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 [Fee Required]

For the fiscal year ended December 31, 2001

                                    OR

[ ]    Transition  report pursuant to Section 13 or 15(d) of the Securities
       Exchange Act of 1934 [No Fee Required]

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 39.   There  is  no
exhibit index.

<PAGE>
                            Table of Contents

Item                                                                   Page

                                  Part I

 1.  Business                                                            3

 2.  Properties                                                          5

 3.  Legal Proceedings                                                   7

 4.  Submission of Matters to a Vote of Security Holders                 7

                                 Part II

 5.  Market for Registrant's Common Equity and Related
     Stockholder Matters                                                 8

 6.  Selected Financial Data                                             9

 7.  Management's Discussion and Analysis of
     Financial Condition and Results of Operations                      10

 8.  Financial Statements and Supplementary Data                        18

 9.  Changes in and Disagreements with Accountants
     on Accounting and Financial Disclosure                             33

                                 Part III

10.  Directors and Executive Officers of the Registrant                 34

11.  Executive Compensation                                             35

12.  Security Ownership of Certain Beneficial Owners and
     Management                                                         35

13.  Certain Relationships and Related Transactions                     37

                                 Part IV

14.  Exhibits, Financial Statement Schedules, and Reports
     on Form 8-K                                                        38

     Signatures                                                         39

<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  89  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>
For  nearly nine months, despite the fears of a global recession, crude oil
prices  held steady between $26 and $28 per barrel due in part to a  series
of  OPEC  and  non-OPEC production cuts.  Then, following what  has  become
known  simply  as  "9-11",  crude prices plunged  immediately  to  $22  and
gradually  fell  to below $18 per barrel.  Slower demand  across  the  U.S.
caused by the threat of recession and warmer than expected weather also led
to  declining prices in the latter half of 2001.  However, the  oil  cartel
and other non-member countries agreed for the fourth time since February to
curb  output in an effort to stabilize prices.  Crude oil contracts trading
on the NYMEX closed the year at approximately $20 per barrel.

Spot  prices in 2001 climbed to their highest levels ever, with the  yearly
average  price  nationwide reaching $4.14/MMBtu, up  9.77%  from  the  2000
average  of $3.77/MMBtu.  Prices reached their zenith in the first  quarter
of  2001 before beginning a steady decline throughout the remainder of  the
year.   The  terrorist  attacks  of  September  11  knocked  the  New  York
Mercantile Exchange out of the market for several days and shook  the  spot
marketplace into a maintenance mode.  As companies measured the  impact  of
the  attacks on the U.S. economy, spot prices deteriorated further.  In the
fourth  quarter,  prices  bottomed out for the year  with  the  three-month
average  falling to $2.31/MMBtu.  As for 2002, record-high  storage  levels
and  the  expectation of a flat economy through the first half of the  year
are  leading  industry  experts to predict prices to  average  $2.05/MMBtu,
remaining above the $2.00 per MMBtu level for a 5th consecutive year.

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

                                  Oil          Gas

                    2001          82%          18%
                    2000          85%          15%
                    1999          86%          14%

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.  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%.  Two purchasers accounted for 85% of the Partnership's
total oil and gas production during 1999: Navajo Refining Company, Inc. for
52%   and  Scurlock  Permian  LLC  for  33%.     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,
2001  there  were 89 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.

<PAGE>
As  of December 31, 2001, 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 has not been any
significant changes in properties during 2001, 2000 and 1999.

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

                        Date
                     Purchased        No. of           Proved Reserves*
Name and Location   and Interest      Wells        Oil (bbls)    Gas (mcf)
-----------------   ------------      -----        ----------    ---------
Carson F #1           6/92                1         23,000         25,000
Ward County,          89%
Texas                 working
                      interest

*Ryder  Scott  Petroleum Engineers prepared the reserve and  present  value
data for the Partnership's existing properties as of January 1, 2002.   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, 2002 are an average price of $18.98 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, 2002 are  an
average price of $2.28 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 2001.

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

<PAGE>
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 2001 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.   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.  In 1999, 5 limited partner units were  tendered
to  and purchased by the Managing General Partner at an average base  price
of $78.06 per unit.

Number of Limited and General Partner Interest Holders
As  of  December 31, 2001, 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  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.  During 1999,  distributions
were  made  totaling  $85,000,  with $75,650 distributed  to  the  investor
partners  and $9,350 to the Managing General Partner.  For the  year  ended
December  31, 1999, distributions of $66.10 per investor partner unit  were
made, based upon 1,144.5 investor partner units outstanding.

