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

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

For the fiscal year ended December 31, 2001

                                    OR

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

For the transition period from                      to

Commission File Number 33-38511

             Southwest Developmental Drilling Fund 92-A, L.P.
                (Exact name of registrant as specified in
                    its limited partnership agreement)

Delaware                                                    75-2387816
(State or other jurisdiction                             (I.R.S. Employer
of incorporation or organization)                       Identification No.)

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

Registrant's telephone number, including area code  (915) 686-9927

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

                                   None

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

                  limited and general partner interests

Indicate by check mark whether registrant (1) has filed reports required to
be  filed  by  Section 13 or 15(d) of the Securities Exchange Act  of  1934
during  the  preceding  12  months (or for such  shorter  period  that  the
registrant was required to file such reports), and (2) has been subject  to
such filing requirements for the past 90 days:     Yes   x    No

Indicate by check mark if disclosure of delinquent filers pursuant to  Item
405  of  Regulation S-K (229.405 of this chapter) is not contained  herein,
and  will  not  be  contained,  to the best of registrant's  knowledge,  in
definitive  proxy or information statements incorporated  by  reference  in
Part III of this Form 10-K or any amendment to this Form 10-K.     [x]

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

The  total  number of pages contained in this report is 39.   There  is  no
exhibit index.

<PAGE>
                            Table of Contents

Item                                                                   Page

                                  Part I

 1.  Business                                                            3

 2.  Properties                                                          5

 3.  Legal Proceedings                                                   7

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

                                 Part II

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

 6.  Selected Financial Data                                             9

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

 8.  Financial Statements and Supplementary Data                        19

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

                                 Part III

10.  Directors and Executive Officers of the Registrant                 34

11.  Executive Compensation                                             35

12.  Security Ownership of Certain Beneficial Owners and
     Management                                                         35

13.  Certain Relationships and Related Transactions                     37

                                 Part IV

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

     Signatures                                                         39

<PAGE>

                                  Part I

Item 1.   Business

General
Southwest  Developmental  Drilling Fund 92-A, L.P.  (the  "Partnership"  or
"Registrant")  was organized as a Delaware limited partnership  on  May  5,
1992.   The offering of limited and general partner interests began  August
11,  1992  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 December 28, 1992, with the offering of limited
and  general  partner interests concluding December 31,  1992,  with  total
investor partner contributions of $1,407,000. The Managing General  Partner
made a contribution to the capital of the Partnership at the conclusion  of
the  offering  period  in  an  amount  equal  to  1%  of  its  net  capital
contributions.  The Managing General Partner contribution was $12,030,  for
total  capital  contributions  of  $1,419,030.   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 from such properties.

The  principal executive offices of the Partnership are located at  407  N.
Big Spring, Suite 300, Midland, Texas, 79701.  The Managing General Partner
of  the  Partnership,  Southwest Royalties,  Inc.  (the  "Managing  General
Partner")   and  its  staff  of  89  individuals,  together  with   certain
independent  consultants  used  on an "as needed"  basis,  perform  various
services on behalf of the Partnership, including the selection of leasehold
interests  upon  which drilling would be performed, and  the  marketing  of
future anticipated production from such properties.  The Partnership has no
employees.

Principal Products, Marketing and Distribution
The  Partnership has acquired undeveloped 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 will be sold to unrelated third parties
in the oil and gas business.

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

<PAGE>

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

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

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

                                  Oil          Gas

                    2001          72%          28%
                    2000          78%          22%
                    1999          77%          23%

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 of 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
anticipates  that  it  will  be able to sell all  of  the  expected  future
production  of natural gas, either through contracts or on the spot  market
at the then prevailing spot market price.

Customer Dependence
No  material portion of the Partnership's business is dependent on a single
purchaser,  or a very few purchasers, where the loss of one  would  have  a
material adverse impact on the Partnership.  Three purchasers accounted for
93%  of  the Partnership's total oil and gas production during 2001: Plains
Marketing  LP  for  58%,  Duke Energy Field Services  for  21%  and  Navajo
Refining Company, Inc. for 14%.  Three purchasers accounted for 94% of  the
Partnership's total oil and gas production during 2000: Plains Marketing LP
for  63%,  Navajo Refining Company, Inc. for 16% and Duke Energy  Transport
and Trad. for 15%.  Three purchasers accounted for 95% of the Partnership's
total  oil  and gas production during 1999: Scurlock Permian LLC  for  59%,
Duke  Energy Transport and Trad. for 20% and Navajo Refining Company,  Inc.
for  16%.   All purchasers of the Partnership's oil and gas production  are
unrelated  third parties.  In the event this purchaser were to  discontinue
purchasing  the  Partnership's  production, the  Managing  General  Partner
believes that a substitute purchaser or purchasers could be located without
undue  delay.   No  other purchaser accounted for an  amount  equal  to  or
greater than 10% of the Partnership's total oil and gas production.

<PAGE>

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

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

Regulation

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

Various  aspects of the Partnership's oil and gas activities are  regulated
by  administrative agencies under statutory provisions of the states  where
such  activities  are  conducted and by certain  agencies  of  the  federal
government for operations on Federal leases.  Moreover, certain  prices  at
which  the  Partnership may sell its future expected 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, landmen and clerical  staff
who  engage in Partnership activities and operations and perform additional
services  for  the  Partnership as needed.  In  addition  to  the  Managing
General  Partner's  staff, the Partnership engages independent  consultants
such  as petroleum engineers and geologists as needed.  As of December  31,
2001,  there were 89 individuals directly employed by the Managing  General
Partner in various capacities.

Item 2.   Properties

In  determining  whether an interest in a particular leasehold  was  to  be
acquired,  the  Managing  General  Partner  considered  such  criteria   as
estimated  drilling costs, estimated oil and gas reserves,  estimated  cash
flow  from the sale of future production, present and future prices of  oil
and   gas,  the  extent  of  undeveloped  and  unproved  reserves  and  the
availability of markets.

<PAGE>
As  of December 31, 2001, the Partnership possessed an interest in oil  and
gas properties located in Ward County of Texas and Lea and Eddy Counties of
New Mexico.  These properties consist of various interests in 9 wells.

Due  to  the  Partnership's  objective of  maintaining  current  operations
without  engaging  in  the  additional drilling  of  any  developmental  or
exploratory  wells,  or  additional acquisitions of  producing  properties,
there has not been any significant changes in properties during 2001,  2000
and 1999.

