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  33-38511

             Southwest Developmental Drilling Fund 91-A, L.P.
                 Exact name of registrant as specified in
                    its limited partnership agreement

Delaware                                                    75-2387814
(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 code (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 and general partner 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  45.   The  exhibit
index is found on page 42.

<PAGE>
                            Table of Contents

Item                                                                   Page

                                  Part I

     Glossary of Oil and Gas Terms                                       3

 1.  Business                                                            5

 2.  Properties                                                          9

 3.  Legal Proceedings                                                  10

 4.  Submission of Matters to a Vote of Security Holders                10

                                 Part II

 5.  Market for Registrant's Common Equity, Related
     Stockholder Matters and Issuer Purchases of Equity Securities      11

 6.  Selected Financial Data                                            12

 7.  Management's Discussion and Analysis of
     Financial Condition and Results of Operations                      13

7A.  Quantitative and Qualitative Disclosures About Market Risk         19

 8.  Financial Statements and Supplementary Data                        20

 9.  Changes in and Disagreements with Accountants
     on Accounting and Financial Disclosure                             34

9A.  Controls and Procedures                                            34

                                 Part III

10.  Directors and Executive Officers of the Registrant                 35

11.  Executive Compensation                                             37

12.  Security Ownership of Certain Beneficial Owners and
     Management and Related Stockholder Matters                         37

13.  Certain Relationships and Related Transactions                     38

14.  Principal Accountant Fees and Services                             38

                                 Part IV

15.  Exhibits, Financial Statement Schedules, and Reports
     on Form 8-K                                                        39

     Signatures                                                         40

<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.

     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  Developmental  Drilling Fund 91-A, L.P.  (the  "Partnership"  or
"Registrant") was organized as a Delaware limited partnership on January 7,
1991.   The  offering  of  limited  and  general  partner  interests  began
September  17, 1991 as part of a shelf offering registered under  the  name
Southwest  Developmental Drilling Program 1991-92, reached minimum  capital
requirements  on  April  22,  1992  and  concluded  April  30,  1992.   The
Partnership has no subsidiaries.

The  Partnership has expended its capital and acquired leasehold  interests
and  completed  drilling  operations.  The  Partnership  has  produced  and
marketed the crude oil and natural gas produced from such properties.

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.   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 leasehold interests and drilled oil  and  gas
properties  located  in  Texas  and New  Mexico.   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 and gas 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      84%       16%
  2002      90%       10%
  2001      82%       18%

As  the table indicates, the majority of the Partnership's revenue is  from
its   oil  production;  therefore,  Partnership  revenues  will  be  highly
dependent upon the future prices and demands for oil.

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
97%  of  the Partnership's total oil and gas production during 2003: Plains
Marketing  LP for 80% and Duke Energy Field Services LP for 17%.  Contracts
for  2003 with these major purchasers cover time periods ranging from month
to  month  contracts up to year-to-year contract periods.  Prices  received
from  these  major  purchasers ranged from $4.64 per  mcf  and  $30.08  per
barrel.  One purchaser accounted for 85% of the Partnership's total oil and
gas  production  during 2002: Plains Marketing LP for 85%.   Contracts  for
2002  with  these major purchaser covers month-to-month contracts.   Prices
received  from this major purchaser were $23.36 per barrel.  Two purchasers
accounted for 94% of the Partnership's total oil and gas production  during
2001:  Plains Marketing LP for 76% and Duke Energy Field Services for  18%.
Contracts  for 2001 with these major purchasers cover time periods  ranging
from  month to month contracts up to year-to-year contract periods.  Prices
received  from these major purchasers ranged from $4.51 per mcf and  $27.05
per barrel.  All purchasers of the Partnership's oil and gas production are
unrelated  third parties.  In the event this purchaser 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 total oil and gas production.

Competition
Because  the  Partnership has utilized all of its funds available  for  the
acquisition  of interests in producing oil and gas properties  or  drilling
operations,  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.

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.

<PAGE>
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, land men 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  property  was  to  be
acquired,  the  Managing  General  Partner  considered  such  criteria   as
estimated  oil  and gas reserves, estimated drilling costs, 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 Eddy County of New Mexico and Rains,  Van  Zandt
and Ward County of Texas. These properties consist of various interests  in
3 wells.

Due  to  the  Partnership's  objective of  maintaining  current  operations
without engaging in the drilling of any developmental or exploratory wells,
or additional acquisitions of producing properties, there have not been any
significant changes in properties during 2003, 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 Interest    Wells      Oil       Gas
Location                                 (bbls)    (mcf)
-------------  ------------    -----    --------  --------
----                                       --        -
Carson F #1        6/92          1       16,000    20,000
Ward County,        89%          1      16,000(1  20,000(1
                                           )         )
Texas             working
                 interest

Carson E          6/92 at        1       14,000    8,000
Ward  County,   90% working      1      14,000(1  8,000(1)
Texas                                      )
                 interest


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


<PAGE>
*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 $31.81 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 $5.49 per Mcf.

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.  All of the proved
reserves  are  included  in  the engineering reports,  which  evaluate  the
Partnership's present reserves.

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
Investor  partner  interests, or units, in the Partnership  were  initially
offered  and  sold for a price of $1,000.  Investor partner units  are  not
traded  on any exchange and there is no public or organized trading  market
for  them.   Further, a transferee may not become a substitute  limited  or
general partner without the consent of the Managing General Partner.