<PAGE>
Item 6.   Selected Financial Data

The  following  selected financial data for the years  ended  December  31,
2001,  2000,  1999,  1998 and 1997 should be read in conjunction  with  the
financial statements included in Item 8:

                                    Years ended December 31,
                     -----------------------------------------------------
                                                        Restated
                        2001        2000      1999        1998      1997
                        ----        ----      ----        ----      ----
Revenues            $  139,286    162,884    252,026    172,847   307,526

Net income (loss)       30,325     58,242    119,990    (3,178)   126,704

Partners' share of
 net income (loss):

  Managing General
   Partner               5,536      7,617     17,159      5,480    20,529

  Investor partners     24,789     50,625    102,831    (8,658)   106,175

Investor partners'
 net income (loss)
  per unit               21.66      44.23      89.85     (7.57)     92.77

Investor partners'
 cash distributions
  per unit               48.39      94.12      66.10      31.49    225.51

Total assets        $  133,225    165,095    237,888    195,528   236,923

<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 2002 to enhance production.  The partnership will most likely
experience the historical production decline of approximately 8% 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.

<PAGE>
The Partnership's policy for depreciation, depletion and amortization of
oil and gas properties is computed under the units of revenue method.
Under the units of revenue method, depreciation, depletion and amortization
is computed on the basis of current gross revenues from production in
relation to future gross revenues, based on current prices, from estimated
production of proved oil and gas reserves.

A.  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
                                                 December 31,    Percentage
                                                                  Increase
                                                2001      2000   (Decrease)
                                                ----      ----   ---------

Average price per barrel of oil            $   25.84    29.88    (14%)
Average price per mcf of gas               $    4.41     3.82      15%
Oil production in barrels                      4,440    4,600     (3%)
Gas production in mcf                          5,540    6,600    (16%)
Gross oil and gas revenue                  $ 139,132  162,628    (14%)
Net oil and gas revenue                    $  65,516   83,755    (22%)
Partnership distributions                  $  62,234  121,035    (49%)
Limited partner distributions              $  55,388  107,721    (49%)
Per unit distribution to limited partners  $   48.39    94.12    (49%)
Number of limited partner units              1,144.5  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  to  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>
B.  General Comparison of the Years Ended December 31, 2000 and 1999

The  following  table  provides certain information  regarding  performance
factors for the years ended December 31, 2000 and 1999:

                                                  Year Ended
                                                 December 31,    Percentage
                                                                  Increase
                                                2000      1999   (Decrease)
                                                ----      ----   ---------

Average price per barrel of oil            $   29.88    16.88      77%
Average price per mcf of gas               $    3.82     1.81     111%
Oil production in barrels                      4,600   12,800    (64%)
Gas production in mcf                          6,600   19,540    (66%)
Gross oil and gas revenue                  $ 162,628  251,484    (35%)
Net oil and gas revenue                    $  83,755  171,878    (51%)
Partnership distributions                  $ 121,035   85,000      42%
Limited partner distributions              $ 107,721   75,650      42%
Per unit distribution to limited partners  $   94.12    66.10      42%
Number of limited partner units              1,144.5  1,144.5

Revenues

The  Partnership's oil and gas revenues decreased to $162,628 from $251,484
for the years ended December 31, 2000 and 1999, respectively, a decrease of
35%.   The  principal factors affecting the comparison of the  years  ended
December 31, 2000 and 1999 are as follows:

1.  The  average  price  for a barrel of oil received  by  the  Partnership
    increased  during the year ended December 31, 2000 as compared  to  the
    year ended December 31, 1999 by 77%, or $13.00 per barrel, resulting in
    an increase of approximately $59,800 in revenues. Oil sales represented
    %85  of total oil and gas sales during the year ended December 31, 2000
    as compared to 86% during the year ended December 31, 1999.

    The  average  price  for  an  mcf of gas received  by  the  Partnership
    increased  during the same period by 111%, or $2.01 per mcf,  resulting
    in an increase of approximately $13,300 in revenues.

    The  total  increase in revenues due to the change in  prices  received
    from oil and gas production is approximately $73,100.  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 8,200 barrels or 64% during the
   year ended December 31, 2000 as compared to the year ended December  31,
   1999, resulting in a decrease of approximately $138,400 in revenues.

    Gas  production  decreased approximately 12,940 mcf or 66%  during  the
    same  period,  resulting  in  a decrease of  approximately  $23,400  in
    revenues.

    The  total  decrease  in revenues due to the change  in  production  is
    approximately  $161,800.  The sharp decrease in oil and gas  production
    is  in  relation to a settlement of royalty on the Dagger  Draw  Lease.
    Production  interest of approximately 5,000 bbls and  7,230  mcfs  were
    held  in  suspense from 1993 through 1999.  These dollars were received
    and  recorded  in  the Partnership during the third  quarter  of  1999.
    Production  without the settlement would be a decrease of 25%  for  oil
    and 29% for gas.  This decrease was due to the occurrence of payout  on
    the Dagger Draw.  Upon occurrence of payout the percentage of ownership
    for the Partnership decrease significantly.

