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, 2002

                                    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 (915) 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 (229.405 of this chapter) 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]

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  40.   The  exhibit
index is found on page 38.

<PAGE>
                            Table of Contents

Item                                                                   Page

                                  Part I

 1.  Business                                                            3

 2.  Properties                                                          5

 3.  Legal Proceedings                                                   6

 4.  Submission of Matters to a Vote of Security Holders                 6

                                 Part II

 5.  Market for Registrant's Common Equity and Related
     Stockholder Matters                                                 7

 6.  Selected Financial Data                                             8

 7.  Management's Discussion and Analysis of
     Financial Condition and Results of Operations                       9

 8.  Financial Statements and Supplementary Data                        16

 9.  Changes in and Disagreements with Accountants
     on Accounting and Financial Disclosure                             29

                                 Part III

10.  Directors and Executive Officers of the Registrant                 30

11.  Executive Compensation                                             32

12.  Security Ownership of Certain Beneficial Owners and
     Management                                                         32

13.  Certain Relationships and Related Transactions                     33

                                 Part IV

14.  Exhibits, Financial Statement Schedules, and Reports
     on Form 8-K                                                        34

     Signatures                                                         35

<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  82  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.

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>
In  2002, fighting and threats of fighting in the Middle East and a  strike
in  a  major  oil exporting country dominated the direction  of  crude  oil
prices.  While OPEC agreed to keep production constant throughout the year,
conflicts  between  the U.S. and Iraq, as well as between  Israel  and  the
Palestinians  threatened supplies and caused oil prices to surge  in  2002.
In  addition,  a  strike by oil workers in Venezuela,  the  fourth  largest
supplier to the U.S., took a significant amount of crude oil off the market
toward  the end of the year.  As a result, OPEC agreed in January  2003  to
increase output by 1.5 million barrels per day in an effort to make up  for
the lost supply and stabilize prices.

In  2002,  spot prices for natural gas fell by 27.5% from the unprecedented
heights  reached in 2001, averaging just under $3.00/MMBtu  for  the  year.
Most  of  the  lowest  prices were seen early on, with  the  first  quarter
averaging  of  $2.24/MMBtu.   But as the year  progressed,  prices  climbed
higher,  ending  with a $3.99 average in December.  As for  2003,  industry
analysts are divided on their gas price predictions, with estimates ranging
anywhere  from $4.00 to $6.00/MMBtu.  Weather forecasts, storage  inventory
levels,  a  tighter  supply and demand balance, and the unstable  situation
with  Iraq  are  all  factors that will have a significant  impact  on  the
direction  prices will take.  Overall however, analysts are  maintaining  a
bullish perspective, expecting gas prices to remain at or above $4.00/MMBtu
in 2003.

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

            Oil       Gas
            ----      ----
  2002      90%       10%
  2001      82%       18%
  2000      85%       15%

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 is highly seasonal, with higher  demand
in  the colder winter months and in very hot summer months, the Partnership
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.  As a
result,  the volumes sold by the Partnership have not fluctuated materially
with the change of season.

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.  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%.  Two purchasers accounted
for  91%  of  the Partnership's total oil and gas production  during  2000:
Plains  Marketing  LP  for 78% and Duke Energy Transport  for  13%.     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.

<PAGE>
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.

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.  Moreover, certain prices  at,
which  the  Partnership may sell its natural gas production, are controlled
by  the  Natural Gas Policy Act of 1978, the Natural Gas Wellhead Decontrol
Act  of  1989  and  the  regulations  promulgated  by  the  Federal  Energy
Regulatory Commission.

Environmental  - The Partnership's oil and gas activities  are  subject  to
extensive  federal,  state  and local laws and  regulations  governing  the
generation,  storage, handling, emission, transportation and  discharge  of
materials into the environment.  Governmental authorities have the power to
enforce compliance with their regulations, and violations carry substantial
penalties.   This  regulatory burden on the oil and gas industry  increases
its cost of doing business and consequently affects its profitability.  The
Managing  General  Partner  is  unable to  predict  what,  if  any,  effect
compliance will have on the Partnership.

Industry  Regulations  and  Guidelines - Certain industry  regulations  and
guidelines  apply to the registration, qualification and operation  of  oil
and  gas programs in the form of limited partnerships.  The Partnership  is
subject  to  these  guidelines  which regulate  and  restrict  transactions
between  the Managing General Partner and the Partnership.  The Partnership
complies  with these guidelines and the Managing General Partner  does  not
anticipate that continued compliance will have a material adverse effect on
Partnership operations.

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,
2002  there  were 82 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, 2002, 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
5 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 2002, 2001 and 2000.

<PAGE>
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       19,000    18,000
Ward County,        89%
Texas             working
                 interest

*Ryder Scott Company, L.P. prepared the reserve and present value data  for
the  Partnership's existing properties as of January 1, 2003.  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, 2003 are an average price of $29.68 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, 2003 are  an
average price of $4.20 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 2002.

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
producing  and proved developed non-producing.  All of the proved  reserves
are  included  in the engineering reports, which evaluate the Partnership's
present reserves.

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 2002 through the solicitation of proxies or otherwise.

