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, 1999

                                    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 38.   There  is  no
exhibit index.

<PAGE>
                            Table of Contents

Item                                                                   Page

                                  Part I

 1.  Business                                                            3

 2.  Properties                                                          6

 3.  Legal Proceedings                                                   8

 4.  Submission of Matters to a Vote of Security Holders                 8

                                 Part II

 5.  Market for Registrant's Common Equity and Related
     Stockholder Matters                                                 9

 6.  Selected Financial Data                                            10

 7.  Management's Discussion and Analysis of
     Financial Condition and Results of Operations                      11

 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                     36

                                 Part IV

14.  Exhibits, Financial Statement Schedules, and Reports
     on Form 8-K                                                        37

     Signatures                                                         38

<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  97  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>
Oil prices experienced a year of recovery during 1999.  After seeing prices
languish  near  $10  per barrel in December 1998, a rebound  occurred  that
would briefly push NYMEX pricing over $27 in late November 1999.  Crude oil
prices reached $20 per barrel in mid-July and would not fall below $21  the
rest of the year.  There were drastic improvements to the main factors that
gave  rise  to  the worst price depression in history.  These  improvements
provoked a spike in crude oil prices to levels not seen since the Gulf War.
First, OPEC has done a remarkable job of adhering to production cuts agreed
to  in  March, despite the temptation to cheat given current  pricing.   As
prices  have  risen  over  the last twelve months,  OPEC  has  consistently
maintained a compliance rate above 90 percent.  Also, most foreign  markets
are well on their way to recovery, greatly increasing the demand for energy
in   those  countries.   These  and  other  factors  have  eliminated   the
"oversupply"  of  crude oil that we experienced in 1998.   The  near  month
contract for crude oil settled at $25.60 per barrel on December 30, 1999.

In  1999  natural  gas  prices rose 10% to an average of  $2.18/MMBtu,  18 cents
higher  than  the  $2.00/MMBtu average seen in 1998.  Despite  warmer-than-
normal  heating seasons at both ends of the year, 1999 was the fourth  year
in  a  row that prices averaged $2.00/MMBtu or above. Citing lower  storage
levels and a rising demand for natural gas, industry experts are predicting
a "healthy jump" in prices for 2000.  Although higher prices in 1999 fueled
an  increase in production, end of year gas in storage nationwide  is  only
75% of capacity as compared to 87% at the end of 1998.  Further, gas demand
is expected to continue to increase at a faster pace than the amount of gas
being replaced.  A record breaking 70% of single-family homes built in 1999
were equipped with natural gas services ranging from traditional heating to
water   heating,   cooking  and  grilling.   Based  on  these   encouraging
statistics,  we  remain optimistic in our expectation  of  slightly  higher
natural  gas  prices in the coming year, hopefully seeing an average  above
the $2.20/MMBtu level.

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

                                  Oil          Gas

                    1999          86%          14%
                    1998          83%          17%
                    1997          85%          15%

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

Seasonality of Business
Although the demand for natural gas is highly seasonal, with higher  demand
in  the colder winter months and in very hot summer months, the Partnership
has  been able to sell all of its natural gas, either through contracts  in
place or on the spot market at the then prevailing spot market price.  As a
result,  the volumes sold by the Partnership have not fluctuated materially
with the change of season.

<PAGE>
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
85%  of  the Partnership's total oil and gas production during 1999: Navajo
Refining  Company, Inc. for 52% and Scurlock Permian LLC  for  33%.   Three
purchasers  accounted  for  93%  of the Partnership's  total  oil  and  gas
production  during  1998: Navajo Refining Company, Inc. for  45%,  Scurlock
Permian  Corporation 38% and Phillips 66 Natural Gas Company for 10%.   Two
purchasers  accounted  for  83%  of the Partnership's  total  oil  and  gas
production during 1997: Navajo Refining Company, Inc. for 49%, and Scurlock
Permian  Corporation for 34%.  All purchasers of the Partnership's oil  and
gas  production  are unrelated third parties.  In the event this  purchaser
were  to  discontinue purchasing the Partnership's production, the Managing
General Partner believes that a substitute purchaser or purchasers could be
located  without undue delay.  No other purchaser accounted for  an  amount
equal  to  or  greater  than 10% of the Partnership's  total  oil  and  gas
production.

