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

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

For the fiscal year ended December 31, 2002

                                    OR

[ ]    Transition  report pursuant to Section 13 or 15(d) of the Securities
       Exchange Act of 1934

For the transition period from                      to

Commission File Number 33-38511

             Southwest Developmental Drilling Fund 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  41.   The  exhibit
index is found on page 39.

<PAGE>
                            Table of Contents

Item                                                                   Page

                                  Part I

 1.  Business                                                            3

 2.  Properties                                                          5

 3.  Legal Proceedings                                                   6

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

                                 Part II

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

 6.  Selected Financial Data                                             8

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

 8.  Financial Statements and Supplementary Data                        16

 9.  Changes in and Disagreements with Accountants
     on Accounting and Financial Disclosure                             30

                                 Part III

10.  Directors and Executive Officers of the Registrant                 31

11.  Executive Compensation                                             33

12.  Security Ownership of Certain Beneficial Owners and
     Management                                                         33

13.  Certain Relationships and Related Transactions                     34

                                 Part IV

14.  Exhibits, Financial Statement Schedules, and Reports
     on Form 8-K                                                        35

     Signatures                                                         36

<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  82  individuals,  together  with   certain
independent  consultants  used  on an "as needed"  basis,  perform  various
services on behalf of the Partnership, including the selection of 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>

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

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

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

            Oil       Gas
            ----      ----
  2002      75%       25%
  2001      72%       28%
  2000      78%       22%

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
95%  of  the Partnership's total oil and gas production during 2002: Plains
Marketing  LP  for 59%, Duke Energy Field Services LP for  19%  and  Navajo
Refining Company, Inc. for 17%.  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%.   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,
2002,  there were 82 individuals directly employed by the Managing  General
Partner in various capacities.

Item 2.   Properties

In  determining  whether an interest in a particular 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.

As  of December 31, 2002, 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 have not been any significant changes in properties during 2002, 2001
and 2000.

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

                  Date
                Purchased    No. of    Proved Reserves*
Name      and      and       Wells      Oil       Gas
Location        Interest               (bbls)    (mcf)
-------------  -----------  --------  --------  --------
------------     ------       ---      ------    ------
Mobil  Fee  G   12/92 at       1       28,000    24,000
#1
Ward  County,     100%
Texas
                 working
                interest

Mobil  Fee  H   12/92 at       1       45,000   167,000
#1
Ward  County,     100%
Texas
                 working
                interest

*Ryder Scott Company, L.P. prepared the reserve and present value data  for
the  Partnership's existing properties as of January 1, 2003.  The  reserve
estimates  were  made  in  accordance with guidelines  established  by  the
Securities and Exchange Commission pursuant to Rule 4-10(a) of Regulation S-
X.   Such guidelines require oil and gas reserve reports be prepared  under
existing economic and operating conditions with no provisions for price and
cost escalation except by contractual arrangements.

Oil  price  adjustments were made in the individual evaluations to  reflect
oil quality, gathering and transportation costs. The results of the reserve
report as of January 1, 2003 are an average price of $29.67 per barrel.

Gas  price  adjustments were made in the individual evaluations to  reflect
BTU  content,  gathering and transportation costs and  gas  processing  and
shrinkage.  The results of the reserve report as of January 1, 2003 are  an
average price of $4.49 per Mcf.

As  also discussed in Part II, Item 7, Management's Discussion and Analysis
of  Financial Condition and Results of Operations, oil and gas prices  were
subject to frequent changes in 2002.

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

Unanticipated  depletion, if it occurs, will result in lower reserves  than
previously  estimated; thus an ultimately lower return for the Partnership.
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 2002 through the solicitation of proxies or otherwise.

<PAGE>
                                 Part II


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

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

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

Number of Limited and General Partner Interest Holders
As of December 31, 2002, 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  2002,  quarterly  distributions were made totaling  $112,957,  with
$100,532  distributed to the investor partners and $12,425 to the  Managing
General  Partners.  For the year ended December 31, 2002, distributions  of
$71.45  per  investor  partner unit were made, based  upon  1,407  investor
partner units outstanding.  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.