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

                         Date
                       Purchased       No. of         Proved Reserves*
Name and Location     and Interest     Wells      Oil (bbls)     Gas (mcf)

Mobil Fee H #1        12/92 at            1         46,000        189,000
Ward County,          100%
Texas                 working
                      interest

*Ryder Scott Petroleum Engineer prepared the reserve and present value data
for  the  Partnership's existing properties as of  January  1,  2002.   The
reserve  estimates were made in accordance with guidelines  established  by
the  Securities  and  Exchange  Commission  pursuant  to  Rule  4-10(a)  of
Regulation  S-X.   Such guidelines require oil and gas reserve  reports  be
prepared  under  existing  economic  and  operating  conditions   with   no
provisions   for   price   and  cost  escalation  except   by   contractual
arrangements.

Oil  price  adjustments were made in the individual evaluations to  reflect
oil quality, gathering and transportation costs. The results of the reserve
report as of January 1, 2002 are an average price of $18.90 per barrel.

Gas  price  adjustments were made in the individual evaluations to  reflect
BTU  content,  gathering and transportation costs and  gas  processing  and
shrinkage.  The results of the reserve report as of January 1, 2002 are  an
average price of $2.34 per Mcf.

As  also discussed in Part II, Item 7, Management's Discussion and Analysis
of  Financial Condition and Results of Operations, oil and gas prices  were
subject to frequent changes in 2001.

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

<PAGE>

Unanticipated  depletion, if it occurs, will result in lower reserves  than
previously  estimated; thus an ultimately lower return for the Partnership.
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.   All  of  the proved reserves are included in  the  engineering
reports which evaluate the Partnership's present reserves.

Item 3.   Legal Proceedings

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

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

No  matter  was submitted to a vote of security holders during  the  fourth
quarter of 2001 through the solicitation of proxies or otherwise.

<PAGE>
                                 Part II


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

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

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 Nations Bank, N.A. of
Midland, Texas, plus one percent (1%), which value shall be further reduced
by  a risk factor discount of no more than one-third (1/3) to be determined
by the Managing General Partner in its sole and absolute discretion.  As of
December  31, 2001, no limited partner units were purchased by the Managing
General  Partner.  In 2000, 5 limited partner units were  tendered  to  and
purchased  by  the  Managing General Partner at an average  base  price  of
$181.86  per unit.  As of December 31, 1999, no limited partner units  were
purchased by the Managing General Partner.


Number of Limited and General Partner Interest Holders
As of December 31, 2001, there were 105 holders of limited partner units.

Distributions
Pursuant  to Article IV, Section 4.01 of the Partnership's Certificate  and
Agreement  of  Limited Partnership, "Net Cash Flow" is distributed  to  the
partners  on  a quarterly basis.  "Net Cash Flow" is defined as  "the  cash
generated  by the Partnership's drilling activities, less (i)  General  and
Administrative  Costs,  (ii)  Operating  Costs,  and  (iii)  any   reserves
necessary  to  meet  current  and anticipated  needs  of  the  Partnership,
including, but not limited to drilling cost overruns, as determined in  the
sole discretion of the Managing General Partner."

During  2001,  quarterly  distributions were made totaling  $208,798,  with
$185,830  distributed to the investor partners and $22,968 to the  Managing
General  Partners.  For the year ended December 31, 2001, distributions  of
$132.08  per  investor partner unit were made, based  upon  1,407  investor
partner  units outstanding. During 2000, quarterly distributions were  made
totaling  $224,640, with $199,930 distributed to the investor partners  and
$24,710 to the Managing General Partners.  For the year ended December  31,
2000,  distributions of $142.10 per investor partner unit were made,  based
upon  1,407 investor partner units outstanding.  During 1999, distributions
were  made  totaling  $85,000,  with $75,650 distributed  to  the  investor
partners  and $9,350 to the Managing General Partners.  For the year  ended
December  31, 1999, distributions of $53.77 per investor partner unit  were
made, based upon 1,407 investor partner units outstanding.

<PAGE>
Item 6.   Selected Financial Data

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

                                       Year ended December 31,
                           ------------------------------------------------
                               2001    2000      1999      1998     1997
                               ----    ----      ----      ----     ----

Revenues              $   333,192     372,553   249,965  201,370  335,791

Net income (loss)         160,893     217,640   112,767(331,847)   93,437

Partners' share of net
 income (loss):

  Managing General
   Partner                 20,338      25,590    14,274    6,863   19,601

  Investor partners       140,555     192,050    98,493(338,710)   73,836

Investor partners' net
  income (loss) per unit                 99.90    136.50     70.00 (240.73)
52.48

Investor partners' cash
  distributions per unit                132.08    142.10    53.77     58.32
129.99

Total assets          $   231,369     279,195   286,195  258,508  682,573

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

General

Southwest  Developmental  Drilling Fund 92-A, L.P.  (the  "Partnership"  or
"Registrant")  was organized as a Delaware limited partnership  on  May  5,
1992.   The offering of limited and general partner interests began  August
11,  1992  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 December 28, 1992, with the offering of limited
and  general  partner interests concluding December 31,  1992,  with  total
investor partner contributions of $1,407,000.  The Managing General Partner
made a contribution to the capital of the Partnership at the conclusion  of
the  offering  period  in  an  amount  equal  to  1%  of  its  net  capital
contributions.  The Managing General Partner contribution was $12,030.

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

Based on current conditions, management anticipates performing no workovers
to  enhance  production.  The partnership will most likely  experience  the
historical production decline of approximately 6% per year.

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

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

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

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

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

Results of Operations

A.  General Comparison of the Years Ended December 31, 2001 and 2000

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

                                                  Year Ended     Percentage
                                                 December 31,     Increase
                                                2001      2000   (Decrease)
                                                ----      ----   ---------

Average price per barrel of oil            $   25.25    29.73    (15%)
Average price per mcf of gas               $    4.08     3.98       3%
Oil production in barrels                      9,460    9,800     (3%)
Gas production in mcf                         23,000   20,200      14%
Gross oil and gas revenue                  $ 332,643  371,824    (11%)
Net oil and gas revenue                    $ 200,862  247,853    (19%)
Partnership distributions                  $ 208,798  224,640     (7%)
Limited partner distributions              $ 185,830  199,930     (7%)
Per unit distribution to limited partners  $  132.08   142.10     (7%)
Number of limited partner units                1,407    1,407

Revenues

The  Partnership's oil and gas revenues decreased to $332,643 from $371,824
for the years ended December 31, 2001 and 2000, respectively, a decrease of
11%.   The  principal factors affecting the comparison of the  years  ended
December 31, 2001 and 2000 are as follows:

1.  The  average  price  for a barrel of oil received  by  the  Partnership
    decreased  during the year ended December 31, 2001 as compared  to  the
    year ended December 31, 2000 by 15%, or $4.48 per barrel, resulting  in
    a  decrease of approximately $42,400 in revenues. Oil sales represented
    72%  of total oil and gas sales during the year ended December 31, 2001
    as compared to 78% during the year ended December 31, 2000.