<PAGE>
                                 Part II


Item 5.   Market for the Registrant's Common Equity and Related Stockholder
          Matters

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,  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.  As of
December  31, 2002, no limited partner units were purchased by the Managing
General Partner.  Southwest, as Managing General Partner, evaluated several
liquidity alternatives for the partnerships in 2001 and 2002.  During 2002,
Southwest  specifically pursued the possible roll-up and merger of  twenty-
one   (21)  partnerships  with  the  general  partner.   Because   of   the
complexities and conflicts of interest in such a transaction, the  Managing
General  Partner  did not make a formal repurchase offer in  2002  but  has
responded  to  limited  partners  desiring  to  sell  their  units  in  the
partnerships  on  an "as requested" basis.  Southwest anticipates  that  it
will maintain this policy in 2003 because the aforementioned transaction is
ongoing.   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.  As of December 31, 2000, no limited partner units were purchased  by
the Managing General Partner.

Number of Limited and General Partner Interest Holders
As  of  December 31, 2002, there were 102 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."

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. During 2000, quarterly distributions were  made
totaling  $121,035, with $107,721 distributed to the investor partners  and
$13,314  to the Managing General Partner.  For the year ended December  31,
2000,  distributions of $94.12 per investor partner unit were  made,  based
upon 1,144.50 investor partner units outstanding.

<PAGE>
Item 6.   Selected Financial Data

The  following  selected financial data for the years  ended  December  31,
2002,  2001,  2000,  1999 and 1998 should be read in conjunction  with  the
financial statements included in Item 8:

                                Years ended December 31,
                   --------------------------------------------------
                                           ---
                                                              Restate
                                                                 d
                     2002       2001       2000       1999      1998
                     ----       ----       ----       ----      ----
Revenues        $  105,095    139,286    162,884    252,026   172,847

Net     income     15,942     30,325     58,242     119,990   (3,178)
(loss)

Partners'
share of
   net  income
(loss):

Managing
General
 Partner           3,184      5,536      7,617      17,159    5,480

Investor           12,758     24,789     50,625     102,831   (8,658)
partners

Investor
partners'
   net  income
(loss)
  per unit          11.15
                              21.66      44.23      89.85     (7.57)

Investor
partners'
          cash
distributions
per unit            14.36
                              48.39      94.12      66.10     31.49

Total assets    $  130,697    133,225    165,095    237,888   195,528

<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  2003 to enhance production.  Additional workovers may be  performed
in  the  year  2004.   The partnership may have an increase  in  production
volumes  for  the  year 2004, otherwise, the partnership will  most  likely
experience the historical production decline, which have approximated   14%
per year.

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.

Prior  to October 1, 2002, the Partnership calculated depletion of oil  and
gas  properties under the units of revenue method.  The Partnership changed
methods  of estimating depletion effective October 1, 2002 to the units  of
production  method.   The units of production method is more  predominantly
used throughout the oil and gas industry and will allow the Partnership  to
more  closely align itself with its peers.  This change in estimate had  no
impact on depletion expense for the fourth quarter.

<PAGE>
A.  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%)
Gross oil and gas        $  104,083   139,132    (25%)
revenue
Net oil and gas revenue  $  44,302    65,516     (32%)
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 $89,153 from $108,961 for the  years
ended  December 31, 2002 and 2001, respectively, a decrease  of  18%.   The
decrease  is  the  result of lower depletion expense  and  lease  operating
costs, partially offset an increase in general and administrative costs.

1.    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 decreased to $13,000 for the year ended December  31,
    2002  from  $20,000  for the same period in 2001.   This  represents  a
    decrease  of 35%.  Prior to October 1, 2002, the Partnership calculated
    depletion of oil and gas properties under the units of revenue  method.
    The  Partnership  changed  methods of  estimating  depletion  effective
    October  1,  2002  to  the units of production method.   The  units  of
    production method is more predominantly used throughout the oil and gas
    industry  and  will allow the Partnership to more closely align  itself
    with  its  peers.  This change in estimate had no impact  on  depletion
    expense for the fourth quarter.

   The  major  factor  in  the decrease in depletion  expense  between  the
   comparative periods was the increase in oil and gas prices of  the  2003
   reserves  as compared to 2002, and the decrease in oil and gas  revenues
   received by the Partnership during 2002 as compared to 2001.

<PAGE>
B.  General Comparison of the Years Ended December 31, 2001 and 2000

The  following  table  provides certain information  regarding  performance
factors for the years ended December 31, 2001 and 2000:

                                Year Ended      Percenta
                                                   ge
                               December 31,     Increase
                              2001      2000    (Decreas
                                                   e)
                              ----      ----    --------
                                                   -

Average price per        $    25.84              (14%)
barrel of oil                         29.88
Average price per mcf    $     4.41               15%
of gas                                3.82
Oil production in           4,440     4,600       (3%)
barrels
Gas production in mcf       5,540     6,600      (16%)
Gross oil and gas        $  139,132   162,628    (14%)
revenue
Net oil and gas revenue  $  65,516    83,755     (22%)
Partnership              $  62,234    121,035    (49%)
distributions
Investor partner         $  55,388    107,721    (49%)
distributions
Per unit distribution    $    48.39              (49%)
to investor partners                  94.12
Number of investor          1,144.5
partner units                         1,144.5

Revenues

The  Partnership's oil and gas revenues decreased to $139,132 from $162,628
for the years ended December 31, 2001 and 2000, respectively, a decrease of
14%.   The  principal factors affecting the comparison of the  years  ended
December 31, 2001 and 2000 are as follows:

1.  The  average  price  for a barrel of oil received  by  the  Partnership
    decreased  during the year ended December 31, 2001 as compared  to  the
    year ended December 31, 2000 by 14%, or $4.04 per barrel, resulting  in
    a  decrease of approximately $17,900 in revenues. Oil sales represented
    82%  of total oil and gas sales during the year ended December 31, 2001
    as compared to 85% during the year ended December 31, 2000.

