisors, LLC, which  he  joined  in
January  2003.   Prior to Regiment, Mr. Chapman acted as a capital  markets
and  strategic  planning consultant with private and public  companies,  as
well as hedge funds, across a range of industries. Prior to establishing an
independent  consulting practice, Mr. Chapman worked for The  Renco  Group,
Inc. from December 1996 to December 2001.  Prior to Renco, Mr. Chapman  was
a  founding  principal of Fieldstone Private Capital Group in August  1990.
Prior  to joining Fieldstone, Mr. Chapman worked for Bankers Trust  Company
from  July 1985 to August 1990, most recently in the BT Securities  capital
markets area.  Mr. Chapman serves as a member of the board of directors  of
Anchor  Glass  Container Corporation, Davel Communications, Inc.,  Coinmach
Corporation, as well as a number of private companies.

William  P. Nicoletti has served as a director since April 19,  2002.   Mr.
Nicoletti  is Managing Director of Nicoletti & Company Inc., an  investment
banking  and financial advisory firm he founded in 1991.  He was previously
a  senior officer and head of the Energy Investment Banking Groups of E. F.
Hutton  &  Company Inc. and Paine Webber, Incorporated.   From  March  1998
until June 1990 he was a managing director and co-head of Energy Investment
Banking  at  McDonald Investments Inc.  Mr. Nicoletti  is  a  director  and
Chairman  of  the Audit Committee of Star Gas Partners, L.P., the  nation's
largest  retail  distributor  of  home  heating  oil  and  a  major  retail
distributor  of  propane  gas.  He is also a director  of  MarkWest  Energy
Partners,  L.P.,  a  business engaged in the gathering  and  processing  of
natural  gas and the fractionation and storage of natural gas liquids,  and
Russell-Stanley Holdings, Inc., a manufacturer and marketer  of  steel  and
plastic  industrial containers.  Mr. Nicoletti is a graduate of Seton  Hall
University  and  received an MBA degree from Columbia  University  Graduate
School of Business.

<PAGE>
Joseph J. Radecki, Jr. has served as a director since April 19, 2002.   Mr.
Radecki is currently a Managing Director in the Leveraged Finance Group  of
CIBC  World  Markets  where he is principally responsible  for  the  firm's
financial restructuring and distressed situation advisory practice.   Prior
to  joining  CIBC World Markets in 1998, Mr. Radecki was an Executive  Vice
President and Director of the Financial Restructuring Group of Jefferies  &
Company,  Inc.  beginning in 1990.  From 1983 until 1990, Mr.  Radecki  was
First  Vice President in the International Capital Markets Group at  Drexel
Burnham Lambert, Inc., where he specialized in financial restructurings and
recapitalizations.   Over the past fourteen years,  Mr.  Radecki  has  been
integrally involved in over 120 transactions totaling nearly $50 billion in
recapitalized  securities.  Mr. Radecki currently serves as a  Director  of
RBX  Corporation,  a  manufacturer of rubber and  plastic  foam  and  other
polymer  products.   He  previously served  as  a  Director  of  Wherehouse
Entertainment, Inc., a music and video specialty retailer, as  Chairman  of
the  Board  of  American  Rice,  Inc., an  international  rice  miller  and
marketer,  as  a  member  of  the  Board of Directors  of  Service  America
Corporation,   a   national   food   service   management   firm,   Bucyrus
International, Inc., a mining equipment manufacturer, and ECO-Net,  a  non-
profit  engineering related network firm.  Mr. Radecki graduated magna  cum
laude in 1980 from Georgetown University with a B.A. in Government.

Richard  D.  Rinehart has served as a director since April 19,  2002.   Mr.
Rinehart is a founding principal of PetroCap, Inc. and president of Kestrel
Resources,  Inc.   PetroCap, Inc. provides investment and merchant  banking
services  to  a  variety  of clients active in the oil  and  gas  industry.
Kestrel Resources, Inc. is a privately owned oil and gas operating company.
He  served  as Director of Coopers & Lybrand's Energy Systems and  Services
Division prior to the founding of Kestrel Resources, Inc. in 1992. Prior to
joining  Coopers & Lybrand, he was chief executive officer/founder of  Dawn
Information  Resources,  Inc., formed in 1986 and  acquired  by  Coopers  &
Lybrand  in  early  1991.  Mr. Rinehart served as CEO  of  Terrapet  Energy
Corporation during the period 1982 through 1986. Prior to the formation  of
Terrapet in 1982, he was employed as President of the Terrapet Division  of
E.I.  DuPont de Nemours and Company. Before its acquisition by  DuPont,  he
served  as  CEO and President of Terrapet Corp., a privately owned  E  &  P
company. Before the formation of Terrapet Corp. in 1972, he was manager  of
supplementary recovery methods and senior evaluation engineer  with  H.  J.
Gruy and Associates, Inc., Dallas, Texas.