Costs and Expenses

Total  costs and expenses decreased to $104,642 from $132,036 for the years
ended  December 31, 2000 and 1999, respectively, a decrease  of  21%.   The
decrease  is  the result of lower lease operating costs, depletion  expense
and general and administrative costs.

2.    Lease  operating  costs  and  production  taxes  were  1%  lower,  or
   approximately $700 less during the year ended December 31, 2000 as compared
   to the year ended December 31, 1999.

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  decreased
    10% or approximately $1,700 during the year ended December 31, 2000  as
    compared to the year ended December 31, 1999.

3.  Depletion expense decreased to $11,000 for the year ended December  31,
    2000  from  $36,000  for the same period in 2000.   This  represents  a
    decrease  of 69%.  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  to  the  decline in depletion  expense  between  the
   comparative periods was the increase in oil and gas prices of  the  2001
   reserves 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 $4,000 as of December 31, 1999.

<PAGE>
C.  Revenue and Distribution Comparison

Partnership net income for the years ended December 31, 2001, 2000 and 1999
was $30,325, $58,242 and $119,990, respectively.  Excluding the effects  of
depreciation,  depletion and amortization, net income for the  years  ended
December  31,  2001,  2000  and  1999 was $50,325,  $69,242  and  $155,990,
respectively.   Correspondingly, Partnership distributions  for  the  years
ended  December 31, 2001, 2000 and 1999 were $62,234, $121,035 and $85,000,
respectively.

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.  The sources for the 1999 distributions of $85,000 were oil and gas
operations  of  approximately  $134,600 and  the  change  in  oil  and  gas
properties   of  approximately  $(900),  resulting  in  excess   cash   for
contingencies or subsequent distributions.

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.
Total distributions during the year ended December 31, 1999 were $85,000 of
which  $75,650 was distributed to the investor partners and $9,350  to  the
Managing  General Partner.  The per unit distribution to investor  partners
during the same period was $66.10.

Since  inception of the Partnership, cumulative monthly cash  distributions
of  $1,396,009  have been made to the partners.  As of December  31,  2001,
$1,244,359 or $1,087.25 per investor partner unit, has been distributed  to
the   investor  partners,  representing  a  109%  return  of  the   capital
contributed.

<PAGE>
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 $60,400  in
2001  compared to $78,700 in 2000 and approximately $134,600 in 1999.   The
primary  source  of  the  2001  cash flow  from  operating  activities  was
profitable operations.

Cash  flows  used in investing activities were approximately $200  in  2001
compared to $200 in 2000 and approximately $900 in 1999. The principal  use
of  the  2001 cash flow from investing activities was additions to oil  and
gas properties.

Cash  flows used in financing activities were approximately $62,200 in 2001
compared  to $120,400 in 2000 and approximately $88,200 in 1999.  The  only
use in the 2001 financing activities was the distributions to partners.

As  of  December  31,  2001, the Partnership had approximately  $14,400  in
working  capital.   The  Managing  General  Partner  knows  of  no  unusual
contractual commitments and believes the revenue generated from  operations
are adequate to meet the needs of the Partnership.

Liquidity - Managing General Partner

The  Managing General Partner has a highly leveraged capital structure with
$50.0  million and $123.7 million of principal due in August  of  2003  and
October  of  2004, respectively.  The Managing General Partner  will  incur
approximately  $17.6  million in interest payments  in  2002  on  its  debt
obligations. Due to the depressed commodity prices experienced  during  the
last  quarter  of  2001,  the  Managing  General  Partner  is  experiencing
difficulty  in generating sufficient cash flow to meet its obligations  and
sustain its operations.  The Managing General Partner is currently  in  the
process  of  renegotiating the terms of its various  obligations  with  its
creditors  and/or  attempting  to seek new  lenders  or  equity  investors.
Additionally,  the  Managing General Partner would  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 lenders will agree  to
a   course   of  action  consistent  with  the  Managing  General  Partners
requirements  in restructuring the obligations.  Even if such agreement  is
reached,  it  may  require approval of additional  lenders,  which  is  not
assured.   Furthermore, there can be no assurance that the sales of  assets
can  be  successfully  accomplished on terms  acceptable  to  the  Managing
General   Partner.   Under  current  circumstances,  the  Managing  General
Partner's  ability to continue as a going concern depends upon its  ability
to  (1)  successfully  restructure  its obligations  or  obtain  additional
financing  as  may  be  required, (2) maintain  compliance  with  all  debt
covenants, (3) generate sufficient cash flow to meet its obligations  on  a
timely  basis, and (4) achieve satisfactory levels of future earnings.   If
the  Managing  General Partner is unsuccessful in its efforts,  it  may  be
unable to meet its obligations making it necessary to undertake such  other
actions  as  may  be  appropriate  to  preserve  asset  values.   Upon  the
occurrence of any event of dissolution by the Managing General Partner, the
holders  of  a  majority of limited partnership interests may,  by  written
agreement,  elect  to  continue the business  of  the  Partnership  in  the
Partnership's   name,  with  Partnership  property,  in   a   reconstituted
partnership under the terms of the partnership agreement and to designate a
successor Managing General Partner.