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

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

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.

<PAGE>
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,
1999  there  were 97 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, 1999, 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
4 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 1999, 1998 and 1977.

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         29,000         36,000
Ward County,          89%
Texas                 working
                      interest

Dagger Draw A #1      11/92               2         23,000         35,000
Eddy County,          45%
New Mexico            working
                      interest

*Donald  R.  Creamer,  P.E., an Independent Registered  Petroleum  Engineer
prepared  the reserve and present value data for the Partnership's existing
properties  as  of  January 1, 2000.  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.

The  New York Mercantile Exchange price at December 31, 1999 of $25.60  was
used  as the beginning basis for the oil price.  Oil price adjustments from
$25.60  per  barrel were made in the individual evaluations to reflect  oil
quality,  gathering and transportation costs. The results  are  an  average
price received at the lease of $23.73 per barrel in the preparation of  the
reserve report as of January 1, 2000.

<PAGE>
In  the  determination of the gas price, the New York  Mercantile  Exchange
price  at December 31, 1999 of $2.33 was used as the beginning basis.   Gas
price   adjustments  from  $2.33  per  Mcf  were  made  in  the  individual
evaluations to reflect BTU content, gathering and transportation costs  and
gas processing and shrinkage.  The results are an average price received at
the  lease of $2.27 per Mcf in the preparation of the reserve report as  of
January 1, 2000.

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 1999.

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

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

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

Item 3.   Legal Proceedings

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

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

No  matter  was submitted to a vote of security holders during  the  fourth
quarter of 1999 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
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.   As
of  December 31, 1998 and 1997, no limited partner units were purchased  by
the Managing General Partner.

Number of Limited and General Partner Interest Holders
As  of  December 31, 1999, there were 103 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  monthly basis.  "Net Cash Flow" is defined  as  "the  cash
generated  by the Partnership's drilling activities, less (i)  General  and
Administrative  Costs,  (ii)  Operating  Costs,  and  (iii)  any   reserves
necessary  to  meet  current  and anticipated  needs  of  the  Partnership,
including, but not limited to drilling cost overruns, as determined in  the
sole discretion of the Managing General Partner."

<PAGE>
During  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.   During 1998, distributions were made totaling $40,500,  with
$36,045  distributed to the investor partners and $4,455  to  the  Managing
General  Partner.   For the year ended December 31, 1998, distributions  of
$31.49  per  investor partner unit were made, based upon 1,144.50  investor
partner  units outstanding. During 1997, twelve monthly distributions  were
made  totaling $290,000, with $258,100 distributed to the investor partners
and  $31,900 to the Managing General Partner.  For the year ended  December
31,  1997,  distributions of $225.51 per investor partner unit  were  made,
based upon 1,144.50 investor partner units outstanding.

Item 6.   Selected Financial Data

The  following  selected financial data for the years  ended  December  31,
1999,  1998,  1997,  1996 and 1995 should be read in conjunction  with  the
financial statements included in Item 8:

                                    Years ended December 31,
                     -----------------------------------------------------
                                            Restated
                        1999        1998      1997        1996      1995
                        ----        ----      ----        ----      ----
Revenues            $  252,026    172,847    307,526    480,994   276,584

Net income (loss)      119,990    (3,178)    126,704    278,970    40,828

Partners' share of
 net income (loss):

  Managing General
   Partner              17,159      5,480     20,529     38,903    14,247

  Investor partners    102,831    (8,658)    106,175    240,067    26,581

Investor partners'
 net income (loss)
  per unit               89.85     (7.57)      92.77     209.76      23.22

Investor partners'
 cash distributions
  per unit               66.10      31.49     225.51     196.74     86.32

Total assets        $  237,888    195,528    236,923    399,872   373,960

<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 a workover
during  2000 to enhance production.  Additional workovers may be  performed
in  the  year  2003.   The partnership may have an increase  in  production
volumes  for the year 2000 and 2003, otherwise, the partnership  will  most
likely  experience  the historical production decline of approximately  12%
per year.