John  White has served as a director since April 19, 2002. Mr. White became
an  equity  analyst for Harris Nesbitt Gerard following the acquisition  by
BMO  Financial  Group in 2003.  He had joined BMO Nesbitt  Burns  in  1998,
responsible  for  high  yield research on oil, gas  and  energy  companies.
Previously,  Mr.  White worked at John S. Herold, Inc., an independent  oil
and  gas  research and consulting firm, where he was responsible for  fixed
income  research  on the oil and gas industry.  His prior  experience  also
included four years managing a portfolio of oil and gas loans for The  Bank
of Nova Scotia.  Before entering financial services, Mr. White was with BP,
where he worked in exploration and production for seven years.  At BP,  his
experience  was  primarily  in the basins of the  Mid-Continent  and  Rocky
Mountain regions.  Mr. White is a graduate of The University of Oklahoma.

Herbert  C. Williamson, III has served as a director since April 19,  2002.
At  present, Mr. Williamson is self-employed as a consultant.   From  March
2001  to  March  2002  Mr. Williamson served as an investment  banker  with
Petrie  Parkman & Co.  From April 1999 to March 2001 Mr. Williamson  served
as chief financial officer and from August 1999 to March 2001 as a director
of  Merlon  Petroleum  Company, a private oil and gas company  involved  in
exploration  and production in Egypt.  Mr. Williamson served  as  executive
vice  president,  chief  financial  officer  and  director  of  Seven  Seas
Petroleum,  Inc., a publicly traded oil and gas exploration  company,  from
March  1998  to  April 1999.  From 1995 through April 1998,  he  served  as
director  in  the  Investment Banking Department  of  Credit  Suisse  First
Boston.   Mr.  Williamson  served  as  vice  chairman  and  executive  vice
president  of Parker and Parsley Petroleum Company, a publicly  traded  oil
and  gas  exploration company (now Pioneer Natural Resources Company)  from
1985 through 1995.

Bill  E.  Coggin  has served as Vice President and Chief Financial  Officer
since joining the Managing General Partner in 1985.  Previously, Mr. Coggin
was  Controller  for Rod Ric Corporation, an oil and gas drilling  company,
and  for  C.F.  Lawrence  &  Associates, a large independent  oil  and  gas
operator.  Mr. Coggin received a B.S. in Education and a B.A. in Accounting
from Angelo State University.

J.  Steven Person has served as Vice President, Marketing since joining the
Managing  General  Partner in 1989.  Mr. Person  began  in  the  investment
industry  with Dean Witter in 1983.  Prior to joining the Managing  General
Partner, Mr. Person was a senior wholesaler with Capital Realty, Inc. While
at  Capital  Realty, he was involved in the syndication of  mortgage  based
securities  through  the major brokerage houses.   Mr.  Person  received  a
B.B.A.  degree  from Baylor University and an M.B.A. from  Houston  Baptist
University.

<PAGE>

Key Employees

Jon  P.  Tate,  age  46, has served as Vice President, Land  and  Assistant
Secretary  of the Managing General Partner since 1989. From 1981  to  1989,
Mr.  Tate  was employed by C.F. Lawrence & Associates, Inc., an independent
oil  and  gas company, as land manager. Mr. Tate is a member of the Permian
Basin Landman's Association.

R.  Douglas  Keathley, age 48, has served as Vice President, Operations  of
the  Managing  General Partner since 1992. Before joining us, Mr.  Keathley
worked  as a senior drilling engineer for ARCO Oil and Gas Company  and  in
similar capacities for Reading & Bates Petroleum Co. and Tenneco Oil Co.

In certain instances, the Managing General Partner will engage professional
petroleum   consultants   and  other  independent  contractors,   including
engineers   and   geologists  in  connection  with  property  acquisitions,
geological  and  geophysical  analysis,  and  reservoir  engineering.   The
Managing  General Partner believes that, in addition to its own  "in-house"
staff,  the utilization of such consultants and independent contractors  in
specific  instances  and  on  an  "as-needed"  basis  allows  for   greater
flexibility  and greater opportunity to perform its oil and gas  activities
more economically and effectively.