Each  Additional  General Partner interest, whom elected  at  the  time  of
subscription  into  the  Partnership, has been  converted  into  a  limited
partner effective January 1, 1994.

The  Managing  General  Partner has the right, but not  the  obligation  in
accordance  with the partnership agreement, to purchase limited partnership
units  should  an  investor  desire to sell.  The  value  of  the  unit  is
determined by adding the sum of (1) current assets less liabilities and (2)
the  present  value  of  the  future net revenues  attributable  to  proved
reserves and by discounting the future net revenues at a rate not in excess
of  the prime rate charged by NationsBank, N.A. of Midland, Texas plus  one
percent  (1%),  which  value shall be further  reduced  by  a  risk  factor
discount  of no more than one-third (1/3) to be determined by the  Managing
General Partner in its sole and absolute discretion.

                   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          -      $     -          -           N/A
November 1-
   30,
   2003          -            -          -           N/A
December 1-
   31,
   2003          -            -          -           N/A
  TOTALS         -      $     -

(1)  In  April 2003, the Managing General Partner purchased a total  of  50
limited  partner units from limited partners at an average  base  price  of
$135.68  per unit.  As of December 31, 2002, no limited partner units  were
purchased  by  the Managing General Partner.  In 2001, 17  limited  partner
units were tendered to and purchased by the Managing General Partner at  an
average  base  price of $214.15 per unit.  These discretionary  repurchases
were made based upon the partnership agreement criteria.

Number of Limited and General Partner Interest Holders
As  of  December 31, 2003, there were 101 holders of limited partner  units
and no holders of general 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 drilling activities, less (i)  General  and
Administrative  Costs,  (ii)  Operating  Costs,  and  (iii)  any   reserves
necessary  to  meet  current  and anticipated  needs  of  the  Partnership,
including, but not limited to drilling cost overruns, as determined in  the
sole discretion of the Managing General Partner."

<PAGE>
During  2003,  distributions  were  made  totaling  $32,765,  with  $29,161
distributed  to  the investor partners and $3,604 to the  Managing  General
Partner.  For the year ended December 31, 2003, distributions of $25.48 per
investor partner unit were made, based upon 1,144.50 investor partner units
outstanding.   During 2002, distributions were made totaling $18,462,  with
$16,431  distributed to the investor partners and $2,031  to  the  Managing
General  Partner.   For the year ended December 31, 2002, distributions  of
$14.36  per  investor partner unit were made, based upon 1,144.50  investor
partner  units  outstanding. During 2001, distributions were made  totaling
$62,234,  with $55,388 distributed to the investor partners and  $6,846  to
the  Managing  General  Partner.  For the year  ended  December  31,  2001,
distributions  of  $48.39 per investor partner unit were made,  based  upon
1,144.50 investor 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           $  161,802   105,095   139,286   162,884   252,026

Net income before
cumulative
    effects    of     23,093    2,942     30,325    58,242    119,990
accounting
changes

Net income            33,297    102,942   30,325    58,242    119,990

Partners'   share
of
    net    income
(loss):

Managing General
 Partner              6,767     3,184     5,536     7,617     17,159

Investor partners     26,530    99,758    24,789    50,625    102,831

Investor
partners'
    net    income
(loss) per unit
           before
cumulative
effects
   of  accounting     15.25
changes                         (.21)     21.66     44.23     89.85

Investor
partners'
    net    income     23.18
(loss) per unit                 87.16     21.66     44.23     89.85

Investor
partners'
             cash
distributions
per unit              25.48
                                14.36     48.39     94.12     66.10

Total assets       $  235,779   217,697   133,225   165,095   237,888


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

General
Southwest  Developmental  Drilling Fund  91-A,  L.P.  was  organized  as  a
Delaware  limited partnership on January 7, 1991.  The offering of  limited
and  general  partner interests began on September 17, 1991 as  part  of  a
shelf  offering registered under the name Southwest Developmental  Drilling
Program 1991-92.  Minimum capital requirements for the Partnership were met
on  April  22,  1992,  with  the offering of limited  and  general  partner
interests  concluding  on  April  30, 1992,  with  total  investor  partner
contributions  of  $1,144,500.   The  Managing  General  Partner   made   a
contribution  to  the capital of the Partnership at the conclusion  of  its
offering  period in an amount equal to 1% of its net capital contributions.
The  Managing  General  Partner contribution  was  $9,800.   Total  capital
contributions were $1,154,300.

The  Partnership was formed to engage primarily in the business of drilling
developmental  and exploratory wells, to produce and market crude  oil  and
natural  gas produced from such properties, to distribute any net  proceeds
from  operations  to the general and limited partners  and  to  the  extent
necessary, acquire leases, which contain drilling prospects.  Net  revenues
will  not  be  reinvested in other revenue producing assets except  to  the
extent  that  performance of remedial work is needed to  improve  a  well's
producing capabilities.  The economic life of the Partnership thus  depends
on  the  period  over  which the Partnership's oil  and  gas  reserves  are
economically recoverable.