<PAGE>
A.  General Comparison of the Years Ended December 31, 1999 and 1998

The  following  table  provides certain information  regarding  performance
factors for the years ended December 31, 1999 and 1998:

                                                  Year Ended
                                                 December 31,    Percentage
                                                                  Increase
                                                1999      1998   (Decrease)
                                                ----      ----   ---------

Average price per barrel of oil            $   16.88    12.74      32%
Average price per mcf of gas               $    1.81     1.60      13%
Oil production in barrels                     12,800   11,300      13%
Gas production in mcf                         19,540   17,800      10%
Gross oil and gas revenue                  $ 251,484  172,545      46%
Net oil and gas revenue                    $ 171,878   72,410     137%
Partnership distributions                  $  85,000   40,500     110%
Limited partner distributions              $  75,650   36,045     110%
Per unit distribution to limited partners  $   66.10    31.49     110%
Number of limited partner units              1,144.5  1,144.5

Revenues

The  Partnership's oil and gas revenues increased to $251,484 from $172,545
for  the  years ended December 31, 1999 and 1998, respectively, an increase
of  46%.  The principal factors affecting the comparison of the years ended
December 31, 1999 and 1998 are as follows:

1.  The  average  price  for a barrel of oil received  by  the  Partnership
    increased  during the year ended December 31, 1999 as compared  to  the
    year ended December 31, 1998 by 32%, or $4.14 per barrel, resulting  in
    an increase of approximately $46,800 in revenues. Oil sales represented
    86%  of total oil and gas sales during the year ended December 31, 1999
    as compared to 83% during the year ended December 31, 1998.

    The  average  price  for  an  mcf of gas received  by  the  Partnership
    increased during the same period by 13%, or $.21 per mcf, resulting  in
    an increase of approximately $3,700 in revenues.

    The  total  increase in revenues due to the change in  prices  received
    from oil and gas production is approximately $50,500.  The market price
    for  oil  and gas has been extremely volatile over the past decade  and
    management  expects a certain amount of volatility to continue  in  the
    foreseeable future.

<PAGE>
2.   Oil production increased approximately 1,500 barrels or 13% during the
   year ended December 31, 1999 as compared to the year ended December  31,
   1998, resulting in an increase of approximately $25,300 in revenues.

    Gas production increased approximately 1,740 mcf or 10% during the same
    period, resulting in an increase of approximately $3,100 in revenues.

    The  total  increase  in revenues due to the change  in  production  is
    approximately $28,400.  The increase in 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 have actually decreased oil by 31% and  gas  by  30%.
    This  decrease  was  due primarily to a decrease  of  the  Partnerships
    interest in the Dagger Draw lease in relation to a fairness letter.

Costs and Expenses

Total  costs and expenses decreased to $132,036 from $176,025 for the years
ended  December 31, 1999 and 1998, respectively, a decrease  of  25%.   The
decrease  is  the result of lower lease operating costs, depletion  expense
and general and administrative costs.

1.    Lease  operating  costs  and production  taxes  were  21%  lower,  or
   approximately $20,500 less during the year ended December  31,  1999  as
   compared  to  the year ended December 31, 1998.  The decrease  in  lease
   operating costs are due primarily to workover expenses incurred during 1998
   and the issuance of a fairness letter, which decreased the Partnership's
   ownership percentage on the Dagger Draw.

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
    28% or approximately $6,500 during the year ended December 31, 1999  as
    compared to the year ended December 31, 1998.  The decrease of  general
    and  administrative  costs  were due in part to  additional  accounting
    costs  incurred  in  1998  in relation to the outsourcing  of  K-1  tax
    package  preparation and a change in auditors requiring  opinions  from
    both  the  predecessors  and  successor  auditors.   Additionally,  the
    Managing  General  Partner in its effort to cut  back  on  general  and
    administrative costs whenever and wherever possible was able to  reduce
    the  cost  of  reserve reports and K-1 tax package  preparation  during
    1999.

3.  Depletion expense decreased to $36,000 for the year ended December  31,
    1999  from  $53,000  for the same period in 1999.   This  represents  a
    decrease  of 32%.  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.

   A  contributing factor to the decline in depletion expense  between  the
   comparative  periods was the impact of revisions of  previous  estimates
   on  reserves.  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  decreased  depletion
   expense approximately $19,000 as of December 31, 1998.