Code of Ethics

Neither the Partnership nor the Managing General Partner has adopted a code
of  ethics  for  employees, or any principal executive officers,  principal
financial officers, principal accounting officers or the Board of Directors
of the Managing General Partner.  The Board of the Managing General Partner
believes  that  the Partnership's existing internal control procedures  and
current business practices are adequate to promote ethical conduct  and  to
deter  wrongdoing  on the part of these executives.  The  Managing  General
Partner  of  the  Partnership intends to implement during 2004  a  code  of
ethics  that will apply to these executives.  In accordance with applicable
SEC rules, the code of ethics will be made publicly available.

Audit Committee

The  current members of the Audit Committee of the Managing General Partner
are  William  P. Nicoletti, John M. White and Joseph J. Radecki,  Jr.   The
Board of Directors of the Managing General Partner has determined that  Mr.
Nicoletti, the Chairman of the Audit Committee, meets the definition of  an
"audit  committee financial expert" under Item 401(h)(2) of Regulation  S-K
and  has  also  determined that all of the members of the Audit  Committee,
including  Mr.  Nicoletti, meet the independence  requirements  of  Section
10A(m)(3) of the Securities Exchange Act of 1934, as amended, and the rules
and regulations promulgated thereunder.

Item 11.  Executive Compensation

The  Partnership  does  not  employ any directors,  executive  officers  or
employees.  The Managing General Partner receives an administrative fee for
the  management of the Partnership.  The Managing General Partner  received
$144,000  during 2003, 2002 and 2001 as an annual administrative fee.   The
executive officers of the Managing General Partner do not receive any  form
of  compensation, from the Partnership; instead, their compensation is paid
solely  by  Southwest.  The executive officers, however,  may  occasionally
perform administrative duties for the Partnership but receive no additional
compensation for this work.

Item  12.   Security Ownership of Certain Beneficial Owners and  Management
and Related Stockholder Matters

There  are  no  limited partners who own of record, or  are  known  by  the
Managing General Partner to beneficially own, more than five percent of the
Partnership's limited partnership interests.

The  Managing  General  Partner owns a ten percent interest  as  a  general
partner.   Through repurchase offers to the limited partners, the  Managing
General  Partner also owns 7,131.5 limited partner units, a  32.1%  limited
partner  interest.  The Managing General Partners total percentage interest
ownership in the Partnership is 42.1%.

No  officer or director of the Managing General Partner directly owns units
in  the  Partnership.  The officers and directors of the  Managing  General
Partner  are  considered  beneficial owners of the  limited  partner  units
acquired by the Managing General Partner by virtue of their status as such.
Beneficial  ownership is determined in accordance with  the  rules  of  the
Securities and Exchange Commission and includes voting or investment  power
with  respect to the limited partner units.  To our knowledge, except under
applicable  community property laws or as otherwise indicated, the  persons
named in the table have sole voting and sole investment control with regard
to  all  limited  partner  units beneficially  owned.   We  are  presenting
ownership information as of December 31, 2003. A list of beneficial  owners
of  limited  partner units, known to the Managing General  Partner,  is  as
follows:

<PAGE>

                                                 Amount and
                                                 Nature of      Percen
                                                                  t
                        Name and Address of      Beneficial       of
  Title of Class         Beneficial Owner        Ownership      Class
-------------------    ---------------------     ----------     ------
-------------------    ---------------------     ----------     ------
-                                                   ---           -
Limited Partnership    Southwest  Royalties,     Directly       32.1%
Interest               Inc.                      Owns
                       Managing      General     7,131.5
                       Partner                   Units
                       407   N.  Big  Spring
                       Street
                       Midland, TX 79701

Limited Partnership    H. H. Wommack, III        Indirectly     32.1%
Interest                                         Owns
                       Chairman    of    the     7,131.5
                       Board,                    Units
                       President, and CEO
                       of          Southwest
                       Royalties, Inc.,
                       the  Managing General
                       Partner
                       407   N.  Big  Spring
                       Street
                       Midland, TX 79701


There are no arrangements known to the Managing General Partner, which  may
at a subsequent date result in a change of control of the Partnership.

Item 13.  Certain Relationships and Related Transactions

In   2003,   the   Managing  General  Partner  received  $144,000   as   an
administrative  fee.  This amount is part of the general and administrative
expenses incurred by the Partnership.