<PAGE>
Item 6.   Selected Financial Data

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

                                 Year ended December 31,
                      ---------------------------------------------
                                           ---
                        2002      2001     2000     1999      1998
                        ----      ----     ----     ----      ----

Revenues            $ 275,362   333,192  372,553  249,965   201,370

Net income (loss)     120,581   160,893  217,640  112,767   (331,847
                                                            )

Partners' share of
net
 income (loss):

Managing General
 Partner              14,804    20,338   25,590   14,274    6,863

Investor partners     105,777   140,555  192,050  98,493    (338,710
                                                            )

Investor partners'
net
 income (loss) per     75.18
unit                            99.90    136.50   70.00     (240.73)

Investor partners'
cash
 distributions per     71.45
unit                            132.08   142.10   53.77     58.32

Total assets        $ 238,993   231,369  279,195  286,195   258,508

<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, which have approximated  7% per year.

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

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

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

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

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

<PAGE>
Results of Operations

A.  General Comparison of the Years Ended December 31, 2002 and 2001

The  following  table  provides certain information  regarding  performance
factors for the years ended December 31, 2002 and 2001:

                              Year Ended      Percenta
                                                 ge
                             December 31,     Increase
                            2002      2001    (Decreas
                                                 e)
                            ----      ----    --------
                                                  -
Average price per      $   24.56                (3%)
barrel of oil                       25.25
Average price per mcf  $    3.05                (25%)
of gas                              4.08
Oil production in         8,410     9,460       (11%)
barrels
Gas production in mcf     22,000    23,000      (4%)
Gross oil and gas      $  273,741   332,643     (18%)
revenue
Net oil and gas        $  150,469   200,862     (25%)
revenue
Partnership            $  112,957   208,798     (46%)
distributions
Limited partner        $  100,532   185,830     (46%)
distributions
Per unit distribution  $   71.45                (46%)
to limited partners                 132.08
Number of limited         1,407     1,407
partner units

Revenues

The  Partnership's oil and gas revenues decreased to $273,741 from $332,643
for the years ended December 31, 2002 and 2001, respectively, a decrease of
18%.   The  principal factors affecting the comparison of the  years  ended
December 31, 2002 and 2001 are as follows:

1.  The  average  price  for a barrel of oil received  by  the  Partnership
    decreased  during the year ended December 31, 2002 as compared  to  the
    year ended December 31, 2001 by 3%, or $.69 per barrel, resulting in  a
    decrease of approximately $5,800 in revenues. Oil sales represented 75%
    of  total oil and gas sales during the year ended December 31, 2002  as
    compared to 72% during the year ended December 31, 2001.

    The  average  price  for  an  mcf of gas received  by  the  Partnership
    decreased during the same period by 25%, or $1.03 per mcf, resulting in
    a decrease of approximately $22,700 in revenues.

    The  total  decrease in revenues due to the change in  prices  received
    from oil and gas production is approximately $28,500.  The market price
    for  oil  and gas has been extremely volatile over the past decade  and
    management  expects a certain amount of volatility to continue  in  the
    foreseeable future.

<PAGE>

2.   Oil production decreased approximately 1,050 barrels or 11% during the
   year ended December 31, 2002 as compared to the year ended December  31,
   2001, resulting in a decrease of approximately $26,500 in revenues.

    Gas  production decreased approximately 1,000 mcf or 4% during the same
    period, resulting in a decrease of approximately $4,100 in revenues.

    The  total  decrease  in revenues due to the change  in  production  is
    approximately $30,600.

Costs and Expenses

Total  costs and expenses decreased to $154,781 from $172,299 for the years
ended  December 31, 2002 and 2001, respectively, a decrease  of  10%.   The
decrease  is  the  result  of  lower lease operating  costs  and  depletion
expense,  partially  offset  by  an  increase  general  and  administrative
expense.

1.    Lease  operating  costs  and  production  taxes  were  6%  lower,  or
   approximately  $8,500 less during the year ended December  31,  2002  as
   compared to the year ended December 31, 2001.

2.  General and administrative costs consist of independent accounting  and
    engineering  fees,  computer services, postage,  and  Managing  General
    Partner personnel costs. General and administrative costs increased  6%
    or  approximately  $1,000 during the year ended December  31,  2002  as
    compared to the year ended December 31, 2001.

3.  Depletion expense decreased to $14,000 for the year ended December  31,
    2002  from  $24,000  for the same period in 2001.   This  represents  a
    decrease  of 42%.  Prior to October 1, 2002, the Partnership calculated
    depletion of oil and gas properties under the units of revenue  method.
    The  Partnership  changed  methods of  estimating  depletion  effective
    October  1,  2002  to  the units of production method.   The  units  of
    production method is more predominantly used throughout the oil and gas
    industry  and  will allow the Partnership to more closely align  itself
    with  its  peers.  This change in estimate had no impact  on  depletion
    expense for the fourth quarter.