<PAGE>
Results of Operations

B.  General Comparison of the Years Ended December 31, 1998 and 1997

The  following  table  provides certain information  regarding  performance
factors for the years ended December 31, 1998 and 1997:

                                                  Year Ended
                                                 December 31,    Percentage
                                                                  Increase
                                                1998      1997   (Decrease)
                                                ----      ----   ---------

Average price per barrel of oil            $   12.74    20.10    (37%)
Average price per mcf of gas               $    1.60     2.14    (25%)
Oil production in barrels                     11,300   12,900    (12%)
Gas production in mcf                         17,800   21,200    (16%)
Gross oil and gas revenue                  $ 172,545  304,617    (43%)
Net oil and gas revenue                    $  72,410  201,996    (64%)
Partnership distributions                  $  40,500  290,000    (86%)
Limited partner distributions              $  36,045  258,100    (86%)
Per unit distribution to limited partners  $   31.49   225.51    (86%)
Number of limited partner units              1,144.5  1,144.5

Revenues

The  Partnership's oil and gas revenues decreased to $172,545 from $304,617
for the years ended December 31, 1998 and 1997, respectively, a decrease of
43%.   The  principal factors affecting the comparison of the  years  ended
December 31, 1998 and 1997 are as follows:

1.  The  average  price  for a barrel of oil received  by  the  Partnership
    decreased  during the year ended December 31, 1998 as compared  to  the
    year ended December 31, 1997 by 37%, or $7.36 per barrel, resulting  in
    a decrease of approximately $94,900 in revenues.  Oil sales represented
    83%  of total oil and gas sales during the year ended December 31, 1998
    as compared to 85% during the year ended December 31, 1997.

    The  average  price  for  an  mcf of gas received  by  the  Partnership
    decreased during the same period by 25%, or $.54 per mcf, resulting  in
    a decrease of approximately $11,400 in revenues.

    The  total  decrease in revenues due to the change in  prices  received
    from  oil  and  gas production is approximately $106,300.   The  market
    price  for oil and gas has been extremely volatile over the past decade
    and  management expects a certain amount of volatility to  continue  in
    the foreseeable future.

<PAGE>
2.  Oil production decreased approximately 1,600 barrels or 12% during the
   year ended December 31, 1998 as compared to the year ended December 31,
   1997, resulting in a decrease of approximately $20,400 in revenues.

    Gas production decreased approximately 3,400 mcf or 16% during the same
    period, resulting in a decrease of approximately $5,400 in revenues.

    The  total  decrease  in revenues due to the change  in  production  is
    approximately $25,800.  The decrease in production is due  to  downtime
    on one gas well and sharp natural decline.

Costs and Expenses

Total  costs and expenses decreased to $176,025 from $180,822 for the years
ended  December  31, 1998 and 1997, respectively, a decrease  of  3%.   The
decrease  is  the  result  of  lower lease operating  costs  and  depletion
expense,  partially  offset  by an increase in general  and  administrative
costs.

2.    Lease  operating  costs  and  production  taxes  were  2%  lower,  or
   approximately  $2,500 less during the year ended December  31,  1998  as
   compared to the year ended December 31, 1997.

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
    25% or approximately $4,600 during the year ended December 31, 1998  as
    compared to the year ended December 31, 1997.  The increase in  general
    and  administrative costs are the result of higher accounting fees  due
    to the necessity of contracting out preparation of tax depletion and K-
    1 schedules.

3.  Depletion expense decreased to $53,000 for the year ended December  31,
    1998  from  $58,000  for the same period in 1998.   This  represents  a
    decrease  of  9%.  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.

   A  contributing factor to the decline in depletion expense  between  the
   comparative  periods was the impact of revisions of  previous  estimates
   on  reserves.  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  decreased  depletion
   expense approximately $10,000 as of December 31, 1997.

<PAGE>


Results of Operations

C.  Revenue and Distribution Comparison

Partnership net income (loss) for the years ended December 31,  1999,  1998
and  1997 was $119,990, $(3,178) and $126,704, respectively.  Excluding the
effects  of  depreciation, depletion and amortization, net income  for  the
years  ended  December  31, 1999, 1998 and 1997 was $155,990,  $49,822  and
$186,627, respectively.  Correspondingly, Partnership distributions for the
years  ended  December  31, 1999, 1998 and 1997 were $85,000,  $40,500  and
$290,000, respectively.