In  some  instances the Managing General Partner and certain  officers  and
employees  may  be working interest owners in an oil and  gas  property  in
which  the Partnership also has a net profits interest.  Certain properties
in  which  the  Partnership has an interest are operated  by  the  Managing
General  Partner,  who  was paid approximately $83,000  for  administrative
overhead attributable to operating such properties during 2003.

The  terms of the above transactions are similar to ones, which would  have
been  obtained  through arm's length negotiations with  unaffiliated  third
parties.

Item 14.  Principal Accountant Fees and Services

The  following table presents fees for professional audit services rendered
by KPMG, LLP for the audit of the Partnership's annual financial statements
for  the  years ended December 31, 2003 and 2002 and fees billed for  other
services rendered by KPMG during those periods.

     For  the  Year Ended  December    2003
     31,                                       2002

     Audit Fees                      $         $
                                     8,565     4,763
     Audit Related Fees                   -
                                               -
     Tax Fees                             -
                                               -
     All Other Fees                       -
                                               -

         TOTAL                       $         $
                                     8,565     4,763

The  Audit Committee of the Managing General Partner reviewed and approved,
in advance, all audit and non-audit services provided by KPMG, LLP.

<PAGE>
                                 Part IV


Item 15.  Exhibits, Financial Statement Schedules and Reports on Form 8-K

          (a)(1)  Financial Statements:

                  Included in Part II of this report --

                  Independent Auditors Report
                  Balance Sheets
                  Statements of Operations
                  Statement of Changes in Partners' Equity
                  Statements of Cash Flows
                  Notes to Financial Statements

                     (2)  Schedules required by Article 12 of Regulation S-
                  X  are either omitted because they are not applicable  or
                  because  the  required  information  is  shown   in   the
                  financial statements or the notes thereto.

                    (3)  Exhibits:

                                       4      (a)         Certificate   and
                          Agreement  of  Limited Partnership  of  Southwest
                          Royalties, Inc. Income Fund VI, dated December 4,
                          1986.     (Incorporated   by    reference    from
                          Partnership's Form 10-K for the fiscal year ended
                          December 31, 1986.)

                                           (b)        First  Amendment   to
                          Certificate  and Agreement of Limited Partnership
                          of  Southwest  Royalties, Inc.  Income  Fund  VI,
                          dated   January   16,1987.    (Incorporated    by
                          reference  from Partnership's Form 10-K  for  the
                          fiscal year ended December 31, 1987.)

                                            (c)          Corrected   Second
                          Amendment to Certificate and Agreement of Limited
                          Partnership  of Southwest Royalties, Inc.  Income
                          Fund  VI,  dated  May 6, 1987.  (Incorporated  by
                          reference  from Partnership's Form 10-K  for  the
                          fiscal year ended December 31, 1987.)

                                           (d)        Third  Amendment   to
                          Certificate  and Agreement of Limited Partnership
                          of  Southwest  Royalties, Inc.  Income  Fund  VI,
                          dated February 3, 1988 (Incorporated by reference
                          from  Partnership's Form 10-K for the fiscal year
                          ended December 31, 1988.)

                                           (e)        Fourth  Amendment  to
                          Certificate  and Agreement of Limited Partnership
                          of  Southwest  Royalties, Inc.  Income  Fund  VI,
                          dated  June  30, 1988 (Incorporated by  reference
                          from  Partnership's Form 10-K for the fiscal year
                          ended December 31, 1988.)

                                           (f)        Fifth  Amendment   to
                          Certificate  and Agreement of Limited Partnership
                          of  Southwest  Royalties, Inc.  Income  Fund  VI,
                          dated   December   30,  1988   (Incorporated   by
                          reference  from the Partnership's Form  10-K  for
                          the fiscal year ended December 31, 1988.)

                                           (g)        Sixth  Amendment   to
                          Certificate  and Agreement of Limited Partnership
                          of  Southwest  Royalties, Inc.  Income  Fund  VI,
                          dated  as  of  March 19, 1990.  (Incorporated  by
                          reference  from the Partnership's Form  10-K  for
                          the fiscal year ended December 31, 1990.)

                                          (h)        Seventh  Amendment  to
                          Certificate  and Agreement of Limited Partnership
                          of  Southwest  Royalties, Inc.  Income  Fund  VI,
                          dated as of December 31, 1990.  (Incorporated  by
                          reference  from the Partnership's Form  10-K  for
                          the fiscal year ended December 31, 1990.)
<PAGE>
                                           (i)        Eighth  Amendment  to
                          Certificate  and Agreement of Limited Partnership
                          of  Southwest  Royalties, Inc.  Income  Fund  VI,
                          dated as of September 30, 1991.  (Incorporated by
                          reference  from the Partnership's Form  10-K  for
                          the fiscal year ended December 31, 1991.)