    The  average  price  for  an  mcf of gas received  by  the  Partnership
    increased  during the same period by 3%, or $.10 per mcf, resulting  in
    an increase of approximately $2,300 in revenues.

    The net total decrease in revenues due to the change in prices received
    from oil and gas production is approximately $40,100.  The market price
    for  oil  and gas has been extremely volatile over the past decade  and
    management  expects a certain amount of volatility to continue  in  the
    foreseeable future.

<PAGE>

2.   Oil  production decreased approximately 340 barrels or 3%  during  the
   year ended December 31, 2001 as compared to the year ended December  31,
   2000, resulting in a decrease of approximately $10,100 in revenues.

    Gas production increased approximately 2,800 mcf or 14% during the same
    period, resulting in an increase of approximately $11,100 in revenues.

    The  net total increase in revenues due to the change in production  is
    approximately $1,000.

Costs and Expenses

Total  costs and expenses increased to $172,299 from $154,913 for the years
ended  December 31, 2001 and 2000, respectively, an increase of  11%.   The
increase  is the result of higher lease operating costs, depletion  expense
and general and administrative expense.

1.    Lease  operating  costs  and production  taxes  were  6%  higher,  or
   approximately  $7,800 more during the year ended December  31,  2001  as
   compared to the year ended December 31, 2000.

2.  General and administrative costs consist of independent accounting  and
    engineering  fees,  computer services, postage,  and  Managing  General
    Partner personnel costs. General and administrative costs increased  4%
    or  approximately  $600  during the year ended  December  31,  2001  as
    compared to the year ended December 31, 2000.

3.  Depletion expense increased to $24,000 for the year ended December  31,
    2001  from  $15,000  for the same period in 2000.  This  represents  an
    increase  of 60%.  Depletion is calculated using the units  of  revenue
    method  of  amortization based on a percentage of current period  gross
    revenues  to  total future gross oil and gas revenues, as estimated  by
    the Partnership's independent petroleum consultants.

    The  major  factor  to  the increase in depletion expense  between  the
    comparative periods was the decrease in the price of oil and  gas  used
    to determine the Partnership's reserves for January 1, 2002 as compared
    to  2001,  and  the decrease in oil and gas revenues  received  by  the
    Partnership  during  2001 as compared to 2000.  Revisions  of  previous
    estimates  can be attributed to the changes in production  performance,
    oil  and  gas  price and production costs.  The impact of the  revision
    would  have  increased  depletion expense approximately  $6,000  as  of
    December 31, 2000.



<PAGE>


Results of Operations

B.  General Comparison of the Years Ended December 31, 2000 and 1999

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

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

Average price per barrel of oil            $   29.73    17.74      68%
Average price per mcf of gas               $    3.98     2.35      69%
Oil production in barrels                      9,800   10,770     (9%)
Gas production in mcf                         20,200   24,940    (19%)
Gross oil and gas revenue                  $ 371,824  249,636      49%
Net oil and gas revenue                    $ 247,853  146,852      69%
Partnership distributions                  $ 224,640   85,000     164%
Limited partner distributions              $ 199,930   75,650     164%
Per unit distribution to limited partners  $  142.10    53.77     164%
Number of limited partner units                1,407    1,407

Revenues

The  Partnership's oil and gas revenues increased to $371,824 from $249,636
for  the  years ended December 31, 2000 and 1999, respectively, an increase
of  49%.  The principal factors affecting the comparison of the years ended
December 31, 2000 and 1999 are as follows:

1.  The  average  price  for a barrel of oil received  by  the  Partnership
    increased  during the year ended December 31, 2000 as compared  to  the
    year ended December 31, 1999 by 68%, or $11.99 per barrel, resulting in
    an   increase  of  approximately  $117,500  in  revenues.   Oil   sales
    represented  78%  of  total oil and gas sales  during  the  year  ended
    December 31, 2000 as compared to 77% during the year ended December 31,
    1999.

    The  average  price  for  an  mcf of gas received  by  the  Partnership
    increased during the same period by 69%, or $1.63 per mcf, resulting in
    an increase of approximately $32,900 in revenues.

    The  total  increase in revenues due to the change in  prices  received
    from  oil  and  gas production is approximately $150,400.   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 970 barrels or 9%  during  the
   year ended December 31, 2000 as compared to the year ended December  31,
   1999, resulting in a decrease of approximately $17,200 in revenues.

    Gas production decreased approximately 4,470 mcf or 19% during the same
    period, resulting in a decrease of approximately $11,100 in revenues.

    The  total  decrease  in revenues due to the change  in  production  is
    approximately $28,300.

Costs and Expenses

Total  costs and expenses increased to $154,913 from $137,198 for the years
ended  December 31, 2000 and 1999, respectively, an increase of  13%.   The
increase is the result of higher lease operating costs, partially offset by
a decrease in depletion expense and general and administrative expense.

2.    Lease  operating  costs  and production taxes  were  21%  higher,  or
   approximately $21,200 more during the year ended December  31,  2000  as
   compared  to  the year ended December 31, 1999.  The increase  in  lease
   operating costs and production taxes is due in part to an increase in major
   repairs and maintenance, such as overhead and electrical repairs on  two
   leases,  and in part to the rise in production taxes directly associated
   with the rise in oil and gas prices received during the past year.   The
   rise in oil and gas prices for 2000 has allowed the Partnership to perform
   these  repairs  and  maintenance in the hopes of increasing  production,
   thereby increasing revenues.

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  8%
    or  approximately  $1,500 during the year ended December  31,  2000  as
    compared to the year ended December 31, 1999.

3.  Depletion expense decreased to $15,000 for the year ended December  31,
    2000  from  $17,000  for the same period in 1999.   This  represents  a
    decrease  of 12%.  Depletion is calculated using the units  of  revenue
    method  of  amortization based on a percentage of current period  gross
    revenues  to  total future gross oil and gas revenues, as estimated  by
    the Partnership's independent petroleum consultants.

    The  major  factor  to  the decrease in depletion expense  between  the
    comparative periods was the increase in the price of oil and  gas  used
    to determine the Partnership's reserves for January 1, 2001 as compared
    to  2000.   Revisions of previous estimates can be  attributed  to  the
    changes  in  production performance, oil and gas price  and  production
    costs.   The  impact  of  the revision would have  increased  depletion
    expense approximately $3,000 as of December 31, 1999.