Based on current conditions, management anticipates performing no workovers
during  2004  to  enhance  production.  The partnership  will  most  likely
continue  to  experience sporadic production.   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>
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:

                                Year Ended      Percenta
                                                   ge
                               December 31,     Increase
                              2003      2002    (Decreas
                                                   e)
                              ----      ----    --------
                                                   -
Average price per        $    30.29               21%
barrel of oil                         24.96
Average price per mcf    $     4.73               67%
of gas                                2.83
Oil production in           4,400     3,750       17%
barrels
Gas production in mcf       5,300     3,700       43%
Oil and gas revenue      $  158,356   104,083     52%
Production expense       $  86,296    59,781      44%
Partnership              $  32,765    18,462      77%
distributions
Investor partner         $  29,161    16,431      77%
distributions
Per unit distribution    $    25.48               77%
to investor partners                  14.36

Number of investor          1,144.5
partner units                         1,144.5

Revenues

The  Partnership's oil and gas revenues increased to $158,356 from $104,083
for  the  years ended December 31, 2003 and 2002, respectively, an increase
of  52%.  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 $5.33 per barrel, resulting  in
    an increase of approximately $23,500 in revenues. Oil sales represented
    84%  of total oil and gas sales during the year ended December 31, 2003
    as compared to 90% 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 67%, or $1.90 per mcf, resulting in
    an increase of approximately $10,100 in revenues.

    The  total  increase in revenues due to the change in  prices  received
    from oil and gas production is approximately $33,600.  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 increased approximately 650 barrels or 17% during  the
   year ended December 31, 2003 as compared to the year ended December  31,
   2002, resulting in an increase of approximately $16,200 in revenues.

    Gas production increased approximately 1,600 mcf or 43% during the same
    period, resulting in an increase of approximately $4,500 in revenues.

    The  total  increase  in revenues due to the change  in  production  is
    approximately  $20,700.  The increase in oil and gas  volumes  are  the
    result of one well returning to historic production levels after  being
    down in 2002.

Costs and Expenses

Total  costs and expenses increased to $138,079 from $102,153 for the years
ended  December 31, 2003 and 2002, respectively, an increase of  30%.   The
increase is the result of the addition of accretion expense, higher general
and administrative costs, lease operating costs and depletion expense.

1.    Lease  operating  costs  and production taxes  were  44%  higher,  or
   approximately $26,500 more during the year ended December  31,  2003  as
   compared  to  the year ended December 31, 2002.  The increase  in  lease
   operating costs is the result of well repairs on one well and the increase
   in production taxes due to the increase in commodity prices.

2.  General and administrative costs consist of independent accounting  and
    engineering  fees,  computer services, postage,  and  Managing  General
    Partner  personnel costs.  General and administrative  costs  increased
    40% or approximately $6,500 during the year ended December 31, 2003  as
    compared to the year ended December 31, 2002.

3.  Depletion expense increased to $28,221 for the year ended December  31,
    2003  from  $26,000  for the same period in 2002.  This  represents  an
    increase  of 9%.  The contributing factor to the decrease in  depletion
    expense  is  in relation to the BOE depletion rate for the  year  ended
    December 31, 2003, which was $5.34 applied to 5,283 BOE as compared  to
    $5.95 applied to 4,367 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  $26,483,  a  long  term   liability   of
approximately  $16,279  and  a  gain  of  approximately  $10,204  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 $17,581, and the increase in  the  balance  from
January  1,  2003  of $1,302 is due to accretion expense.   The  pro  forma
amounts  of  the asset retirement obligation as of December 31, 2002,  2001
and  2000,  were approximately $16,279, $15,081 and $13,971,  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>
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:

                                Year Ended      Percenta
                                                   ge
                               December 31,     Increase
                              2002      2001    (Decreas
                                                   e)
                              ----      ----    --------
                                                   -
Average price per        $    24.96               (3%)
barrel of oil                         25.84
Average price per mcf    $     2.83              (36%)
of gas                                4.41
Oil production in           3,750     4,440      (16%)
barrels
Gas production in mcf       3,700     5,540      (33%)
Oil and gas revenue      $  104,083   139,132    (25%)
Production expense       $  59,781    73,616     (19%)
Partnership              $  18,462    62,234     (70%)
distributions
Investor partner         $  16,431    55,388     (70%)
distributions
Per unit distribution    $    14.36              (70%)
to investor partners                  48.39
Number of investor          1,144.5
partner units                         1,144.5

Revenues

The  Partnership's oil and gas revenues decreased to $104,083 from $139,132
for the years ended December 31, 2002 and 2001, respectively, a decrease of
25%.   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
    decreased  during the year ended December 31, 2002 as compared  to  the
    year ended December 31, 2001 by 3%, or $.88 per barrel, resulting in  a
    decrease of approximately $3,300 in revenues. Oil sales represented 90%
    of  total oil and gas sales during the year ended December 31, 2002  as
    compared to 82% 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 36%, or $1.58 per mcf, resulting in
    a decrease of approximately $5,800 in revenues.

    The  total  decrease in revenues due to the change in  prices  received
    from  oil and gas production is approximately $9,100.  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 690 barrels or 16% during  the
   year ended December 31, 2002 as compared to the year ended December  31,
   2001, resulting in a decrease of approximately $17,800 in revenues.

    Gas production decreased approximately 1,840 mcf or 33% during the same
    period, resulting in a decrease of approximately $8,100 in revenues.

    The  total  decrease  in revenues due to the change  in  production  is
    approximately  $25,900.   The decrease in  oil  production  is  due  to
    fluctuation in production on one out of three leases.  The decrease  in
    gas  production  is due primarily to downtime on one  lease,  which  is
    water  production influenced and gas production cannot be restored,  in
    addition one lease experiences fluctuations in levels of production.