                                           (j)        Ninth  Amendment   to
                          Certificate  and Agreement of Limited Partnership
                          of  Southwest  Royalties, Inc.  Income  Fund  VI,
                          dated as of December 31, 1991.  (Incorporated  by
                          reference  from the Partnership's Form  10-K  for
                          the fiscal year ended December 31, 1992.)

                                           (k)        Tenth  Amendment   to
                          Certificate  and Agreement of Limited Partnership
                          of  Southwest  Royalties, Inc.  Income  Fund  VI,
                          dated  as  of  March 31, 1992.  (Incorporated  by
                          reference  from the Partnership's Form  10-K  for
                          the fiscal year ended December 31, 1992.)

                                          (l)        Eleventh Amendment  to
                          Certificate  and Agreement of Limited Partnership
                          of  Southwest  Royalties, Inc.  Income  Fund  VI,
                          dated  as  of  June  30, 1992.  (Incorporated  by
                          reference  from the Partnership's Form  10-K  for
                          the fiscal year ended December 31, 1992.)

                                          (m)        Twelfth  Amendment  to
                          Certificate  and Agreement of Limited Partnership
                          of  Southwest  Royalties, Inc.  Income  Fund  VI,
                          dated as of November 23, 1992.  (Incorporated  by
                          reference  from the Partnership's Form  10-K  for
                          the fiscal year ended December 31, 1992.)

                                          (n)       Thirteenth Amendment to
                          Certificate  and Agreement of Limited Partnership
                          of  Southwest  Royalties, Inc.  Income  Fund  VI,
                          dated  as  of  April 22, 1993.  (Incorporated  by
                          reference  from the Partnership's Form  10-K  for
                          the fiscal year ended December 31, 1993.)

                                          (o)       Fourteenth Amendment to
                          Certificate  and Agreement of Limited Partnership
                          of  Southwest  Royalties, Inc.  Income  Fund  VI,
                          dated as of September 30, 1993.  (Incorporated by
                          reference  from the Partnership's Form  10-K  for
                          the fiscal year ended December 31, 1993.)

                                          (p)       Fifteenth Amendment  to
                          Certificate  and Agreement of Limited Partnership
                          of  Southwest  Royalties, Inc.  Income  Fund  VI,
                          dated as of December 31, 1993.  (Incorporated  by
                          reference  from the Partnership's Form  10-K  for
                          the fiscal year ended December 31, 1993.)

                                          (q)       Sixteenth Amendment  to
                          Certificate  and Agreement of Limited Partnership
                          of  Southwest  Royalties, Inc.  Income  Fund  VI,
                          dated  as  of  July  26, 1994.  (Incorporated  by
                          reference  from the Partnership's Form  10-K  for
                          the fiscal year ended December 31, 1994.)

                                         (r)       Seventeenth Amendment to
                          Certificate  and Agreement of Limited Partnership
                          of  Southwest  Royalties, Inc.  Income  Fund  VI,
                          dated  as of January 18, 1995.  (Incorporated  by
                          reference  from the Partnership's Form  10-K  for
                          the fiscal year ended December 31, 1994.)

                                          (s)       Eighteenth Amendment to
                          Certificate  and Agreement of Limited Partnership
                          of  Southwest  Royalties, Inc.  Income  Fund  VI,
                          dated as of July 26, 1995.

                                          (t)       Nineteenth Amendment to
                          Certificate  and Agreement of Limited Partnership
                          of  Southwest  Royalties, Inc.  Income  Fund  VI,
                          dated as of January 29, 1996.

                                          (u)       Twentieth Amendment  to
                          Certificate  and Agreement of Limited Partnership
                          of  Southwest  Royalties, Inc.  Income  Fund  VI,
                          dated as of April 30, 1996.

                                          (v)        Twenty First Amendment
                          to   Certificate   and   Agreement   of   Limited
                          Partnership  of Southwest Royalties, Inc.  Income
                          Fund VI, dated as of September 30, 1996.

<PAGE>

                                          (w)       Twenty Second Amendment
                          to   Certificate   and   Agreement   of   Limited
                          Partnership  of Southwest Royalties, Inc.  Income
                          Fund VI, dated as of January 15, 1997.