    The  major  factor  in  the decrease in depletion expense  between  the
    comparative periods was the increase in the price of oil and  gas  used
    to determine the Partnership's reserves for January 1, 2003 as compared
    to  2002,  and  the decrease in oil and gas revenues  received  by  the
    Partnership during 2002 as compared to 2001.



<PAGE>


Results of Operations

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

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

                                Year Ended      Percenta
                                                   ge
                               December 31,     Increase
                              2001      2000    (Decreas
                                                   e)
                              ----      ----    --------
                                                   -
Average price per        $    25.25              (15%)
barrel of oil                         29.73
Average price per mcf    $     4.08                3%
of gas                                3.98
Oil production in           9,460     9,800       (3%)
barrels
Gas production in mcf       23,000    20,200      14%
Gross oil and gas        $  332,643   371,824    (11%)
revenue
Net oil and gas revenue  $  200,862   247,853    (19%)
Partnership              $  208,798   224,640     (7%)
distributions
Limited partner          $  185,830   199,930     (7%)
distributions
Per unit distribution    $   132.08               (7%)
to limited partners                   142.10
Number of limited           1,407     1,407
partner units

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  in  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>


C.   Revenue and Distribution Comparison

Partnership net income for the years ended December 31, 2002, 2001 and 2000
was  $120,581, $160,893 and $217,640, respectively.  Excluding the  effects
of depreciation, depletion and amortization, net income for the years ended
December  31,  2002, 2001 and 2000, would have been $134,581, $184,893  and
$232,640, respectively.  Correspondingly, Partnership distributions for the
years  ended  December 31, 2002, 2001 and 2000 were $112,957, $208,798  and
$224,640, respectively.  These differences are indicative of the changes in
oil and gas prices, production and property during 2002, 2001 and 2000.

The  sources  for  the  2002 distributions of $112,957  were  oil  and  gas
operations  of  approximately  $124,000 and  the  change  in  oil  and  gas
properties   of   approximately  $(10),  resulting  in  excess   cash   for
contingencies  or  subsequent distributions.   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.

Total  distributions during the year ended December 31, 2002 were  $112,957
of  which $100,532 was distributed to the investor partners and $12,425  to
the  Managing  General  Partners.  The per unit  distribution  to  investor
partners during the same period was $71.45.  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.

Since  inception of the Partnership, cumulative monthly cash  distributions
of  $1,699,310  have been made to the partners.  As of December  31,  2002,
$1,512,762 or $1,075.17 per investor partner unit, has been distributed  to
the  investor  partners, representing a 100% return of  capital  and  a  8%
return on capital contributed.

Liquidity and Capital Resources

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

Cash flows provided by operating activities were approximately $124,000  in
2002 compared to $197,000 in 2001 and approximately $228,800 in 2000.   The
primary  source  of  the  2002  cash flow  from  operating  activities  was
profitable operations.

Cash  flows  (used in) provided by investing activities were  approximately
$(10)  in 2002 compared to $1,400 in 2001 and approximately $(75) in  2000.
The  primary  use of the 2002 cash flow from investing activities  was  the
change in oil and gas properties.

Cash flows used in financing activities were approximately $113,000 in 2002
compared to $208,700 in 2001 and approximately $224,600 in 2000.  The  only
use in the 2002 financing activities was the distributions to partners.

As  of  December 31, 2002, the Partnership had $67,000 in working  capital.
The  Managing  General Partner knows of no unusual contractual commitments.
Although  the  partnership  held many long-lived properties  at  inception,
because  of  the  restrictions  on  property  development  imposed  by  the
partnership  agreement, the Managing General Partner  anticipates  that  at
some  point in the near future, the partnership will need to be liquidated.
Maintenance  of  properties  and  administrative  expenses  are  increasing
relative to production.  As the properties continue to deplete, maintenance
of  properties and administrative costs as a percentage of production  will
continue to increase.