Costs and Expenses

Total  costs and expenses decreased to $102,153 from $108,961 for the years
ended  December  31, 2002 and 2001, respectively, a decrease  of  6%.   The
decrease  is  the  result of lower depletion expense  and  lease  operating
costs, partially offset an increase in general and administrative costs.

2.    Lease  operating  costs  and production  taxes  were  19%  lower,  or
   approximately $13,800 less during the year ended December  31,  2002  as
   compared  to  the year ended December 31, 2001.  The decrease  in  lease
   operating expense is due mainly to repairs and maintenance performed during
   2001.

2.  General and administrative costs consist of independent accounting  and
    engineering  fees,  computer services, postage,  and  Managing  General
    Partner personnel costs.  General and administrative costs increased 7%
    or  approximately  $1,000 during the year ended December  31,  2002  as
    compared to the year ended December 31, 2001.

3.  Depletion expense increased to $26,000 for the year ended December  31,
    2002  from  $20,000  for the same period in 2001.  This  represents  an
    increase  of  30%.   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
    $13,000  and increase 2002 net income by $87,000.  See Note  4  of  the
    notes to the Partnership's financial statements.


<PAGE>
C.  Revenue and Distribution Comparison

Partnership net income for the years ended December 31, 2003, 2002 and 2001
was $33,297, $102,942 and $30,325, respectively.  Partnership distributions
for  the years ended December 31, 2003, 2002 and 2001 were $32,765, $18,462
and $62,234, respectively.

The  sources  for  the  2003  distributions of $32,765  were  oil  and  gas
operations  of  approximately  $40,700  and  the  change  in  oil  and  gas
properties   of  approximately  $(200),  resulting  in  excess   cash   for
contingencies  or  subsequent distributions.   The  sources  for  the  2002
distributions  of  $18,462  were oil and gas  operations  of  approximately
$26,900 and the change in oil and gas properties of approximately $(9,100),
with  the  balance  from available cash on hand at  the  beginning  of  the
period.  The sources for the 2001 distributions of $62,234 were oil and gas
operations  of  approximately  $60,400  and  the  change  in  oil  and  gas
properties of approximately $(200), with the balance from available cash on
hand at the beginning of the period.

Total distributions during the year ended December 31, 2003 were $32,765 of
which  $29,161 was distributed to the investor partners and $3,604  to  the
Managing  General Partner.  The per unit distribution to investor  partners
during  the  same period was $25.48.  Total distributions during  the  year
ended  December  31, 2002 were $18,462 of which $16,431 was distributed  to
the  investor partners and $2,031 to the Managing General Partner.  The per
unit  distribution to investor partners during the same period was  $14.36.
Total distributions during the year ended December 31, 2001 were $62,234 of
which  $55,388 was distributed to the investor partners and $6,846  to  the
Managing  General Partner.  The per unit distribution to investor  partners
during the same period was $48.39.

Cumulative  cash distributions of $1,447,236 have been made to the  general
and  limited  partners as of December 31, 2003.  As of December  31,  2003,
$1,289,951 or $1,127.09 per investor partner unit, has been distributed  to
the  investor  partners, representing a 100% return of capital  and  a  13%
return on capital contributed.

Liquidity and Capital Resources

The  primary source of cash is from operations, the receipt of income  from
oil and gas properties.  The Partnership anticipates the primary source  of
cash to continue being from the oil and gas operations.

Cash  flows provided by operating activities were approximately $40,700  in
2003 compared to $26,900 in 2002 and approximately $60,400 in 2001.

Cash  flows  used in investing activities were approximately $200  in  2003
compared  to  $9,100 in 2002 and approximately $200 in 2001. The  principal
use  of  the 2003 cash flow from investing activities was additions to  oil
and gas properties.

Cash  flows used in financing activities were approximately $32,800 in 2003
compared  to $18,500 in 2002 and approximately $62,200 in 2001.   The  only
use in the 2003 financing activities was the distributions to partners.

As  of  December  31,  2003, the Partnership had approximately  $35,500  in
working  capital.   The  Managing  General  Partner  knows  of  no  unusual
contractual  commitments.  Although the Partnership  held  many  long-lived
properties   at  inception,  because  of  the  restrictions   on   property
development  imposed by the partnership agreement, the  Partnership  cannot
develop   its   non  producing  properties,  if  any.   Without   continued
development,  the producing reserves continue to deplete.  Accordingly,  as
the  Partnership's properties have matured and depleted, the net cash flows
from  operations  for  the  Partnership has steadily  declined,  except  in
periods  of  substantially  increased commodity  pricing.   Maintenance  of
properties  and administrative expenses for the Partnership are  increasing
relative to production.  As the properties continue to deplete, maintenance
of  properties  and administrative costs as a percentage of production  are
expected to continue to increase.