<PAGE>


C.   Revenue and Distribution Comparison

Partnership net income for the years ended December 31, 2001, 2000 and 1999
was  $160,893, $217,640 and $112,767, respectively.  Excluding the  effects
of depreciation, depletion and amortization, net income for the years ended
December  31,  2001, 2000 and 1999, would have been $184,893, $232,640  and
$129,767, respectively.  Correspondingly, Partnership distributions for the
years  ended  December 31, 2001, 2000 and 1999 were $208,798, $224,640  and
$85,000, respectively.  These differences are indicative of the changes  in
oil and gas prices, production and property during 2001, 2000 and 1999.

The  sources  for  the  2001 distributions of $208,798  were  oil  and  gas
operations  of  approximately  $197,000 and  the  change  in  oil  and  gas
properties of approximately $1,400, with the balance from available cash on
hand   at  the  beginning  of  the  period.   The  sources  for  the   2000
distributions  of  $224,640  were oil and gas operations  of  approximately
$228,800  and the change in oil and gas properties of approximately  $(75),
resulting  in  excess  cash for contingencies or subsequent  distributions.
The  sources  for  the  1999  distributions of $85,000  were  oil  and  gas
operations  of  approximately  $100,300 and  the  change  in  oil  and  gas
properties   of   approximately  $(20),  resulting  in  excess   cash   for
contingencies or subsequent distributions.

Total  distributions during the year ended December 31, 2001 were  $208,798
of  which $185,830 was distributed to the investor partners and $22,968  to
the  Managing  General  Partners.  The per unit  distribution  to  investor
partners  during  the same period was $132.08.  Total distributions  during
the  year  ended  December 31, 2000 were $224,640  of  which  $199,930  was
distributed  to  the investor partners and $24,710 to the Managing  General
Partners.  The per unit distribution to investor partners during  the  same
period was $142.10.  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 Partners.  The per unit distribution  to
investor partners during the same period was $53.77.

Since  inception of the Partnership, cumulative monthly cash  distributions
of  $1,586,353  have been made to the partners.  As of December  31,  2001,
$1,412,230 or $1,003.72 per investor partner unit, has been distributed  to
the   investor  partners,  representing  a  100%  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 $197,000  in
2001 compared to $228,800 in 2000 and approximately $100,300 in 1999.   The
primary  source  of  the  2001  cash flow  from  operating  activities  was
profitable operations.

Cash  flows  provided by (used in) investing activities were  approximately
$1,400  in 2001 compared to $(75) in 2000 and approximately $(20) in  1999.
The  principal  source of the 2001 cash flow from investing activities  was
the sale of equipment.

Cash flows used in financing activities were approximately $208,700 in 2001
compared  to $224,600 in 2000 and approximately $85,100 in 1999.  The  only
use in the 2001 financing activities was the distributions to partners.

As  of  December 31, 2001, the Partnership had $45,400 in working  capital.
The  Managing  General Partner knows of no unusual contractual  commitments
and believes the revenue generated from operations are adequate to meet the
needs of the Partnership.

Liquidity - Managing General Partner

The  Managing General Partner has a highly leveraged capital structure with
$50.0  million and $123.7 million of principal due in August  of  2003  and
October  of  2004, respectively.  The Managing General Partner  will  incur
approximately  $17.6  million in interest payments  in  2002  on  its  debt
obligations. Due to the depressed commodity prices experienced  during  the
last  quarter  of  2001,  the  Managing  General  Partner  is  experiencing
difficulty  in generating sufficient cash flow to meet its obligations  and
sustain its operations.  The Managing General Partner is currently  in  the
process  of  renegotiating the terms of its various  obligations  with  its
creditors  and/or  attempting  to seek new  lenders  or  equity  investors.
Additionally,  the  Managing General Partner would  consider  disposing  of
certain assets in order to meet its obligations.

There  can  be  no  assurance  that  the Managing  General  Partner's  debt
restructuring efforts will be successful or that the lenders will agree  to
a   course   of  action  consistent  with  the  Managing  General  Partners
requirements  in restructuring the obligations.  Even if such agreement  is
reached,  it  may  require approval of additional  lenders,  which  is  not
assured.   Furthermore, there can be no assurance that the sales of  assets
can  be  successfully  accomplished on terms  acceptable  to  the  Managing
General   Partner.   Under  current  circumstances,  the  Managing  General
Partner's  ability to continue as a going concern depends upon its  ability
to  (1)  successfully  restructure  its obligations  or  obtain  additional
financing  as  may  be  required, (2) maintain  compliance  with  all  debt
covenants, (3) generate sufficient cash flow to meet its obligations  on  a
timely  basis, and (4) achieve satisfactory levels of future earnings.   If
the  Managing  General Partner is unsuccessful in its efforts,  it  may  be
unable to meet its obligations making it necessary to undertake such  other
actions  as  may  be  appropriate  to  preserve  asset  values.   Upon  the
occurrence of any event of dissolution by the Managing General Partner, the
holders  of  a  majority of limited partnership interests may,  by  written
agreement,  elect  to  continue the business  of  the  Partnership  in  the
Partnership's   name,  with  Partnership  property,  in   a   reconstituted
partnership under the terms of the partnership agreement and to designate a
successor Managing General Partner.

<PAGE>
Recent Accounting Pronouncements

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

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

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

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk

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

<PAGE>
Item 8.  Financial Statements and Supplementary Data

                      Index to Financial Statements

                                                                       Page

Independent Auditors Report                                             19

Balance Sheets                                                          20

Statement 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 92-A
 (A Delaware Limited Partnership):


We  have audited the accompanying balance sheets of Southwest Developmental
Drilling  Fund 92-A (the "Partnership") as of December 31, 2001  and  2000,
and  the related statements of operations, changes in partners' equity  and
cash  flows  for each of the years in the three year period ended  December
31,  2001.   These  financial  statements are  the  responsibility  of  the
Partnership's management.  Our responsibility is to express an  opinion  on
these financial statements based on our audits.

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

In  our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Southwest Developmental
Drilling Fund 92-A as of December 31, 2001 and 2000 and the results of  its
operations  and  its cash flows for each of the years  in  the  three  year
period  ended  December  31, 2001 in conformity with accounting  principles
generally accepted in the United States of America.