    The  average  price  for  an  mcf of gas received  by  the  Partnership
    increased during the same period by 15%, or $.59 per mcf, resulting  in
    an increase of approximately $3,300 in revenues.

    The net total decrease in revenues due to the change in prices received
    from oil and gas production is approximately $14,600.  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 decreased approximately 160 barrels or 3%  during  the
   year ended December 31, 2001 as compared to the year ended December  31,
   2000, resulting in a decrease of approximately $4,800 in revenues.

    Gas production decreased approximately 1,060 mcf or 16% during the same
    period, resulting in a decrease of approximately $4,000 in revenues.

    The  total  decrease  in revenues due to the change  in  production  is
    approximately  $8,800.  Gas production is down due to  workovers  being
    performed on one lease.

Costs and Expenses

Total  costs and expenses increased to $108,961 from $104,642 for the years
ended  December 31, 2001 and 2000, respectively, an increase  of  4%.   The
increase  is  the  result  of  higher depletion  expense  and  general  and
administrative costs, partially offset a decrease in lease operating costs.

1.  Lease   operating  costs  and  production  taxes  were  7%  lower,   or
    approximately $5,300 less during the year ended December  31,  2001  as
    compared to the year ended December 31, 2000.

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 4%
    or  approximately  $600  during the year ended  December  31,  2001  as
    compared to the year ended December 31, 2000.

3.  Depletion expense increased to $20,000 for the year ended December  31,
    2001  from  $11,000  for the same period in 2000.  This  represents  an
    increase  of 82%.  Depletion is calculated using the units  of  revenue
    method  of  amortization based on a percentage of current period  gross
    revenues  to  total future gross oil and gas revenues, as estimated  by
    the Partnership's independent petroleum consultants.

   The  major  factor  in  the increase in depletion  expense  between  the
   comparative periods was the decrease in oil and gas prices of  the  2002
   reserves  as compared to 2001, and the decrease in oil and gas  revenues
   received  by the Partnership during 2001 as compared to 2000.  Revisions
   of  previous  estimates can be attributed to the changes  in  production
   performance, oil and gas price and production costs.  The impact of  the
   revision  would  have increased depletion expense approximately  $10,000
   as of December 31, 2000.

<PAGE>
C.  Revenue and Distribution Comparison

Partnership net income for the years ended December 31, 2002, 2001 and 2000
was  $15,942, $30,325 and $58,242, respectively.  Excluding the effects  of
depreciation,  depletion and amortization, net income for the  years  ended
December  31,  2002,  2001  and  2000 was  $28,942,  $50,325  and  $69,242,
respectively.   Correspondingly, Partnership distributions  for  the  years
ended  December 31, 2002, 2001 and 2000 were $18,462, $62,234 and $121,035,
respectively.

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.   The sources for the 2000 distributions of $121,035 were  oil  and
gas  operations  of approximately $78,700 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, 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.
Total  distributions during the year ended December 31, 2000 were  $121,035
of  which $107,721 was distributed to the investor partners and $13,314  to
the  Managing  General  Partner.   The per unit  distribution  to  investor
partners during the same period was $94.12.

Since  inception of the Partnership, cumulative monthly cash  distributions
of  $1,414,471  have been made to the partners.  As of December  31,  2002,
$1,260,790 or $1,101.61 per investor partner unit, has been distributed  to
the  investor  partners, representing a 100% return of capital  and  a  10%
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 $26,900  in
2002  compared to $60,400 in 2001 and approximately $78,700 in  2000.   The
primary  source  of  the  2002  cash flow  from  operating  activities  was
profitable operations.

Cash  flows used in investing activities were approximately $9,100 in  2002
compared to $200 in 2001 and approximately $200 in 2000. The principal  use
of  the  2002 cash flow from investing activities was additions to oil  and
gas properties.

Cash  flows used in financing activities were approximately $18,500 in 2002
compared  to $62,200 in 2001 and approximately $120,400 in 2000.  The  only
use in the 2002 financing activities was the distributions to partners.

As  of  December  31,  2002, the Partnership had approximately  $15,800  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  Managing  General
Partner  anticipates that at some point in the near future, the partnership
will  need  to be liquidated.  Maintenance of properties and administrative
expenses are increasing relative to production.  As the properties continue
to  deplete,  maintenance  of  properties and  administrative  costs  as  a
percentage of production will continue to increase.

As  the  partnerships  properties have matured, the  net  cash  flows  from
operations  for the partnership have generally declined, except in  periods
of substantially increased commodity pricing.  Since the partnership cannot
develop their non-producing properties, the producing reserves continue  to
deplete causing cash flow to steadily decline.