                                          (x)        Twenty Third Amendment
                          to   Certificate   and   Agreement   of   Limited
                          Partnership of Southwest Royalties, Inc.   Income
                          Fund VI, dated as of May 10, 1997.

                          (y)   Twenty Fourth Amendment to Certificate  and
                          Agreement  of  Limited Partnership  of  Southwest
                          Royalties,  Inc.  Income Fund  VI,  dated  as  of
                          January 30, 1998.

                          (z)   Twenty  Fifth Amendment to Certificate  and
                          Agreement of
                          Limited Partnership of Southwest Royalties,  Inc.
                          Income Fund VI, dated as of July 27, 1998.

                                          (aa)  Twenty  Sixth Amendment  to
                          Certificate  and Agreement of Limited Partnership
                          of  Southwest  Royalties, Inc.  Income  Fund  VI,
                          dated as of December 22, 1998.

                                          (bb) Twenty Seventh Amendment  to
                          Certificate  and Agreement of Limited Partnership
                          of  Southwest  Royalties, Inc.  Income  Fund  VI,
                          dated as of February 25, 1999.

                                          (cc)  Twenty Eighth Amendment  to
                          Certificate  and Agreement of Limited Partnership
                          of  Southwest  Royalties, Inc.  Income  Fund  VI,
                          dated as of July 27, 1999.

                                          (dd)  Twenty  Ninth Amendment  to
                          Certificate  and Agreement of Limited Partnership
                          of  Southwest  Royalties, Inc.  Income  Fund  VI,
                          dated as of February 10, 2000.

                                           (ee)   Thirtieth  Amendment   to
                          Certificate  and Agreement of Limited Partnership
                          of  Southwest  Royalties, Inc.  Income  Fund  VI,
                          dated as of April 26, 2000.

                                          (ff)       Thirty First Amendment
                          to   Certificate   and   Agreement   of   Limited
                          Partnership  of Southwest Royalties, Inc.  Income
                          Fund VI, dated as of September 13, 2000.

                                          (gg)  Thirty Second Amendment  to
                          Certificate  and Agreement of Limited Partnership
                          of  Southwest  Royalties, Inc.  Income  Fund  VI,
                          dated as of February 20, 2001.

                                          (hh)  Thirty  Third Amendment  to
                          Certificate  and Agreement of Limited Partnership
                          of  Southwest  Royalties, Inc.  Income  Fund  VI,
                          dated as of July 16, 2001.

<PAGE>

                                               (ii) Thirty Fourth Amendment
                          to   Certificate   and   Agreement   of   Limited
                          Partnership  of Southwest Royalties, Inc.  Income
                          Fund VI, dated as of January 11, 2002.

                                               (jj)  Thirty Fifth Amendment
                          to   Certificate   and   Agreement   of   Limited
                          Partnership  of Southwest Royalties, Inc.  Income
                          Fund VI, dated as of June 3, 2002.

                                               (kk)  Thirty Sixth Amendment
                          to   Certificate   and   Agreement   of   Limited
                          Partnership  of Southwest Royalties, Inc.  Income
                          Fund VI, dated as of July 30, 2002.

                                              (ll) Thirty Seventh Amendment
                          to   Certificate   and   Agreement   of   Limited
                          Partnership  of Southwest Royalties, Inc.  Income
                          Fund VI, dated as of February 20, 2003.

          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
          99.3 Limited Partners as of February 20, 2003

               (b)    Reports on Form 8-K
                      There  were no reports filed on Form 8-K  during  the
               quarter ended December 31, 2003.
<PAGE>
                                Signatures


Pursuant  to  the  requirements of Section 13 or 15(d)  of  the  Securities
Exchange  Act  of 1934, the Partnership 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/ H. H. Wommack, III
                                 ------------------------------------------
-----
                                           H. H. Wommack, III, President


                          Date:  May 12, 2004

<PAGE>
In  accordance with the Exchange Act, this report has been signed below  by
the following persons on behalf of the Registrant and in the capacities and
on the dates indicated.