<PAGE>
Recent Accounting Pronouncements

In  June  1998,  the Financial Accounting Standards Board  ("FASB")  issued
Statement  of  Financial Accounting Standards ("SFAS") No.133,  "Accounting
for  Derivative  Instruments and Hedging Activities."   SFAS  No.  133,  as
amended by SFAS No. 138, establishes accounting and reporting standards for
derivative  instruments, including certain derivative instruments  embedded
in  other contracts and for hedging activities.  Assessment by the Managing
General  Partner  revealed this pronouncement to  have  no  impact  on  the
partnerships.

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.

On  October 3, 2001, the FASB issued Statements No. 144 "Accounting for the
Impairment   or   Disposal  of  Long-Lived  Assets."   This   pronouncement
supercedes FAS 121 "Accounting for the Impairment of Long-Lived Assets  and
for  Long-Lived  Assets to Be Disposed" and eliminates the  requirement  of
Statement  121 to allocate goodwill to long-lived assets to be  tested  for
impairment.   The provisions of this statement are effective for  financial
statements issued for fiscal years beginning after December 15,  2001,  and
interim periods within those fiscal years.  The Managing General Partner is
currently assessing the impact to 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                                             18

Balance Sheets                                                          19

Statements of Operations                                                20

Statement of Changes in Partners' Equity                                21

Statements of Cash Flows                                                22

Notes to Financial Statements                                           24

<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,  2001  and
2000, 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,  2001.  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, 2001 and 2000 and the  results
of  its  operations and its cash flows for each of the years in  the  three
year   period  ended  December  31,  2001  in  conformity  with  accounting
principles generally accepted in the United States of America.








                                                  KPMG LLP



Midland, Texas
March 10, 2002

<PAGE>

             Southwest Developmental Drilling Fund 91-A, L.P.
                     (a Delaware limited partnership)
                              Balance Sheets
                        December 31, 2001 and 2000


2001                                                  2000
                                                      ----          ----

  Assets
  ------

Current assets:
 Cash and cash equivalents                   $        12,402       14,338
 Receivable from Managing General Partner              2,047       12,165

---------                                    ---------
                                                 Total    current    assets
14,449                                       26,503

---------                                    ---------
Oil and gas properties - using the full-
 cost method of accounting                         1,098,776    1,098,592
  Less accumulated depreciation,
                                               depletion  and  amortization
980,000                                      960,000

---------                                    ---------
                                              Net  oil  and gas  properties
118,776                                      138,592

---------                                    ---------
                                                                          $
133,225                                      165,095

=========                                    =========
  Liabilities and Partners' Equity
  --------------------------------

Current liabilities:
 Distribution payable                        $            39            -

---------                                    ---------
Partners' equity:

 Managing General Partner                             22,513       23,823
 Investor partners                                   110,673      141,272

---------                                    ---------
                                                Total    partners'   equity
133,186                                      165,095

---------                                    ---------
                                                                          $
133,225                                      165,095

=========                                    =========
















                  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, 2001, 2000 and 1999



                                                 2001      2000      1999
                                                 ----      ----      ----

  Revenues
  --------

Oil and gas sales                         $    139,132   162,628  251,484
Interest income from operations                    154       256      542
                                                                    -------
-------                                   -------
                                                                    139,286
162,884                                   252,026
                                                                    -------
-------                                   -------
  Expenses
  --------

Production                                      73,616    78,873   79,606
General and administrative                      15,345    14,769   16,430
Depreciation, depletion and amortization        20,000    11,000   36,000
                                                                    -------
-------                                   -------
                                                                    108,961
104,642                                   132,036
                                                                    -------
-------                                   -------
Net income                                $     30,325    58,242  119,990
                                                                    =======
=======                                   =======
Net income allocated to:

 Managing General Partner                 $      5,536     7,617   17,159
                                                                    =======
=======                                   =======
 Investor partners                        $     24,789    50,625  102,831
                                                                    =======
=======                                   =======
  Per investor partner unit               $      21.66     44.23    89.85
                                                                    =======
=======                                   =======
























                  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, 2001, 2000 and 1999


                                               Managing
                                               General   Investor
                                               Partner   Partners   Total
                                               -------   --------   -----
Balance at December 31, 1998              $     21,711   171,187  192,898

 Net income                                     17,159   102,831  119,990

 Distributions                                 (9,350)  (75,650) (85,000)
                                                                    -------
--------                                  --------
Balance at December 31, 1999                    29,520   198,368  227,888