On October 17, 2002, Southwest Royalties, Inc. the Managing General Partner
filed  an S-4 "Registration of Securities, Business Combinations" with  the
Securities and Exchange Commission.  The S-4 relates to a proposed plan  of
merger of twenty-one limited partnerships.


<PAGE>
Liquidity - Managing General Partner

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

Based   on  current  production,  commodity  prices  and  cash  flow   from
operations,  the Managing General Partner has adequate cash  flow  to  fund
debt  service, developmental projects and day to day operations, but it  is
not  sufficient  to  build a cash balance which would  allow  the  Managing
General  Partner to meet its debt principal maturities scheduled for  2004.
Therefore  the Managing General Partner must renegotiate the terms  of  its
various  obligations or seek new lenders or equity investors  in  order  to
meet  its financial obligations, specifically those maturing in 2004.   The
Managing  General Partner may be required to dispose of certain  assets  in
order to meet its obligations.

There  can  be  no  assurance  that  the Managing  General  Partner's  debt
restructuring  efforts  will be successful or that the  debt  holders  will
agree  to a course of action consistent with the Managing General Partner's
requirements in restructurings the obligations.  Furthermore, there can  be
no  assurance that the sales of assets can be successfully accomplished  on
terms acceptable to the Managing General Partner.

Recent Accounting Pronouncements

The  FASB  has  issued Statement No. 143 "Accounting for  Asset  Retirement
Obligations" which establishes requirements for the accounting of  removal-
type  costs  associated with asset retirements.  The standard is  effective
for  fiscal  years beginning after June 15, 2002, with earlier  application
encouraged.  The Managing General Partner is currently assessing the impact
on the partnerships financial statements.

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                                             17

Balance Sheets                                                          18

Statements of Operations                                                19

Statement of Changes in Partners' Equity                                20

Statements of Cash Flows                                                21

Notes to Financial Statements                                           22

<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,  2002  and
2001, 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,  2002.  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, 2002 and 2001 and the  results
of  its  operations and its cash flows for each of the years in  the  three
year   period  ended  December  31,  2002  in  conformity  with  accounting
principles generally accepted in the United States of America.








                                                  KPMG LLP



Midland, Texas
March 14, 2003

<PAGE>

             Southwest Developmental Drilling Fund 91-A, L.P.
                     (a Delaware limited partnership)
                              Balance Sheets
                        December 31, 2002 and 2001

                                   2002      2001
                                   ----      ----
Assets
----------

Current assets:
 Cash and cash equivalents    $  11,779    12,402
  Receivable  from  Managing     4,069     2,047
General Partner
                                 --------  --------
                                 ----      ----
   Total current assets          15,848    14,449
                                 --------  --------
                                 ----      ----
Oil  and  gas  properties  -
using the full-
 cost method of accounting       1,107,84  1,098,77
                                 9         6
       Less      accumulated
depreciation,
         depletion       and     993,000   980,000
amortization
                                 --------  --------
                                 ----      ----
      Net   oil   and    gas     114,849   118,776
properties
                                 --------  --------
                                 ----      ----
                              $  130,697   133,225
                                 =======   ========
                                           =
Liabilities  and   Partners'
Equity
----------------------------
------------

Current liability:
 Distribution payable         $  31        39
                                 --------  --------
                                 ----      ----
Partners' equity:
 Managing General Partner        23,666    22,513
 Investor partners               107,000   110,673
                                 --------  --------
                                 ----      ----
   Total partners' equity        130,666   133,186
                                 --------  --------
                                 ----      ----
                              $  130,697   133,225
                                 =======   ========
                                           =











                  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, 2002, 2001 and 2000


                              2002      2001      2000
                              ----      ----      ----

Revenues
-------------

Oil and gas sales        $  104,083   139,132   162,628
Interest  income   from     9         154       256
operations
Miscellaneous               1,003     -         -
                            --------  --------  --------
                            --        --        --
                            105,095   139,286   162,884
                            --------  --------  --------
                            --        --        --
Expenses
-------------

Production                  59,781    73,616    78,873
General             and     16,372    15,345    14,769
administrative
Depreciation, depletion     13,000    20,000    11,000
and amortization
                            --------  --------  --------
                            --        --        --
                            89,153    108,961   104,642
                            --------  --------  --------
                            --        --        --
Net income               $  15,942    30,325    58,242
                            ======    ======    ======
  Net  income allocated
to:

    Managing    General  $  3,184     5,536     7,617
Partner
                            ======    ======    ======
 Investor partners       $  12,758    24,789    50,625
                            ======    ======    ======
   Per investor partner  $   11.15
unit                                  21.66     44.23
                            ======    ======    ======
















                  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, 2002, 2001 and 2000


                            Managing
                            General   Investor
                            Partner   Partners   Total
                            -------   --------   -----
Balance at December 31,  $  29,520    198,368   227,888
1999

 Net income                 7,617     50,625    58,242

 Distributions              (13,314)  (107,721  (121,035
                                      )         )
                            --------  --------  --------
                            --        ---       ----
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     12,758    15,942

 Distributions              (2,031)   (16,431)  (18,462)
                            --------  --------  --------
                            --        ---       ----
Balance at December 31,  $  23,666    107,000   130,666
2002
                            ======    ======    =======