                                                  KPMG LLP



Midland, Texas
March 10, 2002

<PAGE>

             Southwest Developmental Drilling Fund 92-A, L.P.
                     (a Delaware limited partnership)
                              Balance Sheets
                        December 31, 2001 and 2000


                                                      2001           2000
                                                      ----           ----
  Assets
  ------

Current assets:
 Cash and cash equivalents                   $        16,508       26,865
 Receivable from Managing General Partner             28,977       41,053

---------                                    ---------
                                                 Total    current    assets
45,485                                       67,918

---------                                    ---------
Oil and gas properties - using the full-
 cost method of accounting                         1,313,124    1,314,517
  Less accumulated depreciation,
                                               depletion  and  amortization
1,127,240                                    1,103,240

---------                                    ---------
                                              Net  oil  and gas  properties
185,884                                      211,277

---------                                    ---------
                                                                          $
231,369                                      279,195

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

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

Current liability - distribution payable     $            79            -

---------                                    ---------

Partners' equity:
 Managing General Partner                             27,924       30,554
 Investor partners                                   203,366      248,641

---------                                    ---------
                                                Total    partners'   equity
231,290                                      279,195

---------                                    ---------
                                                                          $
231,369                                      279,195

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




















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

<PAGE>
             Southwest Developmental Drilling Fund 92-A, L.P.
                     (a Delaware limited partnership)
                         Statements of Operations
           For the years ended December 31, 2001, 2000 and 1999


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

Oil and gas sales                         $    332,643   371,824  249,636
Interest income from operations                    549       729      329
                                                                    -------
-------                                   -------
                                                                    333,192
372,553                                   249,965
                                                                    -------
-------                                   -------

  Expenses
  --------

Production                                     131,781   123,971  102,784
General and administrative                      16,518    15,942   17,414
Depreciation, depletion and amortization        24,000    15,000   17,000
                                                                    -------
-------                                   -------
                                                                    172,299
154,913                                   137,198
                                                                    -------
-------                                   -------
Net income                                $    160,893   217,640  112,767
                                                                    =======
=======                                   =======
Net income allocated to:

 Managing General Partner                 $     20,338    25,590   14,274
                                                                    =======
=======                                   =======
 Investor partners                        $    140,555   192,050   98,493
                                                                    =======
=======                                   =======
  Per investor partner unit               $      99.90    136.50    70.00
                                                                    =======
=======                                   =======

























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

<PAGE>
             Southwest Developmental Drilling Fund 92-A, L.P.
                     (a Delaware limited partnership)
                 Statement of Changes in Partners' Equity
               Years ended December 31, 2001, 2000 and 1999


                                               Managing
                                               General   Investor
                                               Partner   Partners  Total
                                               --------  --------  -----
Balance at December 31, 1998              $     24,750   233,678  258,428

 Net income                                     14,274    98,493  112,767

 Distributions                                 (9,350)  (75,650) (85,000)
                                                                     ------
---------                                 --------
Balance at December 31, 1999                    29,674   256,521  286,195

 Net income                                     25,590   192,050  217,640

 Distributions                                (24,710) (199,930)(224,640)
                                                                     ------
---------                                 --------
Balance at December 31, 2000                    30,554   248,641  279,195

 Net income                                     20,338   140,555  160,893

 Distributions                                (22,968) (185,830)(208,798)
                                                                     ------
---------                                 --------
Balance at December 31, 2001              $     27,924   203,366  231,290
                                                                     ======
=========                                 ========































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

<PAGE>
             Southwest Developmental Drilling Fund 92-A, L.P.
                     (a Delaware limited partnership)
                         Statements of Cash Flows
               Years ended December 31, 2001, 2000 and 1999


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

Cash flows from operating activities:

 Cash received from oil and gas sales     $    353,274   361,584  223,480
 Cash paid to Managing General Partner
  for administrative fees and general
                                            and   administrative   overhead
(156,854)                                 (133,476)(123,478)
 Interest received                                 549       729      329
                                                                    -------
-------                                   -------
   Net  cash provided by operating activities              196,969  228,837
100,331
                                                                    -------
-------                                   -------
Cash flows from investing activities:

 Addition to oil and gas properties                  -      (75)     (20)
 Sale of equipment                               1,393         -        -
                                                                    -------
-------                                   -------
  Net cash provided by (used in) investing activities1,393  (75)     (20)
                                                                    -------
-------                                   -------
Cash flows used in financing activities:

 Distributions to partners                   (208,719) (224,640) (85,080)
                                                                    -------
-------                                   -------
Net (decrease) increase in cash and cash
 equivalents                                  (10,357)     4,122   15,231

 Beginning of period                            26,865    22,743    7,512
                                                                    -------
-------                                   -------
 End of period                            $     16,508    26,865   22,743
                                                                    =======
=======                                   =======


(continued)






















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

<PAGE>
             Southwest Developmental Drilling Fund 92-A, L.P.
                     (a Delaware limited partnership)
                   Statements of Cash Flows, continued
               Years ended December 31, 2001, 2000 and 1999


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

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

Net income                                $    160,893   217,640  112,767

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

   Depreciation, depletion and amortization                24,000    15,000
17,000
  Decrease (increase) in receivables            20,631  (10,240) (26,156)
  (Decrease) increase in payables              (8,555)     6,437  (3,280)
                                                                    -------
-------                                   -------
Net cash provided by operating activities $    196,969   228,837  100,331
                                                                    =======
=======                                   =======






































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

<PAGE>
             Southwest Developmental Drilling Fund 92-A, L.P.
                     (a Delaware limited partnership)

                      Notes to Financial Statements

1.   Organization
     Southwest  Developmental Drilling Fund 92-A, L.P. was organized  under
     the  laws of the state of Delaware on May 5, 1992, for the purpose  of
     engaging  primarily  in  the  business of drilling  developmental  and
     exploratory  wells, to produce and market crude oil  and  natural  gas
     produced  from  such  properties, and  acquire  leases  which  contain
     drilling prospects.  The activities of the Partnership should continue
     for  a  term  of  50 years, unless terminated at an  earlier  date  as
     provided   for   in   the  Partnership  Agreement.   The   Partnership
     anticipates  selling  its  oil and gas  production  to  a  variety  of
     purchasers  with the prices it receives being dependent upon  the  oil
     and  gas  economy.  Southwest Royalties, Inc. serves as  the  Managing
     General  Partner.   Revenues,  costs and  expenses  are  allocated  as
     follows:

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

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

          (1)   All  organization costs in excess of 4% of initial  capital
          contributions  will be paid by the Managing General  Partner  and
          will  be treated as a capital contribution.  The Partnership paid
          the  Managing  General Partner an amount equal to 4%  of  initial
          capital contributions for such organization costs.

          (2)   Administrative costs in any year which exceed 2% of capital
          contributions shall be paid by the Managing General  Partner  and
          will be treated as a capital contribution.