/s/ H. H. Wommack, III                       /s/ Bill E. Coggin
---------------------------                  ------------------------
--------------------                         -----------------------
H.    H.   Wommack,    III,                  Bill      E.     Coggin,
Chairman of the Board,                       Executive Vice President
President,   Director   and                  and    Chief   Financial
Chief Executive Officer                      Officer

Date:     May 12, 2004                       Date:     May 12, 2004


/s/ William P. Nicoletti                     /s/ James N. Chapman
---------------------------                  ------------------------
--------------------                         -----------------------
William    P.    Nicoletti,                  James     N.    Chapman,
Director                                     Director

Date:     May 10, 2004                       Date:     May 12, 2004


/s/ Richard D. Rinehart                      /s/  Joseph J.  Radecki,
                                             Jr.
---------------------------                  ------------------------
--------------------                         -----------------------
Richard     D.    Rinehart,                  Joseph J. Radecki,  Jr.,
Director                                     Director

Date:     May 12, 2004                       Date:     May 12, 2004


/s/  Herbert C. Williamson,
III
---------------------------                  ------------------------
--------------------                         -----------------------
Herbert C. Williamson, III,                  John M. White, Director
Director

Date:     May 11, 2004                       Date:



<PAGE>
                    SECTION 302 CERTIFICATION                Exhibit 31.1


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

1.        I  have  reviewed this annual report on Form  10-K  of  Southwest
Royalties, Inc. Income Fund VI;

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

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

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

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

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

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

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

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

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

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


Date:  May 12, 2004                /s/ H. H. Wommack, III
                                   H. H. Wommack, III
                                    Chairman, President and Chief Executive
Officer
                                   of Southwest Royalties, Inc., the
                                   Managing General Partner of
                                   Southwest Royalties, Inc. Income Fund VI

<PAGE>
                    SECTION 302 CERTIFICATION                Exhibit 31.2


I, Bill E. Coggin, certify that:

1.        I  have  reviewed this annual report on Form  10-K  of  Southwest
Royalties, Inc. Income Fund VI;

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

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

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

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

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

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

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

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

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

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


Date:  May 12, 2004                /s/ Bill E. Coggin
                                   Bill E. Coggin
                                   Executive Vice President
                                   and Chief Financial Officer of
                                   Southwest Royalties, Inc., the
                                   Managing General Partner of
                                   Southwest Royalties, Inc. Income Fund VI
<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 Annual Report of Southwest  Royalties,  Inc.
Income  Fund  VI, L.P. (the "Company") on Form 10-K for the  period  ending
December  31, 2003 as filed with the Securities and Exchange Commission  on
the  date  hereof  (the  "Report"), I, H.H. Wommack, III,  Chief  Executive
Officer  of the Managing General Partner of the Company, certify,  pursuant
to  18 U.S.C.  1350, as adopted pursuant to  906 of the Sarbanes-Oxley  Act
of 2002, that:

     (1)  The Report fully complies with the requirements of section 13(a) or
       15(d) of the Securities Exchange Act of 1934; and

     (2)   The information contained in the Report fairly presents, in  all
       material respects, the financial condition and results
 of operation of the
       Company.


Date:  May 12, 2004




/s/ H.H. Wommack, III
H. H. Wommack, III
Chairman, President, Director and Chief Executive Officer
  of Southwest Royalties, Inc., the
  Managing General Partner of
  Southwest Royalties, Inc. Income Fund VI

<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 Annual Report of Southwest  Royalties,  Inc.
Income  Fund  VI, L.P. (the "Company") on Form 10-K for the  period  ending
December  31, 2003 as filed with the Securities and Exchange Commission  on
the  date hereof (the "Report"), I, Bill E. Coggin, Chief Financial Officer
of  the  Managing General Partner of the Company, certify, pursuant  to  18
U.S.C.   1350,  as  adopted pursuant to  906 of the Sarbanes-Oxley  Act  of
2002, that:

     (1)  The Report fully complies with the requirements of section 13(a) or
       15(d) of the Securities Exchange Act of 1934; and

     (2)   The information contained in the Report fairly presents, in  all
       material respects, the financial condition and results
of operation of the
       Company.


Date:  May 12, 2004




/s/ Bill E. Coggin
Bill E. Coggin
Executive Vice President
  and Chief Financial Officer of
  Southwest Royalties, Inc., the
  Managing General Partner of
  Southwest Royalties, Inc. Income Fund VI

<PAGE>

This Instrument Prepared By:
J. Porter Durham, Jr.
Baker, Donelson, Bearman & Caldwell
1800 Republic Centre
633 Chestnut Street
Chattanooga, Tennessee 37450-1800

         THIRTY-SEVENTH AMENDMENT TO CERTIFICATE AND AGREEMENT OF
             LIMITED PARTNERSHIP OF SOUTHWEST ROYALTIES, INC.
             INCOME FUND VI, A TENNESSEE LIMITED PARTNERSHIP