                  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, 2002, 2001 and 2000

                                   2002      2001      2000
                                   ----      ----      ----
Cash  flows  from  operating
activities:

  Cash received from oil and  $  101,165   152,656   166,419
gas sales
   Cash   paid  to  Managing
General Partner
   for  administrative  fees
and general
      and     administrative     (75,257)  (92,367)  (87,964)
overhead
 Interest received               9         154       256
 Miscellaneous settlement        1,003     -         -
                                 --------  --------  --------
                                 ----      ----      ----
     Net  cash  provided  by     26,920    60,443    78,711
operating activities
                                 --------  --------  --------
                                 ----      ----      ----
Cash flows used in investing
activities:

  Additions to oil  and  gas     (9,073)   (184)     (151)
properties
                                 --------  --------  --------
                                 ----      ----      ----
Cash flows used in financing
activities:

 Distributions to partners       (18,470)  (62,195)  (120,418
                                                     )
                                 --------  --------  --------
                                 ----      ----      ----
Net  decrease  in  cash  and
cash
 equivalents                     (623)     (1,936)   (41,858)

Beginning of period              12,402    14,338    56,196
                                 --------  --------  --------
                                 ----      ----      ----
End of period                 $  11,779    12,402    14,338
                                 =======   =======   =======

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

Net income                    $  15,942    30,325    58,242

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

 Depreciation, depletion and     13,000    20,000    11,000
amortization
   (Increase)  decrease   in     (2,918)   13,524    3,791
receivables
   Increase  (decrease)   in     896       (3,406)   5,678
payables
                                 --------  --------  --------
                                 ----      ----      ----
Net    cash   provided    by  $  26,920    60,443    78,711
operating activities
                                 =======   =======   =======




                  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.

     Prior to October 1, 2002, the Partnership calculated depletion of  oil
     and gas properties under the units of revenue method.  The Partnership
     changed  methods of estimating depletion effective October 1, 2002  to
     the  units  of production method.  The units of production  method  is
     more  predominantly used throughout the oil and gas industry and  will
     allow  the  Partnership to more closely align itself with  its  peers.
     This  change  in estimate had no impact on depletion expense  for  the
     fourth quarter.

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

                      Notes to Financial Statements

2.   Summary of Significant Accounting Policies - continued

     Oil and Gas Properties - continued
     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  years ended December 31, 2001, 2000 and for the nine  months
     ended  September 30, 2002, 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, 2002,
     2001  and  2000 the net capitalized costs did not exceed the estimated
     present value of oil and gas reserves.

     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,  2002,  2001  and
     2000, 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,  2002  and 2001 is $110,013 and $113,822, respectively, less  than
     that  shown  on  the  accompanying Balance Sheets in  accordance  with
     generally accepted accounting principles.
<PAGE>
             Southwest Developmental Drilling Fund 91-A, L.P.
                     (a Delaware limited partnership)

                      Notes to Financial Statements

2.   Summary of Significant Accounting Policies - continued

     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, 2002, 2001 and 2000, there were 1,144.5  investor
     partner units outstanding held by 102, 102 and 103 partners.

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

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

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

     Recent Accounting Pronouncements
     The FASB has issued Statement No. 143 "Accounting for Asset Retirement
     Obligations"  which  establishes requirements for  the  accounting  of
     removal-type costs associated with asset retirements.  The standard is
     effective for fiscal years beginning after June 15, 2002, with earlier
     application  encouraged.  The Managing General  Partner  is  currently
     assessing the impact on the partnerships financial statements.



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

                      Notes to Financial Statements

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

     Based  on  current  production, commodity prices and  cash  flow  from
     operations,  the Managing General Partner has adequate  cash  flow  to
     fund  debt  service, developmental projects and day to day operations,
     but it is not sufficient to build a cash balance which would allow the
     Managing  General  Partner  to  meet  its  debt  principal  maturities
     scheduled  for  2004.   Therefore the Managing  General  Partner  must
     renegotiate  the terms of its various obligations or seek new  lenders
     or  equity  investors  in  order to meet  its  financial  obligations,
     specifically  those  maturing in 2004.  The Managing  General  Partner
     would  also consider disposing of certain assets in order to meet  its
     obligations.

     There  can  be  no assurance that the Managing General Partner's  debt
     restructuring efforts will be successful or that the debt holders will
     agree  to  a  course  of action consistent with the  Managing  General
     Partner's    requirements   in   restructurings    the    obligations.
     Furthermore, there can be no assurance that the sales of assets can be
     successfully accomplished on terms acceptable to the Managing  General
     Partner.

4.   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.

     Southwest,  as  Managing General Partner, evaluated several  liquidity
     alternatives  for  the partnerships in 2001 and  2002.   During  2002,
     Southwest  specifically pursued the possible  roll-up  and  merger  of
     twenty-one (21) partnerships with the general partner.  Because of the
     complexities  and  conflicts of interest in such  a  transaction,  the
     Managing  General  Partner did not make a formal repurchase  offer  in
     2002  but  has  responded to limited partners desiring to  sell  their
     units  in  the  partnerships  on an "as requested"  basis.   Southwest
     anticipates  that  it will maintain this policy in  2003  because  the
     aforementioned transaction is ongoing.