2.   Summary of Significant Accounting Policies

     Oil and Gas Properties
     Oil  and  gas properties are accounted for at cost under the full-cost
     method.   Under  this  method, all productive and nonproductive  costs
     incurred   in   connection  with  the  acquisition,  exploration   and
     development of oil and gas reserves are capitalized.  Gain or loss  on
     the   sale  of  oil  and  gas  properties  is  not  recognized  unless
     significant oil and gas reserves are involved.

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


<PAGE>
             Southwest Developmental Drilling Fund 92-A, L.P.
                     (a Delaware limited partnership)

                      Notes to Financial Statements

2.   Summary of Significant Accounting Policies - continued

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

     Should the net capitalized costs exceed the estimated present value of
     oil  and  gas reserves, discounted at 10%, such excess costs would  be
     charged  to current expense. As of December 31, 2001, 2000  and  1999,
     the  net capitalized costs did not exceed the estimated present  value
     of oil and gas reserves.

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

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

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

     Gas Balancing
     The  Partnership utilizes the sales method of accounting for  over  or
     under  deliveries of gas.  Under this method, the Partnership  records
     revenues  based  on  the  payments it  has  received  for  sales  from
     purchasers.   As of December 31, 2001, 2000 and 1999, the  Partnership
     was not over or under produced.

     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 assets at December  31,
     2001  and 2000 was $173,234 and $194,608, respectively, less than that
     shown  on the accompanying Balance Sheets in accordance with generally
     accepted accounting principles.

<PAGE>
             Southwest Developmental Drilling Fund 92-A, L.P.
                     (a Delaware limited partnership)

                      Notes to Financial Statements

2.   Summary of Significant Accounting Policies - continued

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

     Investor Partner Units
     As  of  December  31, 2001, 2000 and 1999, there were  1,407  investor
     units outstanding held by 105, 103 and 103 partners.

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

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

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

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

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

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

<PAGE>
             Southwest Developmental Drilling Fund 92-A, L.P.
                     (a Delaware limited partnership)

                      Notes to Financial Statements

3.   Liquidity - Managing General Partner
     The  Managing General Partner has a highly leveraged capital structure
     with  $50.0 million and $123.7 million of principal due in  August  of
     2003  and October of 2004, respectively.  The Managing General Partner
     will incur approximately $17.6 million in interest payments in 2002 on
     its   debt   obligations.  Due  to  the  depressed  commodity   prices
     experienced  during  the last quarter of 2001,  the  Managing  General
     Partner is experiencing difficulty in generating sufficient cash  flow
     to  meet  its  obligations and sustain its operations.   The  Managing
     General Partner is currently in the process of renegotiating the terms
     of  its  various obligations with its creditors and/or  attempting  to
     seek  new  lenders  or equity investors.  Additionally,  the  Managing
     General Partner would consider disposing of certain assets in order to
     meet its obligations.

     There  can  be  no assurance that the Managing General Partner's  debt
     restructuring  efforts  will be successful or that  the  lenders  will
     agree  to  a  course  of action consistent with the  Managing  General
     Partners requirements in restructuring the obligations.  Even if  such
     agreement  is reached, it may require approval of additional  lenders,
     which is not assured.  Furthermore, there can be no assurance that the
     sales  of  assets can be successfully accomplished on terms acceptable
     to  the  Managing  General Partner.  Under current circumstances,  the
     Managing  General  Partner's ability to continue as  a  going  concern
     depends   upon  its  ability  to  (1)  successfully  restructure   its
     obligations  or  obtain additional financing as may be  required,  (2)
     maintain  compliance with all debt covenants, (3) generate  sufficient
     cash  flow to meet its obligations on a timely basis, and (4)  achieve
     satisfactory  levels  of  future earnings.  If  the  Managing  General
     Partner  is unsuccessful in its efforts, it may be unable to meet  its
     obligations making it necessary to undertake such other actions as may
     be  appropriate to preserve asset values.  Upon the occurrence of  any
     event of dissolution by the Managing General Partner, the holders of a
     majority  of limited partnership interests may, by written  agreement,
     elect to continue the business of the Partnership in the Partnership's
     name,  with Partnership property, in a reconstituted partnership under
     the  terms  of the partnership agreement and to designate a  successor
     Managing General Partner.

4.   Commitments and Contingent Liabilities
     The Managing General Partner has the right, but not the obligation, to
     purchase limited partnership units should an investor desire to  sell.
     The  value of the unit is determined by adding the sum of (1)  current
     assets  less liabilities and (2) the present value of the  future  net
     revenues attributable to proved reserves and by discounting the future
     net  revenues  at  a rate not in excess of the prime rate  charged  by
     Nations  Bank,  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, 2001, the Partnership has not been fined, cited or
     notified  of any environmental violations and management is not  aware
     of  any  unasserted  violations which would have  a  material  adverse
     effect upon capital expenditures, earnings or the competitive position
     in the oil and gas industry.

     However,  the  Managing  General Partner does recognize  by  the  very
     nature  of its business, material costs could be incurred in the  near
     term  to  bring the Partnership into total compliance.  The amount  of
     such  future expenditures is not reliably determinable due to  several
     factors,  including the unknown magnitude of possible  contaminations,
     the  unknown timing and extent of the corrective actions which may  be
     required,   the  determination  of  the  Partnership's  liability   in
     proportion  to other responsible parties and the extent to which  such
     expenditures  are recoverable from insurance or indemnifications  from
     prior owners of Partnership's properties.
<PAGE>
             Southwest Developmental Drilling Fund 92-A, L.P.
                     (a Delaware limited partnership)

                      Notes to Financial Statements

5.   Related Party Transactions
     A  significant  portion  of the oil and gas properties  in  which  the
     Partnership  has  an interest are operated by and purchased  from  the
     Managing  General Partner.  As provided for in the operating agreement
     for  each respective oil and gas property in which the Partnership has
     an  interest,  the  operator  is  paid an  amount  for  administrative
     overhead attributable to operating such properties, with such  amounts
     to  Southwest  Royalties,  Inc.  as  operator  approximating  $23,600,
     $22,700  and $22,400 for the years ended December 31, 2001,  2000  and
     1999,  respectively.   In addition, the Managing General  Partner  and
     certain  officers and employees may have an interest in  some  of  the
     properties that the Partnership also participates.

     Certain  subsidiaries  or affiliates of the Managing  General  Partner
     perform  various  oilfield  services  for  properties  in  which   the
     Partnership  owns an interest.  Such services aggregated approximately
     $500,  $3,700 and $2,900 for the years ended December 31,  2001,  2000
     and 1999, respectively.