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.   The  sources  for  the  1998
distributions  of  $40,500  were oil and gas  operations  of  approximately
$67,300  and  the  change  in  oil  and  gas  properties  of  approximately
$(21,800),  resulting  in  excess  cash  for  contingencies  or  subsequent
distributions.  The sources for the 1997 distributions of $290,000 were oil
and  gas operations of approximately $229,500 and the change in oil and gas
properties of approximately $(9,400), with the balance from available  cash
on hand at the beginning of the period.

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.  Total distributions during  the  year
ended  December  31, 1998 were $40,500 of which $36,045 was distributed  to
the  investor partners and $4,455 to the Managing General Partner.  The per
unit  distribution to investor partners during the same period was  $31.49.
Total  distributions during the year ended December 31, 1997 were  $290,000
of  which $258,100 was distributed to the investor partners and $31,900  to
the  Managing  General  Partner.   The per unit  distribution  to  investor
partners during the same period was $225.51.

Since  inception of the Partnership, cumulative monthly cash  distributions
of  $1,212,740  have been made to the partners.  As of December  31,  1999,
$1,081,250  or  $944.74 per investor partner unit, has been distributed  to
the   investor  partners,  representing  a  94%  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 $134,600  in
1999  compared to $67,300 in 1998 and approximately $229,500 in 1997.   The
primary  source  of  the  1999  cash flow  from  operating  activities  was
profitable operations.

Cash  flows  used by investing activities were approximately $900  in  1999
compared to $21,800 in 1998 and approximately $9,400 in 1997. The principal
use  of  the 1999 cash flow from investing activities was additions to  oil
and gas properties.

Cash  flows used in financing activities were approximately $88,200 in 1999
compared  to $38,200 in 1998 and approximately $289,600 in 1997.  The  only
use in the 1999 financing activities was the distributions to partners.

As  of  December  31,  1999, the Partnership had approximately  $78,400  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
over  $35.1  million principal and $17.5 million interest payments  due  in
2000  on  its  debt  obligations. Due to the severely  depressed  commodity
prices  experienced  during the last quarter of 1997, throughout  1998  and
continuing through the second quarter of 1999 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.

Information Systems for the Year 2000

The  year  2000  issue  referred to the risk of disruptions  of  operations
caused  by  the  failure of computer-controlled systems, including  systems
used  by  third  parties, to properly recognize date sensitive  information
when  the  year changed from 1999 to 2000.  During the year ended  December
31, 1999, the Managing General Partners data processing subsidiary, Midland
Southwest  Software, Inc., installed new software as part  of  an  on-going
project  to upgrade its financial and management information systems.   The
cost  of  upgrading the software occurred in the normal course  of  Midland
Southwest  Software's  business and was not  material  to  the  results  of
operations or financial condition of the Partnership.

The  Partnership  has not experienced any significant business  disruptions
due  to  year  2000 issues causing processing errors in its systems,  or  a
third  party's  systems, during the period of operations after  January  1,
2000 until the filing of the 10-K.

<PAGE>
Item 8.   Financial Statements and Supplementary Data

                      Index to Financial Statements

                                                                       Page

Independent Auditors Report                                             19

Balance Sheets                                                          20

Statements of Operations                                                21

Statement of Changes in Partners' Equity                                22

Statements of Cash Flows                                                23

Notes to Financial Statements                                           25

<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,  1999  and
1998, 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,  1999.  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 generally  accepted  auditing
standards.  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, 1999 and 1998 and the  results
of  its  operations and its cash flows for each of the years in the  three-
year  period ended December 31, 1999 in conformity with generally  accepted
accounting principles.








                                                  KPMG LLP



Midland, Texas
March 10, 2000

<PAGE>

             Southwest Developmental Drilling Fund 91-A, L.P.
                     (a Delaware limited partnership)
                              Balance Sheets
                        December 31, 1999 and 1998


1999                                                  1998
                                                      ----          ----

  Assets

Current assets:
 Cash and cash equivalents                   $        56,196       10,719
 Receivable from Managing General Partner             21,634          241
 Distribution receivable                                 617            -

---------                                    ---------
                                                 Total    current    assets
78,447                                       10,960

---------                                    ---------
Oil and gas properties - using the full-
 cost method of accounting                         1,098,441    1,097,568
  Less accumulated depreciation,
                                               depletion  and  amortization
949,000                                      913,000

---------                                    ---------
                                              Net  oil  and gas  properties
149,441                                      184,568