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

     As  of December 31, 2002, 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.

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

                      Notes to Financial Statements

5.   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  $12,100,
     $11,800  and $11,400 for the years ended December 31, 2002,  2001  and
     2000,   respectively.   The   amounts  for   administrative   overhead
     attributable  to  operating  the  partnership  properties  have   been
     deducted from gross oil and gas revenues in the determination  of  net
     profit  interest.      In addition, the Managing General  Partner  and
     certain  officers and employees may have an interest in  some  of  the
     properties that the Partnership also participates.

     Certain  subsidiaries  or affiliates of the Managing  General  Partner
     perform  various  oilfield  services  for  properties  in  which   the
     Partnership  owns an interest.  Such services aggregated approximately
     $700,  $1,100 and $4,300 for the years ended December 31,  2002,  2001
     and  2000,  respectively. The amounts for oilfield services  performed
     for the partnership by affiliates of the Managing General Partner have
     been deducted from gross oil and gas revenues in the determination  of
     net profit interest.

     Southwest  Royalties,  Inc., the Managing General  Partner,  was  paid
     $10,800 in 2002, 2001 and 2000 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 $4,100 and $2,000 are  from  oil  and  gas
     production, net of lease operating costs and production taxes,  as  of
     December 31, 2002 and 2001, respectively.

6.   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.   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%.   Two  purchasers  accounted  for  91%   of   the
     Partnership's  total  oil  and  gas  production  during  2000:  Plains
     Marketing  LP  for  78%  and  Duke  Energy  Transport  for  13%.   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.

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

                      Notes to Financial Statements

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

                                Oil       Gas
                               (bbls)    (mcf)
                              --------  --------
                                 --        -
Proved     developed     and
undeveloped reserves -

January 1, 2000               44,000    61,000

  Revisions of estimates  in  10,000    15,000
place
 Production                   (5,000)   (7,000)
                              --------  --------
                              --        --
December 31, 2000             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
                              ======    ======
Proved developed reserves -

December 31, 2000             49,000    69,000
                              ======    ======
December 31, 2001             25,000    31,000
                              ======    ======
December 31, 2002             23,000    26,000
                              ======    ======

     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, 2003.  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, 2003 are an average price  of
     $29.68 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, 2003 are an average price of $4.20 per Mcf.
<PAGE>
             Southwest Developmental Drilling Fund 91-A, L.P.
                     (a Delaware limited partnership)

                      Notes to Financial Statements

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

     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
     producing  and  proved developed non-producing.   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, 2002, 2001 and 2000 is
     presented below:

                                   2002      2001      2000
                                   ----      ----      ----

Future cash inflows           $  805,000   553,000   1,966,00
                                                     0
Production  and  development     428,000   395,000   1,129,00
costs                                                0
                                 --------  --------  --------
                                 ----      --        ----
Future net cash flows            377,000   158,000   837,000
10%   annual  discount   for
estimated
 timing of cash flows            103,000   37,000    275,000
                                 --------  --------  --------
                                 ----      --        ----
Standardized   measure    of
discounted
 future net cash flows        $  274,000   121,000   562,000
                                 =======   ======    =======

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

                      Notes to Financial Statements

7.   Estimated Oil & Gas Reserves (unaudited) - continued

     The  principal  sources  of  change in  the  standardized  measure  of
     discounted  future  net cash flows for the years  ended  December  31,
     2002, 2001 and 2000 are as follows:

                                   2002      2001      2000
                                   ----      ----      ----

Sales   of   oil   and   gas
produced,
 net of production costs      $  (44,000)  (66,000)  (84,000)
Changes   in   prices    and     174,000   (346,000  157,000
production costs                           )
Changes of production rates
 (timing) and others             (7,000)   16,000    (28,000)
Revisions of previous
 quantities estimates            18,000    (101,000  116,000
                                           )
Changes in estimated future
 development costs               -         -         15,000
Accretion of discount            12,000    56,000    35,000
Discounted future net
 cash flows -
Beginning of year                121,000   562,000   351,000
                                 --------  --------  --------
                                 --        --        --
End of year                   $  274,000   121,000   562,000
                                 ======    ======    ======

     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.

                                                Quarter
                                 --------------------------------------
                                                --------
                                  First     Second    Third     Fourth
                                  ------   -------    ------    ------
       2002:
       Total revenues         $  18,477    31,744    25,395    29,479
       Total expenses            20,343    21,068    19,650    28,092
       Net income (loss)         (1,866)   10,676    5,745     1,387
       Net   income   (loss)
       per limited
        partners unit             (1.64)                            .69
                                           7.92      4.18

       2001:
       Total revenues         $  55,540    23,594    32,635    27,517
       Total expenses            23,108    32,338    33,137    20,378
       Net income (loss)         32,432    (8,744)   (502)     7,139
       Net   income   (loss)
       per limited
        partners unit              24.74
                                           (7.18)    (1.06)    5.16

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

None


<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 serves for a
term of one year.