 Net income                                      7,617    50,625   58,242

 Distributions                                (13,314) (107,721)(121,035)
                                                                    -------
--------                                  --------
Balance at December 31, 2000                    23,823   141,272  165,095

 Net income                                      5,536    24,789   30,325

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































                  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, 2001, 2000 and 1999



                                                 2001      2000      1999
                                                 ----      ----      ----

Cash flows from operating activities:

 Cash received from oil and gas sales     $    152,656   166,419  235,741
 Cash paid to Managing General Partner
  for administrative fees and general
                                            and   administrative   overhead
(92,367)                                  (87,964)(101,686)
 Interest received                                 154       256      542
                                                                   --------
--------                                  --------
   Net  cash provided by operating activities               60,443   78,711
134,597
                                                                   --------
--------                                  --------
Cash flows used in investing activities:

 Additions to oil and gas properties             (184)     (151)    (873)
                                                                   --------
--------                                  --------
Cash flows used in financing activities:

 Distributions to partners                    (62,195) (120,418) (88,247)
                                                                   --------
--------                                  --------
Net (decrease) increase in cash and cash
 equivalents                                   (1,936)  (41,858)   45,477

 Beginning of period                            14,338    56,196   10,719
                                                                   --------
--------                                  --------
 End of period                            $     12,402    14,338   56,196
                                                                   ========
========                                  ========


(continued)
























                  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, continued
               Years ended December 31, 2001, 2000 and 1999



                                                 2001      2000      1999
                                                 ----      ----      ----

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

Net income                                $     30,325    58,242  119,990

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

   Depreciation, depletion and amortization                20,000    11,000
36,000
  Decrease (increase) in receivables            13,524     3,791 (15,743)
  (Decrease) increase in payables              (3,406)     5,678  (5,650)
                                                                    -------
-------                                   -------
Net cash provided by operating activities $     60,443    78,711  134,597
                                                                    =======
=======                                   =======





































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

     The  Partnership's policy for depreciation, depletion and amortization
     of  oil  and  gas  properties is computed under the units  of  revenue
     method.   Under  the units of revenue method, depreciation,  depletion
     and  amortization is computed on the basis of current  gross  revenues
     from production in relation to future gross revenues, based on current
     prices, from estimated production of proved oil and gas reserves.

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

                      Notes to Financial Statements

2.   Summary of Significant Accounting Policies - continued

     Oil and Gas Properties - continued
     Under  the  units  of  revenue method, the  Partnership  computes  the
     provision  by multiplying the total unamortized cost of  oil  and  gas
     properties by an overall rate determined by dividing (a) oil  and  gas
     revenues during the period by (b) the total future gross oil  and  gas
     revenues  as  estimated  by  the Partnership's  independent  petroleum
     consultants.   It  is  reasonably possible  that  those  estimates  of
     anticipated  future  gross revenues, the remaining estimated  economic
     life  of  the product, or both could be changed significantly  in  the
     near  term  due to the potential fluctuation of oil and gas prices  or
     production.   The  depletion estimate would also be affected  by  this
     change.

     Should the net capitalized costs exceed the estimated present value of
     oil  and  gas reserves, discounted at 10%, such excess costs would  be
     charged  to current expense.  As of December 31, 2001, 2000  and  1999
     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.

     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,  2001,  2000  and
     1999, there were no significant amounts of imbalance in terms of units
     and 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,  2001  and 2000 is $113,822 and $130,818, 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, 2001, 2000 and 1999, there were 1,144.5  investor
     partner units outstanding held by 102, 103 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
     In June 1998, the Financial Accounting Standards Board ("FASB") issued
     Statement   of   Financial  Accounting  Standards   ("SFAS")   No.133,
     "Accounting for Derivative Instruments and Hedging Activities."   SFAS
     No.  133,  as  amended  by  SFAS No. 138, establishes  accounting  and
     reporting  standards  for  derivative instruments,  including  certain
     derivative  instruments embedded in other contracts  and  for  hedging
     activities.  Assessment by the Managing General Partner revealed  this
     pronouncement to have no impact on the partnerships.

     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.