Pursuant  to the Tennessee Revised Uniform Limited Partnership  Act,  62-2-
1204  of  the Tennessee Code Annotated, and the provisions of the Tennessee
Uniform  Limited Partnership Act, being formerly 61-2-101, et seq.  of  the
Tennessee  Code Annotated, this Thirty-Seventh Amendment (the  "Amendment")
to  the  Certificate  and  Agreement of Limited  Partnership  of  Southwest
Royalties, Inc.  Income Fund VI is executed to be effective as of the  20th
day  of  February, 2003, by and between H. H. WOMMACK, III,  an  individual
("General Partner"), SOUTHWEST ROYALTIES, INC. ("Managing General Partner")
(the  Managing  General  Partner and the General Partner,  are  hereinafter
collectively  referred to as "General Partners"), and the General  Partners
as  attorney-in-fact for those persons and entities listed  on  Schedule  1
attached to this Amendment, whether existing or additional limited partners
(collectively  the  "Limited  Partners") and as  attorney-in-fact  for  the
Withdrawing Limited Partners, as defined hereinafter.

WHEREAS,  Southwest  Royalties, Inc.  Income Fund VI  was  organized  as  a
Tennessee   limited  partnership  pursuant  to  an  Agreement  of   Limited
Partnership,  as  amended from time to time, dated  December  4,  1986  and
recorded  in  Book  3280,  Page 726 in the Register's  Office  of  Hamilton
County, Tennessee (the "Agreement"); and

WHEREAS,  the  General Partners, Limited Partners and  Withdrawing  Limited
Partners desire to amend the Agreement in the manner set forth herein;

NOW,  THEREFORE,  for  and  in  consideration  of  the  mutual  rights  and
obligations  herein and other good and valuable consideration  the  receipt
and  legal sufficiency of which are acknowledged, the parties hereto  agree
as follows:

1.   Schedule  1  to  the Agreement is hereby deleted in its  entirety  and
     replaced  by  the  Schedule  1 attached  hereto.   Those  persons  and
     entities which were formerly listed on Schedule 1 to the Agreement but
     which  are not listed on the revised Schedule 1 attached hereto  shall
     be defined collectively as the "Withdrawing Limited Partners."

2.   Except  as  provided herein, the Agreement is hereby  constituted  and
     acknowledged as the controlling Agreement of Southwest Royalties, Inc.
     Income Fund VI.

<PAGE>
IN  WITNESS WHEREOF, the parties hereto acknowledge that they have executed
this  Amendment to the Agreement to be effective as of the date first above
written.

               GENERAL PARTNERS:

               By:  /s/ H. H. Wommack, III
                    -----------------------------------
                    H. H. Wommack, III, General Partner

               By:   SOUTHWEST ROYALTIES, INC.
                    Managing General Partner

               By:  /s/ H. H. Wommack, III
                    -----------------------------------
                    H. H. Wommack, III, President


               LIMITED PARTNERS:


                               By:   General Partners, as attorneys-in-fact
                    for  the Limited Partners listed on Schedule 1 attached
                    hereto  and those Withdrawing Limited Partners  removed
                    from  Schedule  1  under Powers of Attorney  previously
                    granted

               By:  /s/ H. H. Wommack, III
                    -----------------------------------
                    H. H. Wommack, III

               By:  SOUTHWEST ROYALTIES, INC.
                    Managing General Partner

               By:  /s/ H. H. Wommack, III
                    -----------------------------------

STATE OF Texas     )
COUNTY OF Midland     )

Before  me,  /s/ B. Ross, a Notary Public in and for the State  and  County
aforesaid, personally appeared H.H. Wommack, III, with whom I am personally
acquainted  (or  proved to me on the basis of satisfactory  evidence),  and
who,  upon  oath, acknowledged himself to be the attorney-in-fact  for  the
admitted  and  withdrawing Limited Partners, and as president of  Southwest
Royalties,  Inc.  for itself and as attorney-in-fact for the  admitted  and
withdrawing  Limited  Partners,  who  further  acknowledged  that   he   is
authorized  by  Southwest  Royalties, Inc., the Limited  Partners  and  the
Withdrawing  Limited Partners to execute this document  on  its  and  their
behalf.

Witness my hand and seal at office, on this the 26th day of February, 2003.

                    /s/ B. Ross
                    -----------------------------------
                    Notary Public

My commission expires:
08/30/03

<PAGE>


                        AMENDMENTS FOLLOW AS EX-99

<PAGE>