         Name               Age               Position
H. H. Wommack, III          47      Chairman   of   the    Board,
                                    President, Director
                                    and Chief Executive Officer
James N. Chapman(1)         40      Director
William P. Nicoletti(2)     57      Director
Joseph J. Radecki,  Jr.     44      Director
(2)
Richard D. Rinehart(1)      67      Director
John M. White(2)            46      Director
Herbert  C. Williamson,     54      Director
III(1)
Bill E. Coggin              48      Executive Vice President  and
                                    Chief Financial Officer
J. Steven Person            44      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.  Since 1997 Mr. Wommack has served as chairman of the
board  of  directors  of  Midland Red Oak Realty,  Inc.   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.  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 has been involved in the investment banking industry for 18  years,
presently  acting  as  a capital markets and strategic planning  consultant
with  private and public companies across a range of industries,  including
metals,  mining, manufacturing, aerospace, airline, service and healthcare.
Prior  to  establishing  an independent consulting  practice,  Mr.  Chapman
worked  for  The Renco Group, Inc., a multi-billion private corporation  in
New  York,  for  which Mr. Chapman developed and implemented financing  and
merger  and  acquisitions  strategies  for  Renco's  diverse  portfolio  of
companies.   Prior  to  Renco,  Mr. Chapman was  a  founding  principal  of
Fieldstone Private Capital Group, a capital markets advisory firm  that  he
joined  upon  its inception in August 1990.   Prior to joining  Fieldstone,
Mr.  Chapman worked for Bankers Trust Company for six years, most  recently
in  the  BT Securities Capital Markets area.  Mr. Chapman received  an  MBA
degree with distinction from the Amos Tuck School at Dartmouth College  and
was  elected  an  Edward Tuck Scholar.   He received  his  BA  degree  with
distinction magna cum laude, at Dartmouth College, was elected to Phi  Beta
Kappa and was a Rufus Choate Scholar.

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 was formerly a senior officer  and
head  of  the  Energy Investment Banking Groups of E. F. Hutton  &  Company
Inc.,  Paine  Webber,  Incorporated  and  McDonald  Investments  Inc.   Mr.
Nicoletti  is  Chairman  of  the  board  of  directors  of  Russell-Stanley
Holdings, Inc., a manufacturer and marketer of steel and plastic industrial
containers.  He is a director of Mark WestEnergy Partners, L.P., a business
engaged   in  the  gathering  and  processing  of  natural  gas   and   the
fractionation and storage of natural gas liquids.  Mr. Nicoletti is also  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.  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, Mr. Radecki was an Executive Vice President
and  Director of the Financial Restructuring Group of Jefferies &  Company,
Inc.  from 1990 to 1998.  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
Wherehouse  Entertainment, Inc., a music and video specialty retailer,  and
RBX  Corporation,  a  manufacturer of rubber and  plastic  foam  and  other
polymer  products.  He has previously served 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 M. White has served as a director since April 19, 2002.  Mr. White  is
currently  an  oil and gas analyst with BMO Nesbitt Burns, responsible  for
Fixed  Income research on oil, gas and energy companies.  Prior to  joining
BMO  Nesbitt  Burns  in 1998, Mr. White was responsible  for  Fixed  Income
research  on  the  oil  and  gas  industry at  John  S.  Herold,  Inc.,  an
independent  oil  and  gas  research  and  consulting  firm.   Mr.  White's
experience also includes managing a portfolio of oil and gas loans for  The
Bank  of Nova Scotia, which included independent exploration and production
companies,  oil  service  companies,  gas  pipelines,  gas  processors  and
refiners.   Prior  to entering banking, Mr. White was with BP  Exploration,
where he worked primarily in exploration and production.

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

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

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

<PAGE>
Key Employees

Jon  P.  Tate,  age  45, has served as Vice President, Land  and  Assistant
Secretary  of the Managing General Partner since 1989. From 1981  to  1989,
Mr.  Tate  was employed by C.F. Lawrence & Associates, Inc., an independent
oil  and  gas company, as land manager. Mr. Tate is a member of the Permian
Basin Landman's Association.

R.  Douglas  Keathley, age 47, 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.

Item 11.  Executive Compensation

The  Partnership  does not have any directors or executive  officers.   The
executive officers of the Managing General Partner do not receive any  cash
compensation,  bonuses, deferred compensation or compensation  pursuant  to
any  type  of  plan,  from the Partnership.  The Managing  General  Partner
received $10,800 during 2002, 2001 and 2000 as an annual administrative fee
for reimbursement of indirect general and administrative costs.

Item 12.  Security Ownership of Certain Beneficial Owners and Management

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  22.0  limited partner units, or 1.7% limited partner  interest.   The
Managing  General  Partner  total  percentage  interest  ownership  in  the
Partnership is 12.7%.

No  officer or director of the Managing General Partner 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 March 1, 2003. A list of beneficial owners of limited partner units,
acquired by 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        1.7%
Interest               Inc.                      Owns
                       Managing      General     22.0 Units
                       Partner
                       407   N.  Big  Spring
                       Street
                       Midland, TX 79701

Limited Partnership    H. H. Wommack, III        Indirectly      1.7%
Interest                                         Owns
                       Chairman    of    the     22.0 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 2002, the Managing General Partner received $10,800 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 $12,100 for administrative  overhead
attributable to operating such properties during 2002.

Certain  subsidiaries or affiliates of the Managing General Partner perform
various  oilfield services for properties in which the Partnership owns  an
interest.   Such services aggregated approximately $700 for the year  ended
December 31, 2002.