     On October 3, 2001, the FASB issued Statements No. 144 "Accounting for
     the  Impairment or Disposal of Long-Lived Assets."  This pronouncement
     supercedes FAS 121 "Accounting for the Impairment of Long-Lived Assets
     and   for  Long-Lived  Assets  to  Be  Disposed"  and  eliminates  the
     requirement of Statement 121 to allocate goodwill to long-lived assets
     to  be  tested  for impairment.  The provisions of this statement  are
     effective  for financial statements issued for fiscal years  beginning
     after  December  15,  2001, and interim periods  within  those  fiscal
     years.  The Managing General Partner is currently assessing the impact
     to 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  $50.0 million and $123.7 million of principal due in  August  of
     2003  and October of 2004, respectively.  The Managing General Partner
     will incur approximately $17.6 million in interest payments in 2002 on
     its   debt   obligations.  Due  to  the  depressed  commodity   prices
     experienced  during  the last quarter of 2001,  the  Managing  General
     Partner is experiencing difficulty in generating sufficient cash  flow
     to  meet  its  obligations and sustain its operations.   The  Managing
     General Partner is currently in the process of renegotiating the terms
     of  its  various obligations with its creditors and/or  attempting  to
     seek  new  lenders  or equity investors.  Additionally,  the  Managing
     General Partner would 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  lenders  will
     agree  to  a  course  of action consistent with the  Managing  General
     Partners requirements in restructuring the obligations.  Even if  such
     agreement  is reached, it may require approval of additional  lenders,
     which is not assured.  Furthermore, there can be no assurance that the
     sales  of  assets can be successfully accomplished on terms acceptable
     to  the  Managing  General Partner.  Under current circumstances,  the
     Managing  General  Partner's ability to continue as  a  going  concern
     depends   upon  its  ability  to  (1)  successfully  restructure   its
     obligations  or  obtain additional financing as may be  required,  (2)
     maintain  compliance with all debt covenants, (3) generate  sufficient
     cash  flow to meet its obligations on a timely basis, and (4)  achieve
     satisfactory  levels  of  future earnings.  If  the  Managing  General
     Partner  is unsuccessful in its efforts, it may be unable to meet  its
     obligations making it necessary to undertake such other actions as may
     be  appropriate to preserve asset values.  Upon the occurrence of  any
     event of dissolution by the Managing General Partner, the holders of a
     majority  of limited partnership interests may, by written  agreement,
     elect to continue the business of the Partnership in the Partnership's
     name,  with Partnership property, in a reconstituted partnership under
     the  terms  of the partnership agreement and to designate a  successor
     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.

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

                      Notes to Financial Statements

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

     As  of December 31, 2001, 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.

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  $11,800,
     $11,400  and $13,000 for the years ended December 31, 2001,  2000  and
     1999,  respectively.   In addition, the Managing General  Partner  and
     certain  officers and employees may have an interest in  some  of  the
     properties that the Partnership also participates.

     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
     $1,100, $4,300 and $7,300 for the years ended December 31, 2001,  2000
     and 1999, respectively.

     Southwest  Royalties,  Inc., the Managing General  Partner,  was  paid
     $10,800 in 2001 and 2000 and $11,000 in 1999 for indirect general  and
     administrative overhead expenses.

     Receivables  from  Southwest  Royalties, Inc.,  the  Managing  General
     Partner,  of  approximately $2,000 and $12,200 are from  oil  and  gas
     production, net of lease operating costs and production taxes,  as  of
     December 31, 2001 and 2000, respectively.

     In addition, a director and officer of the Managing General Partner is
     a partner in a law firm, with such firm providing legal services.  The
     Partnership  had  no legal services for the years ended  December  31,
     2001, 2000 and 1999, respectively.

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

                      Notes to Financial Statements

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.   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%.   Two
     purchasers  accounted for 85% of the Partnership's total oil  and  gas
     production  during 1999: Navajo Refining Company,  Inc.  for  52%  and
     Scurlock  Permian LLC for 33%.    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.

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

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

     January 1, 1999                                  46,000       68,000

       Revisions of estimates in place                11,000       13,000
       Production                                   (13,000)     (20,000)
                                                     -------      -------
     December 31, 1999                                44,000       61,000

       Revisions of estimates in place                10,000       15,000
       Production                                    (5,000)      (7,000)
                                                     -------      -------
     December 31, 2000                                49,000       69,000

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

     December 31, 1999                                44,000       61,000
                                                     =======      =======
     December 31, 2000                                49,000       69,000
                                                     =======      =======
     December 31, 2001                                25,000       31,000
                                                     =======      =======

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

     *Ryder  Scott  Petroleum Engineers prepared the  reserve  and  present
     value data for the Partnership's existing properties as of January  1,
     2002.   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.

<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
     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, 2002 are an average price  of
     $18.98 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, 2002 are an average price of $2.28 per Mcf.