---------                                    ---------
                                                                          $
227,888                                      195,528

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

Current liability - distribution payable     $             -        2,630

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

 Managing General Partner                             29,520       21,711
 Investor partners                                   198,368      171,187

---------                                    ---------
                                                Total    partners'   equity
227,888                                      192,898

---------                                    ---------
                                                                          $
227,888                                      195,528

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

















                  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, 1999, 1998 and 1997



                                                 1999      1998      1997
                                                 ----      ----      ----

  Revenues

Oil and gas sales                         $    251,484   172,545  304,617
Interest income from operations                    542       302    2,909
                                                                    -------
-------                                   -------
                                                                    252,026
172,847                                   307,526
                                                                    -------
-------                                   -------
  Expenses

Production                                      79,606   100,135  102,621
General and administrative                      16,430    22,890   18,278
Depreciation, depletion and amortization        36,000    53,000   59,923
                                                                    -------
-------                                   -------
                                                                    132,036
176,025                                   180,822
                                                                    -------
-------                                   -------
Net income (loss)                         $    119,990   (3,178)  126,704
                                                                    =======
=======                                   =======
Net income (loss) allocated to:

 Managing General Partner                 $     17,159     5,480   20,529
                                                                    =======
=======                                   =======
 Investor partners                        $    102,831   (8,658)  106,175
                                                                    =======
=======                                   =======
  Per investor partner unit               $      89.85    (7.57)    92.77
                                                                    =======
=======                                   =======


























                  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, 1999, 1998 and 1997


                                               Managing
                                               General   Investor
                                               Partner   Partners   Total
                                               -------   --------   -----

Balance at December 31, 1996, Restated    $     32,057   367,815  399,872

 Net income                                     20,529   106,175  126,704

 Distributions                                (31,900) (258,100)(290,000)
                                                                    -------
--------                                  --------
Balance at December 31, 1997                    20,686   215,890  236,576

 Net income (loss)                               5,480   (8,658)  (3,178)

 Distributions                                 (4,455)  (36,045) (40,500)
                                                                    -------
--------                                  --------
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
                                                                    =======
========                                  ========






























                  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, 1999, 1998 and 1997



                                                 1999      1998      1997
                                                 ----      ----      ----

Cash flows from operating activities:

 Cash received from oil and gas sales     $    235,741   188,548  343,716
 Cash paid to Managing General Partner
  for administrative fees and general
                                            and   administrative   overhead
(101,686)                                 (121,567)(117,118)
 Interest received                                 542       302    2,909
                                                                   --------
--------                                  --------
   Net  cash provided by operating activities              134,597   67,283
229,507
                                                                   --------
--------                                  --------
Cash flows from investing activities:

 Additions to oil and gas properties             (873)  (21,824)  (9,368)
                                                                   --------
--------                                  --------
Cash flows used in financing activities:

 Distributions to partners                    (88,247)  (38,217)(289,653)
                                                                   --------
--------                                  --------

Net increase (decrease) in cash and cash
 equivalents                                    45,477     7,242 (69,514)

 Beginning of period                            10,719     3,477   72,991
                                                                   --------
--------                                  --------
 End of period                            $     56,196    10,719    3,477
                                                                   ========
========                                  ========


(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, 1999, 1998 and 1997



                                                 1999      1998      1997
                                                 ----      ----      ----

Reconciliation of net income (loss) to net
 cash provided by operating activities:

Net income (loss)                         $    119,990   (3,178)  126,704

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

   Depreciation, depletion and amortization                36,000    53,000
59,923
  (Increase) decrease in receivables          (15,743)    16,003   39,099
  Increase (Decrease) in payables              (5,650)     1,458    3,781
                                                                    -------
-------                                   -------
Net cash provided by operating activities $    134,597    67,283  229,507
                                                                    =======
=======                                   =======





































                  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.

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

                      Notes to Financial Statements


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.

     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, 1999, 1998  and  1997
     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.  Actual results could differ
     from those estimates.


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

                      Notes to Financial Statements


2.   Summary of Significant Accounting Policies - continued

     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,  1999,  1998  and
     1997, 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,  1999  and 1998 is $131,815 and $144,886, respectively, less  than
     that  shown  on  the  accompanying Balance Sheets in  accordance  with
     generally accepted accounting principles.