<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                                            21

Balance Sheets                                                          22

Statements of Operations                                                23

Statement of Changes in Partners' Equity                                24

Statements of Cash Flows                                                25

Notes to Financial Statements                                           26

<PAGE>









                       INDEPENDENT AUDITORS' REPORT

The Partners
Southwest Developmental Drilling
 Fund 91-A, L.P.
 (A Delaware Limited Partnership):


We  have audited the accompanying balance sheets of Southwest Developmental
Drilling  Fund 91-A, L.P. (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 Developmental
Drilling  Fund 91-A, L.P. 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  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 Developmental Drilling Fund 91-A, L.P.
                     (a Delaware limited partnership)
                              Balance Sheets
                        December 31, 2003 and 2002

                                   2003      2002
                                   ----      ----
Assets
----------

Current assets:
 Cash and cash equivalents    $  19,513    11,779
  Receivable  from  Managing     15,974    4,069
General Partner
                                 --------  --------
                                 ----      ----
   Total current assets          35,487    15,848
                                 --------  --------
                                 ----      ----
Oil  and  gas  properties  -
using the full-
 cost method of accounting       1,115,29  1,107,84
                                 0         9
       Less      accumulated
depreciation,
         depletion       and     914,998   906,000
amortization
                                 --------  --------
                                 ----      ----
      Net   oil   and    gas     200,292   201,849
properties
                                 --------  --------
                                 ----      ----
                              $  235,779   217,697
                                 =======   =======
Liabilities  and   Partners'
Equity
----------------------------
------------

Current liability:
 Distribution payable         $  -         31
                                 --------  --------
                                 ----      ----

Asset retirement obligation      17,581    -
                                 --------  --------
                                 ----      ----
Partners' equity:
 Managing General Partner        26,829    23,666
 Investor partners               191,369   194,000
                                 --------  --------
                                 ----      ----
   Total partners' equity        218,198   217,666
                                 --------  --------
                                 ----      ----
                              $  235,779   217,697
                                 =======   =======











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

<PAGE>
             Southwest Developmental Drilling Fund 91-A, L.P.
                     (a Delaware limited partnership)
                         Statements of Operations
           For the years ended December 31, 2003, 2002 and 2001

                                        2003      2002      2001
                                        ----      ----      ----
Revenues
-------------
 Oil and gas sales                 $  158,356   104,083   139,132
 Interest income from operations      -         9         154
 Other                                3,446     1,003     -
                                      --------  --------  --------
                                      --        --        --
                                      161,802   105,095   139,286
                                      --------  --------  --------
                                      --        --        --
Expenses
-------------
 Production                           86,296    59,781    73,616
 General and administrative           22,890    16,372    15,345
  Accretion  of asset  retirement     1,302     -         -
obligation
   Depreciation,  depletion   and     28,221    26,000    20,000
amortization
                                      --------  --------  --------
                                      --        --        --
                                      138,709   102,153   108,961
                                      --------  --------  --------
                                      --        --        --
Net   income   before  cumulative
effects
 of accounting changes                23,093    2,942     30,325

Cumulative effect of change in
accounting
 principle - SFAS No. 143 - See       10,204    -         -
Note 3
Cumulative effect of change in
accounting principle
 - change in depletion method -       -         100,000   -
See Note 4
                                      --------  --------  --------
                                      --        --        --
Net income                         $  33,297    102,942   30,325
                                      ======    ======    ======
 Net income allocated to:

 Managing General Partner          $  6,767     3,184     5,536
                                      ======    ======    ======
 Investor partners                 $  26,530    99,758    24,789
                                      ======    ======    ======
    Per   investor  partner  unit  $   15.25      (.21)    21.66
before cumulative effect
  Cumulative effects per investor       7.93     87.37         -
partner unit
                                      --------  --------  --------
                                      --        --        --
  Per investor partner unit        $   23.18     87.16     21.66
                                      ======    ======    ======
Pro    forma   amounts   assuming
changes are applied
 retroactively (See Notes 3 and 4
for details):
  Net  income  before  cumulative  $  -         1,744     13,215
effect
                                      ======    ======    ======
    Per   investor  partner  unit  $       -     (1.14)     6.82
(1,144.5 units)
                                      ======    ======    ======





                  The accompanying notes are an integral
                   part of these financial statements.
<PAGE>
             Southwest Developmental Drilling Fund 91-A, L.P.
                     (a Delaware limited partnership)
                 Statement of Changes in Partners' Equity
           For the years ended December 31, 2003, 2002 and 2001

                            Managing
                            General   Investor
                            Partner   Partners   Total
                            -------   --------   -----
Balance at December 31,  $  23,823    141,272   165,095
2000

 Net income                 5,536     24,789    30,325

 Distributions              (6,846)   (55,388)  (62,234)
                            --------  --------  --------
                            --        ---       ----
Balance at December 31,     22,513    110,673   133,186
2001

 Net income                 3,184     99,758    102,942

 Distributions              (2,031)   (16,431)  (18,462)
                            --------  --------  --------
                            --        ---       ----
Balance at December 31,     23,666    194,000   217,666
2002

 Net income                 6,767     26,530    33,297

 Distributions              (3,604)   (29,161)  (32,765)
                            --------  --------  --------
                            --        ---       ----
Balance at December 31,  $  26,829    191,369   218,198
2003
                            ======    ======    =======
























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

<PAGE>
             Southwest Developmental Drilling Fund 91-A, L.P.
                     (a Delaware limited partnership)
                         Statements of Cash Flows
           For the years ended December 31, 2003, 2002 and 2001

                                     2003      2002      2001
                                     ----      ----      ----
Cash   flows  from   operating
activities:

  Cash  received from oil  and  $  148,024   101,165   152,656
gas sales
 Cash paid to Managing General
Partner
   for administrative fees and
general
  and administrative overhead      (110,759  (75,257)  (92,367)
                                   )
 Interest received                 -         9         154
 Miscellaneous settlement          3,446     1,003     -
                                   --------  --------  --------
                                   ----      ----      ----
     Net   cash  provided   by     40,711    26,920    60,443
operating activities
                                   --------  --------  --------
                                   ----      ----      ----
Cash  flows used in  investing
activities:

  Additions  to  oil  and  gas     (181)     (9,073)   (184)
properties
                                   --------  --------  --------
                                   ----      ----      ----
Cash  flows used in  financing
activities:

 Distributions to partners         (32,796)  (18,470)  (62,195)
                                   --------  --------  --------
                                   ----      ----      ----
Net  increase  (decrease)   in
cash and cash
 equivalents                       7,734     (623)     (1,936)

Beginning of period                11,779    12,402    14,338
                                   --------  --------  --------
                                   ----      ----      ----
End of period                   $  19,513    11,779    12,402
                                   =======   =======   =======

Reconciliation of  net  income
to net
  cash  provided by  operating
activities:

Net income                      $  33,297    102,942   30,325

Adjustments  to reconcile  net
income to
    net   cash   provided   by
operating activities:

 Accretion of asset retirement     1,302     -         -
obligation
  Depreciation, depletion  and     28,221    26,000    20,000
amortization
  Cumulative effect of  change     (10,204)  (100,000  -
in accounting principle                      )
    (Increase)   decrease   in     (10,332)  (2,918)   13,524
receivables
    (Decrease)   increase   in     (1,573)   896       (3,406)
payables
                                   --------  --------  --------
                                   ----      ----      ----
Net cash provided by operating  $  40,711    26,920    60,443
activities
                                   =======   =======   =======
Noncash investing and
financing activities:

 Increase in oil and gas
properties - Adoption
  of SFAS No. 143               $  26,483    -         -
                                   =======   =======   =======
                  The accompanying notes are an integral
                   part of these financial statements.
<PAGE>
             Southwest Developmental Drilling Fund 91-A, L.P.
                     (a Delaware limited partnership)

                      Notes to Financial Statements

1.   Organization
     Southwest  Developmental Drilling Fund 91-A, L.P. was organized  under
     the  laws of the state of Delaware on January 7, 1991 for the  purpose
     of  drilling  developmental and exploratory wells and to  produce  and
     market crude oil and natural gas produced from such properties  for  a
     term of 50 years, unless terminated at an earlier date as provided for
     in  the Partnership Agreement.  The Partnership sells its oil and  gas
     production  to  a  variety of purchasers with the prices  it  receives
     being  dependent  upon the oil and gas economy.  Southwest  Royalties,
     Inc.  serves  as  the Managing General Partner.  Revenues,  costs  and
     expenses are allocated as follows:

                              Managing
                              General   Investor
                              Partner   Partners
                              --------  --------
Interest  income on  capital  -         100%
contributions
Oil and gas sales*            11%       89%
All other revenues*           11%       89%
Organization  and   offering  -         100%
costs (1)
Syndication costs             -         100%
Amortization of organization  -         100%
costs
Lease acquisition costs       1%        99%
Gain/loss    on     property  11%       89%
disposition*
Operating and administrative  11%       89%
costs*(2)
Depreciation, depletion  and
amortization
 of oil and gas properties    -         100%
Intangible   drilling    and  -         100%
development costs
All other costs*              11%       89%

     *After the Investor Partners have received distributions totaling 150%
     of  their  capital contributions, the allocation will  change  to  15%
     Managing General Partner and 85% Investor Partners.

          (1)   All  organization costs in excess of 4% 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 4%  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.

<PAGE>
             Southwest Developmental Drilling Fund 91-A, L.P.
                     (a Delaware limited partnership)

                      Notes to Financial Statements

2.   Summary of Significant Accounting Policies - continued

     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 reserves 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,
     there  were no significant amounts of imbalance in terms of  units  or
     value.

     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 $197,039 and $197,013, 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 statement 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 Investor Partner Units
     As  of  December 31, 2003, 2002 and 2001, there were 1,144.5  investor
     partner units outstanding held by 101, 102 and 102 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.
<PAGE>
             Southwest Developmental Drilling Fund 91-A, L.P.
                     (a Delaware limited partnership)

                      Notes to Financial Statements

2.   Summary of Significant Accounting Policies - continued

     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)

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  $26,483,  a long term  liability  of  approximately
     $16,279 and a gain of approximately $10,204 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 $17,581, and the increase in the balance from  January
     1,  2003 of $1,302 is due to accretion expense.  The pro forma amounts
     of  the asset retirement obligation as of December 31, 2002, 2001  and
     2000,  were  approximately $16,279, $15,081 and $13,971, 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.  The pro forma amounts for the years  ended
     December  31,  2002 and 2001, which are presented below,  reflect  the
     effect of retroactive application of SFAS No. 143.

                                     2002      2001
                                   --------  -------
                                    ------
Pro   forma  amounts  assuming
change is applied
 retroactively:
  Net income before cumulative
effect
    for  change  in  depletion  $  1,744     29,215
method
                                    ======   ======
   Per  limited  partner  unit  $   (1.14)    20.80
(1,144.5 units)
                                    ======   ======
 Net income                     $  101,744   29,215
                                    ======   ======
   Per  limited  partner  unit  $    86.23    20.80
(1,144.5 units)
                                    ======   ======

     <PAGE>
             Southwest Developmental Drilling Fund 91-A, L.P.
                     (a Delaware limited partnership)

                      Notes to Financial Statements

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 $100,000 effective as of January
     1,  2002.   The Partnership's depletion for the years ended  2003  and
     2002  have  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.