     Southwest Royalties, Inc., the Managing General Partner, was  paid  an
     administrative  fee  of  $12,000  during  2001,  2000  and  1999   for
     reimbursement   of   indirect  general  and  administrative   overhead
     expenses.

     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.  There were no legal services for December 31, 2001,
     2000 and 1999.

     Receivables  from  Southwest  Royalties, Inc.,  the  Managing  General
     Partner,  of  approximately $29,000 and $41,100 are from oil  and  gas
     production, net of lease operating costs and production taxes,  as  of
     December 31, 2001 and 2000, respectively.

<PAGE>
             Southwest Developmental Drilling Fund 92-A, L.P.
                     (a Delaware limited partnership)

                      Notes to Financial Statements

6.   Major Customers
     No  material portion of the Partnership's business is dependent  on  a
     single purchaser, or a very few purchaser, where the loss of one would
     have  a  material adverse impact on the Partnership.  Three purchasers
     accounted  for  93% of the Partnership's total oil and gas  production
     during  2001: Plains Marketing LP for 58%, Duke Energy Field  Services
     for  21%  and Navajo Refining Company, Inc. for 14%.  Three purchasers
     accounted  for  94% of the Partnership's total oil and gas  production
     during  2000:  Plains Marketing LP for 63%, Navajo  Refining  Company,
     Inc.  for  16%  and Duke Energy Transport and Trad.  for  15%.   Three
     purchasers  accounted for 95% of the Partnership's total oil  and  gas
     production  during  1999: Scurlock Permian LLC for  59%,  Duke  Energy
     Transport and Trad. for 20% and Navajo Refining Company, Inc. for 16%.
     All  purchasers  of  the  Partnership's oil  and  gas  production  are
     unrelated  third  parties.   In  the  event  this  purchaser  were  to
     discontinue  purchasing  the Partnership's  production,  the  Managing
     General  Partner  believes that a substitute purchaser  or  purchasers
     could  be  located without undue delay.  No other purchaser  accounted
     for  an amount equal to or greater than 10% of the Partnership's total
     oil and gas production.

7.   Estimated Oil and Gas Reserves (unaudited)

     The  Partnership's  interest in proved oil  and  gas  reserves  is  as
     follows:

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

     January 1, 1999                                  76,000     168,000

       Production                                   (11,000)    (25,000)
       Revisions of estimates in place                44,000     166,000
                                                     -------     -------
     December 31, 1999                               109,000     309,000

       Production                                   (10,000)    (20,000)
       Revisions of estimates in place                11,000    (47,000)
                                                     -------     -------
     December 31, 2000                               110,000     242,000

       Revisions of estimates in place              (22,000)      26,000
       Production                                    (9,000)    (23,000)
                                                     -------     -------
     December 31, 2001                                79,000     245,000
                                                     =======     =======

     Proved developed reserves -

     December 31, 1999                               109,000     309,000
                                                     =======     =======
     December 31, 2000                               110,000     242,000
                                                     =======     =======
     December 31, 2001                                79,000     245,000
                                                     =======     =======

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

<PAGE>
             Southwest Developmental Drilling Fund 92-A, L.P.
                     (a Delaware limited partnership)

                      Notes to Financial Statements

7.   Estimated Oil and Gas Reserves (unaudited) - continued
     *Ryder  Scott  Petroleum Engineers prepared the  reserve  and  present
     value data for the Partnership's existing properties as of January  1,
     2002.   The  reserve estimates were made in accordance with guidelines
     established by the Securities and Exchange Commission pursuant to Rule
     4-10(a)  of  Regulation  S-X.  Such guidelines  require  oil  and  gas
     reserve  reports  be  prepared under existing economic  and  operating
     conditions with no provisions for price and cost escalation except  by
     contractual arrangements.

     Oil  price  adjustments  were made in the  individual  evaluations  to
     reflect  oil quality, gathering and transportation costs. The  results
     of  the  reserve report as of January 1, 2002 are an average price  of
     $18.90 per barrel.

     Gas  price  adjustments  were made in the  individual  evaluations  to
     reflect  BTU  content,  gathering and  transportation  costs  and  gas
     processing  and shrinkage.  The results of the reserve  report  as  of
     January 1, 2002 are an average price of $2.34 per Mcf.

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

     Unanticipated  depletion, if it occurs, will result in lower  reserves
     than  previously estimated; thus an ultimately lower  return  for  the
     Partnership.  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.  All of the proved reserves are included in the engineering
     reports which evaluate the Partnership's present reserves.

<PAGE>
             Southwest Developmental Drilling Fund 92-A, L.P.
                     (a Delaware limited partnership)

                      Notes to Financial Statements

7.   Estimated Oil & Gas Reserves (unaudited) - continued
     The  standardized measure of discounted future net cash flows relating
     to  proved oil and gas reserves at December 31, 2001, 2000 and 1999 is
     presented below:

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

     Future cash inflows                $  2,059,000  5,290,000 3,328,000
     Production and development costs      1,334,000  2,403,000 1,838,000
                                           ---------  --------- ---------
     Future net cash flows                   725,000  2,887,000 1,490,000
     10% annual discount for estimated
       timing of cash flows                  260,000  1,309,000   603,000
                                           ---------  --------- ---------
     Standardized measure of discounted
       future net cash flows            $    465,000  1,578,000   887,000
                                           =========  ========= =========

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

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

     Sales of oil and gas produced,
       net of production costs          $  (201,000)  (248,000) (147,000)
      Changes in prices and production costs         (1,178,000)    866,000
374,000
     Changes of production rates
       (timing) and others                   177,000   (49,000)   (3,000)
     Revisions of previous
       quantities estimates                 (69,000)     33,000   396,000
     Accretion of discount                   158,000     89,000    24,000
     Discounted future net
       cash flows -
       Beginning of year                   1,578,000    887,000   243,000
                                           ---------  ---------  --------
       End of year                      $    465,000  1,578,000   887,000
                                           =========  =========  ========

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

<PAGE>
             Southwest Developmental Drilling Fund 92-A, L.P.
                     (a Delaware limited partnership)

                      Notes to Financial Statements

8.  Selected Quarterly Financial Results - (unaudited)

                                                 Quarter
                              ----------------------------------------------
                                 First       Second    Third       Fourth
                                 ------     -------    ------      ------
  2001:
     Total revenues           $  124,995     75,628    66,151      66,418
     Total expenses               43,013     50,019    39,776      39,491
     Net income                   81,982     25,609    26,375      26,927
     Net income per limited
      partners unit                51.31      15.81     16.14       16.64

  2000:
     Total revenues           $   90,020     92,567   108,127      81,839
     Total expenses               37,602     37,618    45,451      34,242
     Net income                   52,418     54,949    62,676      47,597
     Net income per limited
      partners unit                32.77      34.52     39.25       29.95


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

None

<PAGE>

                                 Part III

Item 10.  Directors and Executive Officers of the Registrant

Management of the Partnership is provided by Southwest Royalties, Inc.,  as
Managing  General Partner.  The names, ages, offices, positions and  length
of  service of the directors and executive officers of Southwest Royalties,
Inc. are set forth below.  Each director and executive officer serves for a
term  of  one year.  The present directors of the Managing General  Partner
have served in their capacity since the Company's formation in 1983.