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

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

<PAGE>
Liquidity - Managing General Partner

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

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

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

Recent Accounting Pronouncements

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

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk

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

<PAGE>
Item 8.  Financial Statements and Supplementary Data

                      Index to Financial Statements

                                                                       Page

Independent Auditors Report                                             17

Balance Sheets                                                          18

Statement of Operations                                                 19

Statement of Changes in Partners' Equity                                20

Statements of Cash Flows                                                21

Notes to Financial Statements                                           22

<PAGE>









                        INDEPENDENT AUDITORS REPORT

The Partners
Southwest Developmental Drilling
 Fund 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, 2002  and  2001,
and  the related statements of operations, changes in partners' equity  and
cash  flows  for each of the years in the three year period ended  December
31,  2002.   These  financial  statements are  the  responsibility  of  the
Partnership's management.  Our responsibility is to express an  opinion  on
these financial statements based on our audits.

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

In  our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Southwest Developmental
Drilling Fund 92-A as of December 31, 2002 and 2001 and the results of  its
operations  and  its cash flows for each of the years  in  the  three  year
period  ended  December  31, 2002 in conformity with accounting  principles
generally accepted in the United States of America.








                                                  KPMG LLP



Midland, Texas
March 14, 2003

<PAGE>

             Southwest Developmental Drilling Fund 92-A, L.P.
                     (a Delaware limited partnership)
                              Balance Sheets
                        December 31, 2002 and 2001


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

Current assets:
 Cash and cash equivalents    $  27,569    16,508
  Receivable  from  Managing     39,532    28,977
General Partner
                                 --------  --------
                                 ----      ----
   Total current assets          67,101    45,485
                                 --------  --------
                                 ----      ----
Oil  and  gas  properties  -
using the full-
 cost method of accounting       1,313,13  1,313,12
                                 2         4
       Less      accumulated
depreciation,
         depletion       and     1,141,24  1,127,24
amortization                     0         0
                                 --------  --------
                                 ----      ----
      Net   oil   and    gas     171,892   185,884
properties
                                 --------  --------
                                 ----      ----
                              $  238,993   231,369
                                 =======   =======

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

Current     liability      -  $  79        79
distribution payable
                                 --------  --------
                                 ----      ----

Partners' equity:
 Managing General Partner        30,303    27,924
 Investor partners               208,611   203,366
                                 --------  --------
                                 ----      ----
   Total partners' equity        238,914   231,290
                                 --------  --------
                                 ----      ----
                              $  238,993   231,369
                                 =======   ========
                                           =












                  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, 2002, 2001 and 2000


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

Oil and gas sales             $  273,741   332,643   371,824
Interest     income     from     92        549       729
operations
Miscellaneous                    1,529     -         -
                                 --------  --------  --------
                                 --        --        --
                                 275,362   333,192   372,553
                                 --------  --------  --------
                                 --        --        --

Expenses
------------

Production                       123,272   131,781   123,971
General and administrative       17,509    16,518    15,942
Depreciation, depletion  and     14,000    24,000    15,000
amortization
                                 --------  --------  --------
                                 --        --        --
                                 154,781   172,299   154,913
                                 --------  --------  --------
                                 --        --        --
Net income                    $  120,581   160,893   217,640
                                 ======    ======    ======
Net income allocated to:

 Managing General Partner     $  14,804    20,338    25,590
                                 ======    ======    ======
 Investor partners            $  105,777   140,555   192,050
                                 ======    ======    ======
  Per investor partner unit   $    75.18
                                           99.90     136.50
                                 ======    ======    ======
















                  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, 2002, 2001 and 2000


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

 Net income                      14,804    105,777   120,581

 Distributions                   (12,425)  (100,532  (112,957
                                           )         )
                                 --------  --------  --------
                                 --        ---       ---
Balance at December 31, 2002  $  30,303    208,611   238,914
                                 ======    ======    ======























                  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, 2002, 2001 and 2000

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

  Cash received from oil and  $  257,856   353,274   361,584
gas sales
   Cash   paid  to  Managing
General Partner
   for  administrative  fees
and general
      and     administrative     (135,451  (156,854  (133,476
overhead                         )         )         )
 Interest received               92        549       729
 Miscellaneous settlement        1,529     -         -
                                 --------  --------  --------
                                 --        --        --
    Net  cash  provided   by     124,026   196,969   228,837
operating activities
                                 --------  --------  --------
                                 --        --        --
Cash  flows  from  investing
activities:

  Addition  to oil  and  gas     (8)       -         (75)
properties
 Sale of equipment               -         1,393     -
                                 --------  --------  --------
                                 --        --        --
    Net   cash   (used   in)
provided by
   investing activities          (8)       1,393     (75)
                                 --------  --------  --------
                                 --        --        --
Cash flows used in financing
activities:

 Distributions to partners       (112,957  (208,719  (224,640
                                 )         )         )
                                 --------  --------  --------
                                 --        --        --
Net  increase (decrease)  in
cash and cash
 equivalents                     11,061    (10,357)  4,122

Beginning of period              16,508    26,865    22,743
                                 --------  --------  --------
                                 --        --        --
End of period                 $  27,569    16,508    26,865
                                 ======    ======    ======
Reconciliation of net income
to net
  cash provided by operating
activities:

Net income                    $  120,581   160,893   217,640

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

 Depreciation, depletion and     14,000    24,000    15,000
amortization
   (Increase)  decrease   in     (15,885)  20,631    (10,240)
receivables
   Increase  (decrease)   in     5,330     (8,555)   6,437
payables
                                 --------  --------  --------
                                 --        --        --
Net    cash   provided    by  $  124,026   196,969   228,837
operating activities
                                 ======    ======    ======


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

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

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

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

2.   Summary of Significant Accounting Policies

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

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


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

                      Notes to Financial Statements

2.   Summary of Significant Accounting Policies - continued

     Oil and Gas Properties - continued
     Should the net capitalized costs exceed the estimated present value of
     oil  and  gas reserves, discounted at 10%, such excess costs would  be
     charged  to current expense.  In applying the units of revenue  method
     for  the  years ended December 31, 2001, 2000 and for the nine  months
     ended  September 30, 2002, we have not excluded royalty and net profit
     interest  payments from gross revenues as all of our royalty  and  net
     profit  interests have been purchased and capitalized to the depletion
     basis  of our proved oil and gas properties.  As of December 31, 2002,
     2001  and 2000, the net capitalized costs did not exceed the estimated
     present value of oil and gas reserves.

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

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

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

     Revenue Recognition
     We  recognize  oil  and gas sales when delivery to the  purchaser  has
     occurred  and title has transferred.  This occurs when production  has
     been delivered to a pipeline or transport vehicle.

     Gas Balancing
     The  Partnership utilizes the sales method of accounting for  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, 2002, 2001 and 2000, 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,
     2002  and 2001 was $161,628 and $173,234, 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, 2002, 2001 and 2000, there were  1,407  investor
     units outstanding held by 105, 105 and 103 partners.

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

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

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

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


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

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

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

4.   Commitments and Contingent Liabilities
     The Managing General Partner has the right, but not the obligation, to
     purchase limited partnership units should an investor desire to  sell.
     The  value of the unit is determined by adding the sum of (1)  current
     assets  less liabilities and (2) the present value of the  future  net
     revenues attributable to proved reserves and by discounting the future
     net  revenues  at  a rate not in excess of the prime rate  charged  by
     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.

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

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

     As  of December 31, 2002, the Partnership has not been fined, cited or
     notified  of any environmental violations and management is not  aware
     of  any  unasserted  violations, which would have a  material  adverse
     effect upon capital expenditures, earnings or the competitive position
     in the oil and gas industry.

     However,  the  Managing  General Partner does recognize  by  the  very
     nature  of its business, material costs could be incurred in the  near
     term  to  bring the Partnership into total compliance.  The amount  of
     such  future expenditures is not reliably determinable due to  several
     factors,  including the unknown magnitude of possible  contaminations,
     the  unknown timing and extent of the corrective actions which may  be
     required,   the  determination  of  the  Partnership's  liability   in
     proportion  to other responsible parties and the extent to which  such
     expenditures  are recoverable from insurance or indemnifications  from
     prior owners of Partnership's properties.
<PAGE>
             Southwest Developmental Drilling Fund 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  $23,700,
     $23,600  and $22,700 for the years ended December 31, 2002,  2001  and
     2000,   respectively.    The   amounts  for  administrative   overhead
     attributable  to  operating  the  partnership  properties  have   been
     deducted from gross oil and gas revenues in the determination  of  net
     profit  interest.      In addition, the Managing General  Partner  and
     certain  officers and employees may have an interest in  some  of  the
     properties that the Partnership also participates.