                                     2001

                                   -------
Pro   forma  amounts  assuming
change is applied
 retroactively:
 Net income                     $  14,325
                                   ======
   Per  limited  partner  unit  $    7.68
(1,144.5 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
     The Managing General Partner has the right, but not the obligation, to
     purchase limited partnership units should an investor desire to  sell.
     The  value of the unit is determined by adding the sum of (1)  current
     assets  less liabilities and (2) the present value of the  future  net
     revenues attributable to proved reserves and by discounting the future
     net  revenues  at  a rate not in excess of the prime rate  charged  by
     NationsBank, N.A. of Midland, Texas plus one percent (1%), which value
     shall be further reduced by a risk factor discount of no more than one-
     third  (1/3) to be determined by the Managing General Partner  in  its
     sole and absolute discretion.

     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.


<PAGE>
             Southwest Developmental Drilling Fund 91-A, L.P.
                     (a Delaware limited partnership)

                      Notes to Financial Statements

6.   Commitments and Contingent Liabilities - continued
     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  reliably
     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 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  $12,000,
     $12,100  and $11,800 for the years ended December 31, 2003,  2002  and
     2001,  respectively.   In addition, the Managing General  Partner  and
     certain  officers and employees may have an interest in  some  of  the
     properties that the Partnership also participates.

     Southwest  Royalties,  Inc., the Managing General  Partner,  was  paid
     $9,400  in 2003, 2002 and 2001 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 $16,000 and $4,100 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 97% of the Partnership's total oil  and  gas
     production  during 2003: Plains Marketing LP for 80% and  Duke  Energy
     Field  Services LP for 17%.  One purchaser accounted for  85%  of  the
     Partnership's  total  oil  and  gas  production  during  2002:  Plains
     Marketing  LP  for  85%.   Two purchasers accounted  for  94%  of  the
     Partnership's  total  oil  and  gas  production  during  2001:  Plains
     Marketing  LP  for 76% and Duke Energy Field Services  for  18%.   All
     purchasers  of the Partnership's oil and gas production are  unrelated
     third  parties.   In  the  event this purchaser  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  total  oil  and  gas
     production.

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.

<PAGE>
             Southwest Developmental Drilling Fund 91-A, L.P.
                     (a Delaware limited partnership)

                      Notes to Financial Statements

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               49,000    69,000

  Revisions of estimates  in  (20,000)  (32,000)
place
 Production                   (4,000)   (6,000)
                              --------  --------
                              --        --
December 31, 2001             25,000    31,000

  Revisions of estimates  in  2,000     (1,000)
place
 Production                   (4,000)   (4,000)
                              --------  --------
                              --        --
December 31, 2002             23,000    26,000

  Revisions of estimates  in  11,000    7,000
place
 Production                   (4,000)   (5,000)
                              --------  --------
                              --        --
December 31, 2003             30,000    28,000
                              ======    ======
Proved developed reserves -

December 31, 2001             25,000    31,000
                              ======    ======
December 31, 2002             23,000    26,000
                              ======    ======
December 31, 2003             30,000    28,000
                              ======    ======

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

     *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 $31.81, $29.68 and $18.98 per barrel, respectively.

     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 $5.49,  $4.20
     and $2.28 per Mcf, respectively.

     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.
<PAGE>
             Southwest Developmental Drilling Fund 91-A, L.P.
                     (a Delaware limited partnership)

                      Notes to Financial Statements

10.  Estimated Oil and Gas Reserves (unaudited) - continued
     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.  All of the proved reserves are included in the engineering
     reports, which evaluate the Partnership's present reserves.

     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           $  1,113,00  805,000   553,000
                                 0
Production, development and
 abandonment costs               717,000   428,000   395,000
                                 --------  --------  --------
                                 ----      ----      --
Future net cash flows            396,000   377,000   158,000
10%   annual  discount   for
estimated
 timing of cash flows            94,000    103,000   37,000
                                 --------  --------  --------
                                 ----      ----      --
Standardized   measure    of
discounted
 future net cash flows        $  302,000   274,000   121,000
                                 =======   =======   ======

     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 costs      $  (72,000)  (44,000)  (66,000)
Changes   in   prices    and     (40,000)  174,000   (346,000
production costs                                     )
Changes of production rates
 (timing) and others             7,000     (7,000)   16,000
Revisions of previous
 quantities estimates            106,000   18,000    (101,000
                                                     )
Changes in estimated future
 development costs                         -         -
Accretion of discount            27,000    12,000    56,000
Discounted future net
 cash flows -
Beginning of year                274,000   121,000   562,000
                                 --------  --------  --------
                                 --        --        --
End of year                   $  302,000   274,000   121,000
                                 ======    ======    ======

     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 Developmental Drilling Fund 91-A, L.P.
                     (a Delaware limited partnership)