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

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

<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  standardized measure of discounted future net cash flows relating
     to  proved oil and gas reserves at December 31, 2001, 2000 and 1999 is
     presented below:

                                               2001       2000      1999
                                               ----       ----      ----

     Future cash inflows                $    553,000  1,966,000 1,179,000
     Production and development costs        395,000  1,129,000   686,000
                                           ---------  --------- ---------
     Future net cash flows                   158,000    837,000   493,000
     10% annual discount for estimated
       timing of cash flows                   37,000    275,000   142,000
                                           ---------  --------- ---------
     Standardized measure of discounted
       future net cash flows            $    121,000    562,000   351,000
                                           =========  ========= =========

     The  principal  sources  of  change in  the  standardized  measure  of
     discounted  future  net cash flows for the years  ended  December  31,
     2001, 2000 and 1999 are as follows:

                                               2001       2000      1999
                                               ----       ----      ----

     Sales of oil and gas produced,
       net of production costs          $   (66,000)   (84,000) (172,000)
      Changes in prices and production costs           (346,000)    157,000
167,000
     Changes of production rates
       (timing) and others                    16,000   (28,000)  (20,000)
     Revisions of previous
       quantities estimates                (101,000)    116,000    89,000
     Changes in estimated future
       development costs                           -     15,000  (16,000)
     Accretion of discount                    56,000     35,000    28,000
     Discounted future net
       cash flows -
      Beginning of year                      562,000    351,000   275,000
                                           ---------   -------- ---------
      End of year                       $    121,000    562,000   351,000
                                           =========   ======== =========

     Future  net cash flows were computed using year-end prices  and  costs
     that  related  to existing proved oil and gas reserves  in  which  the
     Partnership has mineral interests.
<PAGE>
             Southwest Developmental Drilling Fund 91-A, L.P.
                     (a Delaware limited partnership)

                      Notes to Financial Statements

8.  Selected Quarterly Financial Results - (unaudited)

                                                 Quarter
                              ----------------------------------------------
                                 First       Second    Third       Fourth
                                 ------     -------    ------      ------
  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

  2000:
     Total revenues           $   36,095     43,158    50,190      33,441
     Total expenses               27,399     23,166    26,858      27,219
     Net income                    8,696     19,992    23,332       6,222
     Net income per limited
      partners unit                 6.38      15.35     17.76        4.74

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.  The present directors of the Managing General  Partner
have served in their capacity since the Company's formation in 1983.

     Name                   Age                      Position
--------------------        ---         -----------------------------------
-------
H. H. Wommack, III                      46     Chairman   of   the   Board,
                                        President,
                                        Chief Executive Officer, Treasurer
                                        and Director

H. Allen Corey              45          Secretary and Director

Bill E. Coggin                          47     Vice  President  and   Chief
                                        Financial Officer

J. Steven Person            43          Vice President, Marketing

Paul L. Morris              60          Director

H.  H.  Wommack, III, is Chairman of the Board, President, Chief  Executive
Officer,  Treasurer, principal stockholder and a director of  the  Managing
General  Partner,  and  has  served as its President  since  the  Company's
organization  in August, 1983.  Prior to the formation of the Company,  Mr.
Wommack  was  a  self-employed  independent oil  producer  engaged  in  the
purchase  and sale of royalty and working interests in oil and gas  leases,
and  the drilling of exploratory and developmental oil and gas wells.   Mr.
Wommack  holds  a J.D. degree from the University of Texas  from  which  he
graduated  in  1980, and a B.A. from the University of  North  Carolina  in
1977.

H.  Allen  Corey, a founder of the Managing General Partner, has served  as
the   Managing  General  Partner's  secretary  and  a  director  since  its
inception.   Mr. Corey is President of Trolley Barn Brewery, Inc.,  a  brew
pub restaurant chain based in the Southeast.  Prior to his involvement with
Trolley Barn, Mr. Corey was a partner at the law firm of Miller & Martin in
Chattanooga,  Tennessee.  He is currently of counsel to  the  law  firm  of
Baker,  Donelson,  Bearman  & Caldwell, with the  offices  in  Chattanooga,
Tennessee.  Mr. Corey received a J.D. degree from the Vanderbilt University
Law  School and B.A. degree from the University of North Carolina at Chapel
Hill.

Bill  E. Coggin, Vice President and Chief Financial Officer, has been  with
the Managing General Partner since 1985.  Mr. Coggin was Controller for Rod
Ric  Corporation of Midland, Texas, an oil and gas drilling company, during
the latter part of 1984.  He was Controller for C.F. Lawrence & Associates,
Inc., an independent oil and gas operator also of Midland, Texas during the
early  part of 1984.  Mr. Coggin taught public school for four years  prior
to his business experience.  Mr. Coggin received a B.S. in Education and  a
B.B.A. in Accounting from Angelo State University.

J.  Steven  Person, Vice President, Marketing, assumed his responsibilities
with  the Managing General Partner as National Marketing Director in  1989.
Prior  to joining the Managing General Partner, Mr. Person served  as  Vice
President  of  Marketing  for CRI, Inc., and was  associated  with  Capital
Financial  Group and Dean Witter (1983).  He received a B.B.A. from  Baylor
University in 1982 and an M.B.A. from Houston Baptist University in 1987.