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

H. Allen Corey              45          Secretary and Director

Bill E. Coggin                          47     Vice  President  and   Chief
                                        Financial Officer

J. Steven Person            43          Vice President, Marketing

Paul L. Morris              60          Director

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

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

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

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

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


<PAGE>
Key Employees

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

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

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

Item 11.  Executive Compensation

The  Partnership  does not have any directors or executive  officers.   The
executive officers of the Managing General Partner do not receive any  cash
compensation,  bonuses, deferred compensation or compensation  pursuant  to
any  type  of  plan,  from the Partnership.  The Managing  General  Partner
received  $12,000 during 2001, 2000 and 1999 as an administrative  fee  for
reimbursement of indirect general and administrative expenses.

Item 12.  Security Ownership of Certain Beneficial Owners and Management

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

The  Managing  General Partner owns an 11 percent interest  as  a  Managing
General Partner. Through prior purchases, the Managing General Partner also
owns  5.0  limited  partner units, or .4% limited  partner  interest.   The
Managing  General  Partner  total  percentage  interest  ownership  in  the
Partnership is 11.3%.

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.

                                                  Amount and
                                                   Nature of      Percent
                     Name and Address of           Beneficial        of
 Title of Class        Beneficial Owner            Ownership       Class
-------------------  ---------------------------  ---------------  -------
Limited Partnership  Southwest Royalties, Inc.    Directly Owns       .4%
 Interest            Managing General Partner     5.0 Units
                     407 N. Big Spring Street
                     Midland, TX  79701

Limited Partnership  H. H. Wommack, III           Indirectly Owns     .4%
 Interest            Chairman of the Board,       5.0 Units
                     President, CEO, Treasurer
                     and Director of Southwest
                     Royalties, Inc., the
                     Managing General Partner
                     407 N. Big Spring Street
                     Midland, TX  79701

Limited Partnership  H. Allen Corey               Indirectly Owns     .4%
 Interest            Secretary and Director of    5.0 Units
                     Southwest Royalties, Inc.,
                     the Managing General
                     Partner
                     633 Chestnut Street
                     Chattanooga, TN  37450-1800

Limited Partnership  Bill E. Coggin               Indirectly Owns     .4%
 Interest            Vice President and CFO of    5.0 Units
                     Southwest Royalties, Inc.,
                     the Managing General
                     Partner
                     407 N. Big Spring Street
                     Midland, TX  79701

Limited Partnership  J. Steven Person             Indirectly Owns     .4%
 Interest            Vice President, Marketing of 5.0 Units
                     Southwest Royalties, Inc.,
                     the Managing General
                     Partner
                     407 N. Big Spring Street
                     Midland, TX  79701

Limited Partnership  Paul L. Morris               Indirectly Owns     .4%
 Interest            Director, of Southwest       5.0 Units
                     Royalties, Inc., the
                     Managing General Partner
                     407 N. Big Spring Street
                     Midland, TX  79701


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

<PAGE>
Item 13.  Certain Relationships and Related Transactions

In 2001, the Managing General Partner received $12,000 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 $23,600 for administrative  overhead
attributable to operating such properties during 2001.

Certain  subsidiaries or affiliates of the Managing General Partner perform
various  oilfield services for properties in which the Partnership owns  an
interest.  Such services aggregated approximately $500 for the period ended
December 31, 2001.

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 Sheet
                  Statement of Changes in Partners' Equity
                  Statement of Cash Flows
                  Notes to Financial Statements

                      (2)          Schedules  I  through XIII  are  omitted
                  because  they are not applicable, or because the required
                  information is shown in the financial statements  or  the
                  notes thereto.

             (3)  Exhibits:

                                      Exhibit 4(a):  Certificate of Limited
                                 Partnership   of  Southwest  Developmental
                                 Drilling  Fund 92-A, L.P.,  dated  May  5,
                                 1992   (Incorporated  by  reference   from
                                 Partnership's  Form 10-K  for  the  fiscal
                                 year ended December 31, 1992).

                                       Exhibit 4(b):  Agreement of  Limited
                                 Partnership   of  Southwest  Developmental
                                 Drilling Fund 92-A, L.P. dated May 5, 1992
                                 (Incorporated     by    reference     from
                                 Partnership's  Form 10-K  for  the  fiscal
                                 year ended December 31, 1992).

                                       Exhibit  4(c):  First  Amendment  to
                                 Amended   and   Restated  Certificate   of
                                 Limited     Partnership    of    Southwest
                                 Developmental  Drilling Fund  92-A.  L.P.,
                                 dated    as    of   February   22,    1993
                                 (Incorporated  by reference  from  Partner
                                 ship's Form 10-K for the fiscal year ended
                                 December 31, 1993).

                                       Exhibit  4(d):  Second Amendment  to
                                 Amended   and   Restated  Certificate   of
                                 Limited     Partnership    of    Southwest
                                 Developmental  Drilling Fund  92-A.  L.P.,
                                 dated  as  of March 26, 1993 (Incorporated
                                 by  reference from Partnership's Form 10-K
                                 for  the  fiscal year ended  December  31,
                                 1993).

                                       Exhibit  4(e):  Second  Amended  and
                                 Restated     Certificate    of     Limited
                                 Partnership   of  Southwest  Developmental
                                 Drilling  Fund  92-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

                  Reports on Form 8-K

                  (b)            No report on Form 8-K was filed during the
                  quarter ended December 31, 2001.

<PAGE>
                                Signatures


Pursuant  to  the  requirements of Section 13 or 15(d)  of  the  Securities
Exchange  Act  of 1934, the Partnership has duly caused this report  to  be
signed on its behalf by the undersigned, thereunto duly authorized.


                          Southwest Developmental Drilling Fund 92-A, L.P.,
                          a Delaware limited partnership


                                        By:    Southwest  Royalties,  Inc.,
                                 Managing
                                 General Partner


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


                          Date:    March 29, 2002


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


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


Date:  March 29, 2002


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


Date:  March 29, 2002

<PAGE>