                      Notes to Financial Statements

11.  Selected Quarterly Financial Results - (unaudited)

                                             Quarter
                              --------------------------------------
                              --------------------------------------
                                                -
                               First     Second    Third     Fourth
                               ------   --------  -------   --------
                                          ---                  -
2003:
 Total revenues             $ 42,713    48,914    36,008    34,167
 Total expenses               46,431    37,308    34,337    20,633
  Net income (loss) before
cumulative effect
     of   a   change    in    (3,718)   11,606    1,671     13,534
accounting principle
 Cumulative effect of SFAS    10,204    -         -         -
No. 143
                              --------  --------  --------  --------
                              ----      ----      ----      ----
 Net income                 $ 6,486     11,606    1,671     13,534
                              =======   =======   =======   =======
  Per limited partner unit
amounts:
   Income  (loss)   before  $ (3.75)                   .82
cumulative effect                       8.26                9.92
 Cumulative effect              7.93         -         -         -
                              --------  --------  --------  --------
                              ----      ----      ----      ----
 Net income                 $   4.18                   .82
                                        8.26                9.92
                              =======   =======   =======   =======

     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             $ 18,477    31,744    25,395    29,479
 Total expenses               24,343    25,068    21,650    31,092
                              --------  --------  --------  --------
                              ----      ----      ----      ----
  Net Income (loss) before
cumulative effect
     of   a   change    in    (5,866)   6,676     3,745     (1,613)
accounting principle
   Cumulative  effect   on
prior years (to
   December 31,  2001)  of
changing to a
     different   depletion    100,000   -         -         -
method
                              --------  --------  --------  --------
                              ----      ----      ----      ----
 Net income (loss)          $ 94,134    6,676     3,745     (1,613)
                              =======   =======   =======   =======
  Per limited partner unit
amounts:
   Income  (loss)   before
cumulative effect of a
    change  in  accounting  $ (5.13)
principle                               4.42      2.43      (1.93)
   Cumulative  effect   on
prior years (to
   December 31,  2001)  of
changing to a
     different   depletion     87.37         -         -         -
method
                              --------  --------  --------  --------
                              ----      ----      ----      ----
 Net income (loss)          $  82.24
                                        4.42      2.43      (1.93)
                              =======   =======   =======   =======



<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,
its 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 a 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. Radeki 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.

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.

<PAGE>
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
$9,400,  $10,800  and  $10,800 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 Stockholders 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 an eleven percent interest as a Managing
General Partner. Through prior purchases, the Managing General Partner also
owns  72  limited  partner units, or 5.6% limited  partner  interest.   The
Managing  General  Partner  total  percentage  interest  ownership  in  the
Partnership is 16.6%.

No  officer or director of the Managing General Partner directly owns Units
in  the Partnership.  H. H. Wommack, III, as the individual general partner
of  the Partnership, owns a one percent interest as a general partner.  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        5.6%
Interest               Inc.                      Owns
                       Managing      General     72 Units
                       Partner
                       407   N.  Big  Spring
                       Street
                       Midland, TX 79701

Limited Partnership    H. H. Wommack, III        Indirectly      5.6%
Interest                                         Owns
                       Chairman    of    the     72 Units
                       Board,
                       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 $9,400 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 working interest.  Certain properties  in
which  the Partnership has an interest are operated by the Managing General
Partner,  who  was  paid approximately $12,000 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                     $9,056    $
                                         4,763
Audit Related Fees                  -
                                         -
Tax Fees                            -
                                         -
All Other Fees                      -
                                         -

    TOTAL                      $9,056    $
                                         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
                  Statement of Operations
                  Statement of Changes in Partners' Equity
                  Statement 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  of  Limited
                          Partnership  of Southwest Developmental  Drilling
                          Fund   91-A,   L.P.,  dated  January   9,   1991.
                          (Incorporated  by  reference  from  Partnership's
                          Form 10-K for the fiscal year ended December  31,
                          1991.)

                                            (b)    Agreement   of   Limited
                          Partnership  of Southwest Developmental  Drilling
                          Fund   91-A,   L.P.   dated  January   9,   1991.
                          (Incorporated  by  reference  from  Partnership's
                          Form 10-K for the fiscal year ended December  31,
                          1991.)

                                          (c)   Second Amended and Restated
                          Certificate  of Limited Partnership of  Southwest
                          Developmental Drilling Fund 91-A. L.P., dated  as
                          of  February 1, 1993. (Incorporated by  reference
                          from  Partnership's Form 10-K for the fiscal year
                          ended December 31, 1993.)

                                          (d)   Second Amended and Restated
                          Certificate  of Limited Partnership of  Southwest
                          Developmental Drilling Fund 91-A. L.P., dated  as
                          of  January 12, 1994. (Incorporated by  reference
                          from  Partnership's Form 10-K for the fiscal year
                          ended December 31, 1993.)

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

          (b)     Reports on Form 8-K

                  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 Developmental Drilling Fund  91-
                          A, L.P.,
                          a Delaware 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
Developmental Drilling Fund 91-
A, L.P.

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 Developmental Drilling Fund 91-
A, L.P.



<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 Developmental Drilling Fund 91-
A, L.P.

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 Developmental Drilling Fund 91-
A, L.P.

<PAGE>
                        CERTIFICATION PURSUANT TO           Exhibit 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  Developmental
Drilling Fund 91-A, 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 Developmental Drilling Fund 91-A, L.P.

<PAGE>
           CERTIFICATION PURSUANT TO               Exhibit 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 Developmental Drilling
Fund 91-A, 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 Developmental Drilling Fund 91-A, L.P.


<PAGE>