In  the  opinion  of  management, the terms of the above  transactions  are
similar to ones with unaffiliated third parties.

<PAGE>
                                 Part IV


Item 14.  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.)

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

          (b)     Reports on Form 8-K

                  There  were  no  reports filed on  Form  8-K  during  the
              quarter ended December 31, 2002.

<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:  March 28, 2003


Pursuant  to the requirements of the Securities Exchange Act of 1934,  this
report  has  been signed below by the following persons on  behalf  of  the
Partnership and in the capacities and on the dates indicated.

By:/s/ H. H. Wommack, III                    By:    /s/   James    N.
                                             Chapman
---------------------------                  ------------------------
--------------------                         -----------------------
H.    H.   Wommack,    III,                  James     N.    Chapman,
Chairman of the Board,                       Director
President,   Director   and
Chief Executive Officer

Date:     March 28, 2003                     Date:     March 28, 2003


By:     /s/   William    P.                  By:    /s/   Joseph   J.
Nicoletti                                    Radecki, Jr.
---------------------------                  ------------------------
--------------------                         -----------------------
William    P.    Nicoletti,                  Joseph J. Radecki,  Jr.,
Director                                     Director

Date:     March 28, 2003                     Date:     March 28, 2003


By:     /s/   Richard    D.                  By:  /s/ John M. White
Rinehart
---------------------------                  ------------------------
--------------------                         -----------------------
Richard     D.    Rinehart,                  John M. White, Director
Director

Date:     March 28, 2003                     Date:     March 28, 2003


By:     /s/   Herbert    C.
Williamson, III
---------------------------
--------------------
Herbert C. Williamson, III,
Director

Date:     March 28, 2003


<PAGE>
                         CERTIFICATIONS

          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 annual 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  annual
report;

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

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

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

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

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

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

               a)   all significant deficiencies in the design or operation of
               internal controls which could adversely affect the registrant's
               ability to record, process, summarize and report financial data
               and have identified for the registrant's auditors any material
               weaknesses in internal controls; and

               b)   any fraud, whether or not material, that involves management
               or other employees who have a significant role in the
               registrant's internal controls; and

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

Date:  March 28, 2003

/s/ H.H. Wommack, III
H. H. Wommack, III
Chairman, President and Chief Executive Officer
  of Southwest Royalties, Inc., the
  Managing General Partner of
  Southwest Developmental Drilling Fund 91-A, L.P.
<PAGE>
                         CERTIFICATIONS

          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 annual 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 annual
report;

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

          4.   The registrant's other certifying officers and I are
responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-14 and 15d-
14) for the registrant and we have:
               a)   designed such disclosure controls and procedures to ensure
               that material information relating to the registrant, including
               its consolidated subsidiaries, is made known to us by others
               within those entities, particularly during the period in which
               this annual report is being prepared;

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

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

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

               a)   all significant deficiencies in the design or operation of
               internal controls which could adversely affect the registrant's
               ability to record, process, summarize and report financial data
               and have identified for the registrant's auditors any material
               weaknesses in internal controls; and

               b)   any fraud, whether or not material, that involves management
               or other employees who have a significant role in the
               registrant's internal controls; and

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

Date:  March 28, 2003

/s/ Bill E. Coggin
Bill E. Coggin
Executive Vice President
  and Chief Financial Officer of
  Southwest Royalties, Inc., the
  Managing General Partner of
  Southwest Developmental Drilling Fund 91-A, L.P.
<PAGE>

                          Exhibit Index


Item No.     Description                                           Page No.

             Exhibit 99.1 Certification pursuant to 18 U.S.C.       39
             Section 1350, as adopted pursuant to Section 906
             of the Sarbanes-Oxley Act of 2002

             Exhibit 99.2 Certification pursuant to 18 U.S.C.       40
             Section 1350, as adopted pursuant to Section 906
             of the Sarbanes-Oxley Act of 2002

<PAGE>
                    CERTIFICATION PURSUANT TO
                     19 U.S.C. SECTION 1350,
                     AS ADOPTED PURSUANT TO
          SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002


       In   connection  with  the  Annual  Report  of   Southwest
Developmental  Drilling  Fund  91-A,  Limited  Partnership   (the
"Company") on Form 10-K for the period ending December  31,  2002
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:  March 28, 2003




/s/ H.H. Wommack, III
H. H. Wommack, III
Chairman, President, Director and Chief Executive Officer
  of Southwest Royalties, Inc., the
  Managing General Partner of
  Southwest Developmental Drilling Fund 91-A, L.P.

<PAGE>
                    CERTIFICATION PURSUANT TO
                     19 U.S.C. SECTION 1350,
                     AS ADOPTED PURSUANT TO
          SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002


  In connection with the Annual Report of Southwest Developmental
Drilling Fund 91-A, Limited Partnership (the "Company")  on  Form
10-K  for  the period ending December 31, 2002 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:

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

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


Date:  March 28, 2003




/s/ Bill E. Coggin
Bill E. Coggin
Executive Vice President
  and Chief Financial Officer of
  Southwest Royalties, Inc., the
  Managing General Partner of
  Southwest Developmental Drilling Fund 91-A, L.P.


<PAGE>