     Certain  subsidiaries  or affiliates of the Managing  General  Partner
     perform  various  oilfield  services  for  properties  in  which   the
     Partnership  owns an interest.  Such services aggregated approximately
     $0,  $500  and $3,700 for the years ended December 31, 2002, 2001  and
     2000,  respectively.  The amounts for oilfield services performed  for
     the  partnership  by affiliates of the Managing General  Partner  have
     been deducted from gross oil and gas revenues in the determination  of
     net profit interest

     Southwest Royalties, Inc., the Managing General Partner, was  paid  an
     administrative  fee  of  $12,000  during  2002,  2001  and  2000   for
     reimbursement   of   indirect  general  and  administrative   overhead
     expenses.   The  administrative  fees  are  included  in  general  and
     administrative expense on the statement of operations.


     Receivables  from  Southwest  Royalties, Inc.,  the  Managing  General
     Partner,  of  approximately $39,500 and $29,000 are from oil  and  gas
     production, net of lease operating costs and production taxes,  as  of
     December 31, 2002 and 2001, 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  95% of the Partnership's total oil and gas  production
     during  2002: Plains Marketing LP for 59%, Duke Energy Field  Services
     LP for19% and Navajo Refining Company, Inc. for 17%.  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%.   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       Gas
                               (bbls)    (mcf)
                              --------  --------
                                 --        -
Proved     developed     and
undeveloped reserves -

January 1, 2000               109,000   309,000

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

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

 Production                   17,000    13,000
  Revisions of estimates  in  (8,000)   (22,000)
place
                              --------  --------
                              --        --
December 31, 2002             88,000    236,000
                              ======    ======

Proved developed reserves -

December 31, 2000             110,000   242,000
                              ======    ======
December 31, 2001             79,000    245,000
                              ======    ======
December 31, 2002             88,000    236,000
                              ======    ======

     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 Company, L.P. prepared the reserve and present value data
     for  the Partnership's existing properties as of January 1, 2003.  The
     reserve  estimates were made in accordance with guidelines established
     by  the Securities and Exchange Commission pursuant to Rule 4-10(a) of
     Regulation  S-X.  Such guidelines require oil and gas reserve  reports
     be  prepared under existing economic and operating conditions with  no
     provisions  for  price  and  cost  escalation  except  by  contractual
     arrangements.

     Oil  price  adjustments  were made in the  individual  evaluations  to
     reflect  oil quality, gathering and transportation costs. The  results
     of  the  reserve report as of January 1, 2003 are an average price  of
     $29.67 per barrel.

     Gas  price  adjustments  were made in the  individual  evaluations  to
     reflect  BTU  content,  gathering and  transportation  costs  and  gas
     processing  and shrinkage.  The results of the reserve  report  as  of
     January 1, 2003 are an average price of $4.49 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, 2002, 2001 and 2000 is
     presented below:

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

Future cash inflows           $  3,682,00  2,059,00  5,290,00
                                 0         0         0
Production  and  development     1,945,00  1,334,00  2,403,00
costs                            0         0         0
                                 --------  --------  --------
                                 ----      ----      ----
Future net cash flows            1,737,00  725,000   2,887,00
                                 0                   0
10%   annual  discount   for
estimated
 timing of cash flows            680,000   260,000   1,309,00
                                                     0
                                 --------  --------  --------
                                 ----      ----      ----
Standardized   measure    of
discounted
 future net cash flows        $  1,057,00  465,000   1,578,00
                                 0                   0
                                 =======   =======   =======

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

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

Sales   of   oil   and   gas
produced,
 net of production costs      $  (150,000  (201,000  (248,000
                                 )         )         )
Changes   in   prices    and     549,000   (1,178,0  866,000
production costs                           00)
Changes of production rates
 (timing) and others             (12,000)  177,000   (49,000)
Revisions of previous
 quantities estimates            159,000   (69,000)  33,000
Accretion of discount            46,000    158,000   89,000
Discounted future net
 cash flows -
Beginning of year                465,000   1,578,00  887,000
                                           0
                                 --------  --------  --------
                                 ----      ----      ----
End of year                   $  1,057,00  465,000   1,578,00
                                 0                   0
                                 =======   =======   =======

     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
                             ------   -------    ------    ------
2002:
 Total revenues          $  53,515    70,937    76,111    74,799
 Total expenses             36,583    34,294    40,738    43,166
 Net income                 16,932    36,643    35,373    31,633
 Net income per limited
  partners unit               10.48
                                      22.87     22.14     19.69

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


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

None

<PAGE>

                                 Part III

Item 10.  Directors and Executive Officers of the Registrant

Management of the Partnership is provided by Southwest Royalties, Inc.,  as
Managing  General Partner.  The names, ages, offices, positions and  length
of  service of the directors and executive officers of Southwest Royalties,
Inc. are set forth below.  Each director and executive officer serves for a
term of one year.