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

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

                      Notes to Financial Statements


2.   Summary of Significant Accounting Policies - continued

     Number of Investor Partner Units
     As  of  December 31, 1999, 1998 and 1997, there were 1,144.5  investor
     partner units outstanding held by 103, 99 and 99 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.

3.   Liquidity - Managing General Partner
     The  Managing General Partner has a highly leveraged capital structure
     with  over $35.1 million principal and $17.5 million interest payments
     due  in  2000 on its debt obligations.  Due to the severely  depressed
     commodity  prices  experienced  during  the  last  quarter  of   1997,
     throughout 1998 and continuing through the second quarter of 1999  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.

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

                      Notes to Financial Statements


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.

     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, 1999, the Partnership has not been fined, cited or
     notified  of any environmental violations and management is not  aware
     of  any  unasserted  violations which would have  a  material  adverse
     effect upon capital expenditures, earnings or the competitive position
     in  the  oil and gas industry.  However, the Managing General  Partner
     does  recognize  by  the very nature of its business,  material  costs
     could be incurred in the near term to bring the Partnership into total
     compliance.   The amount of such future expenditures is  not  reliably
     determinable  due to several factors, including the unknown  magnitude
     of  possible  contaminations, the unknown timing  and  extent  of  the
     corrective  actions  which may be required, the determination  of  the
     Partnership's liability in proportion to other responsible parties and
     the  extent to which such expenditures are recoverable from  insurance
     or indemnifications from prior owners of Partnership's properties.

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

                      Notes to Financial Statements


5.   Related Party Transactions
     A  significant  portion  of the oil and gas properties  in  which  the
     Partnership  has  an interest are operated by and purchased  from  the
     Managing General Partner.  As is usual in the industry and 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 $13,000, $13,400 and  $12,000  for  the  years
     ended  December 31, 1999, 1998 and 1997, 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
     $7,300,  $3,200 and none for the years ended December 31,  1999,  1998
     and 1997, respectively, and the Managing General Partner believes that
     these  costs are comparable to similar charges paid by the Partnership
     to unrelated third parties.

     Southwest  Royalties,  Inc., the Managing General  Partner,  was  paid
     $11,000  in  1999,  $10,793 during 1998 and $12,000  during  1997  for
     indirect general and administrative overhead expenses.

     Receivables  from  Southwest  Royalties, Inc.,  the  Managing  General
     Partner,  of  approximately $21,634 and $241  are  from  oil  and  gas
     production, net of lease operating costs and production taxes,  as  of
     December 31, 1999 and 1998, 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  to
     the  Partnership approximating none, none and $30 for the years  ended
     December 31, 1999, 1998 and 1997, respectively.

6.   Major Customers
     No  material portion of the Partnership's business is dependent  on  a
     single  purchaser, or a very few purchasers, where  the  loss  of  one
     would  have  a  material  adverse  impact  on  the  Partnership.   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%.  Three purchasers accounted for  93%  of
     the  Partnership's  total oil and gas production during  1998:  Navajo
     Refining Company, Inc. for 45%, Scurlock Permian Corporation  38%  and
     Phillips 66 Natural Gas Company for 10%.  Two purchasers accounted for
     83%  of  the  Partnership's total oil and gas production during  1997:
     Navajo  Refining  Company, Inc. 49%, and Scurlock Permian  Corporation
     34%.   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>
             Southwest Developmental Drilling Fund 91-A, L.P.
                     (a Delaware limited partnership)

                      Notes to Financial Statements


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

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

     January 1, 1997                                  74,000      141,000

       Revisions of estimates in place               (6,000)     (50,000)
       Production                                   (13,000)     (21,000)
                                                     -------      -------
     December 31, 1997                                55,000       70,000

       Revisions of estimates in place                 2,000       16,000
       Production                                   (11,000)     (18,000)
                                                     -------      -------
     December 31, 1998                                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
                                                     =======      =======

     Proved developed reserves -

     December 31, 1997                                55,000       70,000
                                                     =======      =======
     December 31, 1998                                46,000       68,000
                                                     =======      =======
     December 31, 1999                                44,000       61,000
                                                     =======      =======

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

     *Donald R. Creamer, P.E., an Independent Registered Petroleum Engineer
     prepared  the  reserve  and present value data for  the  Partnership's
     existing properties as of January 1, 2000.  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.