Paul  L.  Morris has served as a Director of Southwest Royalties  Holdings,
Inc.  since August 1998 and Southwest Royalties, Inc. since September 1998.
Mr. Morris is President and CEO of Wagner & Brown, Ltd., one of the largest
independently owned oil and gas companies in the United States.   Prior  to
his  position with Wagner & Brown, Mr. Morris served as President of Banner
Energy  and  in various managerial positions with the Columbia Gas  System,
Inc.

<PAGE>
Key Employees

Jon  P. Tate, Vice President, Land and Assistant Secretary, age 44, assumed
his  responsibilities with the Managing General Partner in 1989.  Prior  to
joining  the  Managing  General Partner, Mr.  Tate  was  employed  by  C.F.
Lawrence  & Associates, Inc., an independent oil and gas company,  as  Land
Manager from 1981 through 1989.  Mr. Tate is a member of the Permian  Basin
Landman's  Association and American Association of Petroleum Landmen.   Mr.
Tate received his B.B.S. degree from Hardin-Simmons University.

R.  Douglas  Keathley,  Vice President, Operations,  age  46,  assumed  his
responsibilities with the Managing General Partner as a Production Engineer
in  October,  1992.   Prior to joining the Managing  General  Partner,  Mr.
Keathley  was  employed for four (4) years by ARCO Oil  &  Gas  Company  as
senior  drilling  engineer working in all phases of well production  (1988-
1992),  eight  (8)  years by Reading & Bates Petroleum  Company  as  senior
petroleum  engineer responsible for drilling (1980-1988) and two (2)  years
by  Tenneco Oil Company as drilling engineer responsible for all phases  of
drilling   (1978-1980).   Mr.  Keathley  received  his  B.S.  in  Petroleum
Engineering in 1977 from the University of Oklahoma.

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 2001 and 2000 and $11,000 during 1999 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 11 percent interest  as  a  Managing
General Partner. Through prior purchases, the Managing General Partner also
owns  22.0  limited partner units, or 1.9% 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.  A list  of  beneficial
owners  of limited partner units, acquired by the Managing General Partner,
is as follows:

<PAGE>
                                                  Amount and
                                                   Nature of      Percent
                     Name and Address of           Beneficial        of
 Title of Class        Beneficial Owner            Ownership       Class
-------------------  ---------------------------  ---------------  -------
Limited Partnership  Southwest Royalties, Inc.    Directly Owns      1.9%
 Interest            Managing General Partner     22.0 Units
                     407 N. Big Spring Street
                     Midland, TX  79701

Limited Partnership  H. H. Wommack, III           Indirectly Owns    1.9%
 Interest            Chairman of the Board,       22.0 Units
                     President, CEO, Treasurer
                     and Director of Southwest
                     Royalties, Inc., the
                     Managing General Partner
                     407 N. Big Spring Street
                     Midland, TX  79701

Limited Partnership  H. Allen Corey               Indirectly Owns    1.9%
 Interest            Secretary and Director of    22.0 Units
                     Southwest Royalties, Inc.,
                     the Managing General
                     Partner
                     633 Chestnut Street
                     Chattanooga, TN  37450-1800

Limited Partnership  Bill E. Coggin               Indirectly Owns    1.9%
 Interest            Vice President and CFO of    22.0 Units
                     Southwest Royalties, Inc.,
                     the Managing General
                     Partner
                     407 N. Big Spring Street
                     Midland, TX  79701

Limited Partnership  J. Steven Person             Indirectly Owns    1.9%
 Interest            Vice President, Marketing of 22.0 Units
                     Southwest Royalties, Inc.,
                     the Managing General
                     Partner
                     407 N. Big Spring Street
                     Midland, TX  79701

Limited Partnership  Paul L. Morris               Indirectly Owns    1.9%
 Interest            Director, of Southwest       22.0 Units
                     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.

<PAGE>
Item 13.  Certain Relationships and Related Transactions

In 2001, 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 $11,800 for administrative  overhead
attributable to operating such properties during 2001.

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 $1,100 for the year ended
December 31, 2001.

The  law  firm  of Baker, Donelson, Bearman & Caldwell, of which  H.  Allen
Corey,  an  officer  and  director of the Managing General  Partner,  is  a
partner, is counsel to the Partnership. Baker, Donelson, Bearman & Caldwell
provided services totaling approximately.  There were no legal services for
the  year ended December 31, 2001, which constitutes an immaterial  portion
of that firm's business.

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.)

          (b)     Reports on Form 8-K

                  There  were  no  reports filed on  Form  8-K  during  the
              quarter ended December 31, 2001.

<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 29, 2002


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
       -----------------------------------
       H. H. Wommack, III, Chairman of the
       Board, President, Chief Executive
       Officer, Treasurer and Director


Date:  March 29, 2002


By:    /s/ H. Allen Corey
       -----------------------------
       H. Allen Corey, Secretary and
       Director


Date:  March 29, 2002

<PAGE>