     The  New York Mercantile Exchange price at December 31, 1999 of $25.60
     was  used  as  the  beginning basis for  the  oil  price.   Oil  price
     adjustments  from  $25.60  per  barrel were  made  in  the  individual
     evaluations  to  reflect  oil  quality, gathering  and  transportation
     costs.   The  results are an average price received at  the  lease  of
     $23.73  per  barrel  in the preparation of the reserve  report  as  of
     January 1, 2000.

<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
     In  the  determination  of  the gas price,  the  New  York  Mercantile
     Exchange price at December 31, 1999 of $2.33 was used as the beginning
     basis.   Gas  price adjustments from $2.33 per Mcf were  made  in  the
     individual   evaluations  to  reflect  BTU  content,   gathering   and
     transportation  costs and gas processing and shrinkage.   The  results
     are  an  average price received at the lease of $2.27 per Mcf  in  the
     preparation of the reserve report as of January 1, 2000.

     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, 1999, 1998 and 1997 is
     presented below:

                                              1999       1998        1997
                                              ----       ----        ----

     Future cash inflows                $  1,179,000    602,000  1,127,000
     Production and development costs        686,000    374,000    565,000
                                           ---------  ---------  ---------
     Future net cash flows                   493,000    228,000    562,000
     10% annual discount for estimated
       timing of cash flows                  142,000   (47,000)    112,000
                                           ---------  ---------  ---------
     Standardized measure of discounted
       future net cash flows            $    351,000    275,000    450,000
                                           =========  =========  =========

     The  principal  sources  of  change in  the  standardized  measure  of
     discounted  future  net cash flows for the years  ended  December  31,
     1999, 1998 and 1997 are as follows:

                                               1999       1998        1997
                                               ----       ----        ----

     Sales of oil and gas produced,
       net of production costs          $  (172,000)   (73,000)  (202,000)
      Changes in prices and production costs             167,000  (339,000)
(472,000)
     Changes of production rates
       (timing) and others                  (20,000)    169,000   (19,000)
     Revisions of previous
       quantities estimates                   89,000     23,000   (93,000)
     Changes in estimated future
       development costs                    (16,000)          -          -
     Accretion of discount                    28,000     45,000    112,000
     Discounted future net
       cash flows -
      Beginning of year                      275,000    450,000  1,124,000
                                           ---------   --------  ---------
      End of year                       $    351,000    275,000    450,000
                                           =========   ========  =========

     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.

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                      44     Chairman   of   the   Board,
                                        President,
                                        Chief Executive Officer, Treasurer
                                        and Director

H. Allen Corey              43          Secretary and Director

Bill E. Coggin                          45     Vice  President  and   Chief
                                        Financial Officer

J. Steven Person            41          Vice President, Marketing

Paul L. Morris              58          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.D.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 Columbia Gas System, Inc.

<PAGE>
Key Employees

Jon  P. Tate, Vice President, Land and Assistant Secretary, age 42, 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 received his B.B.S. degree  from  Hardin-Simmons
University.

R.  Douglas  Keathley,  Vice President, Operations,  age  44,  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  $11,000 during 1999, $10,793 during 1998 and $12,000 during  1997
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  5  limited  partner  units,  or .4% limited  partner  interest.   The
Managing  General  Partner  total  percentage  interest  ownership  in  the
Partnership is 11.0%.

No  officer or director of the Managing General Partner owns Units  in  the
Partnership.   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 1999, the Managing General Partner received $11,000 as an administrative
fee.   This  amount  is  part  of the general and  administrative  expenses
incurred by the Partnership.

In  some  instances the Managing General Partner and certain  officers  and
employees  may  be working interest owners in an oil and  gas  property  in
which  the Partnership also has a working interest.  Certain properties  in
which  the Partnership has an interest are operated by the Managing General
Partner,  who  was  paid approximately $13,000 for administrative  overhead
attributable to operating such properties during 1999.

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 $7,300 for the year ended
December 31, 1999.

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, 1999, 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.)

                  27 Financial Data Schedule

          (b)     Reports on Form 8-K

                  There  were  no  reports filed on  Form  8-K  during  the
              quarter ended December 31, 1999.

<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 31, 2000


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 31, 2000


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


Date:  March 31, 2000

<PAGE>