         Name               Age               Position
H. H. Wommack, III          47      Chairman   of   the    Board,
                                    President, Director
                                    and Chief Executive Officer
James N. Chapman(1)         40      Director
William P. Nicoletti(2)     57      Director
Joseph J. Radecki,  Jr.     44      Director
(2)
Richard D. Rinehart(1)      67      Director
John M. White(2)            46      Director
Herbert  C. Williamson,     54      Director
III(1)
Bill E. Coggin              48      Executive Vice President  and
                                    Chief Financial Officer
J. Steven Person            44      Vice President, Marketing

(1)  Member of the Compensation Committee

(2)  Member of the Audit Committee

H.  H.  Wommack, III has served as Chairman of the Board, President,  Chief
Executive Officer and a director since Southwest's founding in 1983.  Since
1997  Mr.  Wommack  has  served as President, Chief Executive  Officer  and
Chairman of SRH, Southwest's former parent and current holder of 10% of its
voting share capital.  Since 1997 Mr. Wommack has served as chairman of the
board  of  directors  of  Midland Red Oak Realty,  Inc.   From  1997  until
December 2000, Mr. Wommack served as chairman of the board of directors  of
Basic  Energy Services, Inc. and since December 2000 has continued to serve
on Basic's board of directors.  Prior to Southwest's formation, Mr. Wommack
was  a  self-employed  independent oil and  gas  producer  engaged  in  the
purchase  and sale of royalty and working interests in oil and  gas  leases
and  the  drilling of wells.  Mr. Wommack graduated from the University  of
North  Carolina  at  Chapel  Hill and received  his  law  degree  from  the
University of Texas.

James  N.  Chapman  has served as a director since  April  19,  2002.   Mr.
Chapman has been involved in the investment banking industry for 18  years,
presently  acting  as  a capital markets and strategic planning  consultant
with  private and public companies across a range of industries,  including
metals,  mining, manufacturing, aerospace, airline, service and healthcare.
Prior  to  establishing  an independent consulting  practice,  Mr.  Chapman
worked  for  The Renco Group, Inc., a multi-billion private corporation  in
New  York,  for  which Mr. Chapman developed and implemented financing  and
merger  and  acquisitions  strategies  for  Renco's  diverse  portfolio  of
companies.   Prior  to  Renco,  Mr. Chapman was  a  founding  principal  of
Fieldstone Private Capital Group, a capital markets advisory firm  that  he
joined  upon  its inception in August 1990.   Prior to joining  Fieldstone,
Mr.  Chapman worked for Bankers Trust Company for six years, most  recently
in  the  BT Securities Capital Markets area.  Mr. Chapman received  an  MBA
degree with distinction from the Amos Tuck School at Dartmouth College  and
was  elected  an  Edward Tuck Scholar.   He received  his  BA  degree  with
distinction magna cum laude, at Dartmouth College, was elected to Phi  Beta
Kappa and was a Rufus Choate Scholar.

William  P. Nicoletti has served as a director since April 19,  2002.   Mr.
Nicoletti  is Managing Director of Nicoletti & Company Inc., an  investment
banking and financial advisory firm.  He was formerly a senior officer  and
head  of  the  Energy Investment Banking Groups of E. F. Hutton  &  Company
Inc.,  Paine  Webber,  Incorporated  and  McDonald  Investments  Inc.   Mr.
Nicoletti  is  Chairman  of  the  board  of  directors  of  Russell-Stanley
Holdings, Inc., a manufacturer and marketer of steel and plastic industrial
containers.  He is a director of Mark WestEnergy Partners, L.P., a business
engaged   in  the  gathering  and  processing  of  natural  gas   and   the
fractionation and storage of natural gas liquids.  Mr. Nicoletti is also  a
Director  and  Chairman of the Audit Committee of Star Gas Partners,  L.P.,
the  nation's largest retail distributor of home heating oil  and  a  major
retail  distributor of propane gas.  Mr. Nicoletti is a graduate  of  Seton
Hall  University  and  received  an  MBA degree  from  Columbia  University
Graduate School of Business.

<PAGE>

Joseph J. Radecki, Jr. has served as a director since April 19, 2002.   Mr.
Radecki is currently a Managing Director in the Leveraged Finance Group  of
CIBC  World  Markets  where he is principally responsible  for  the  firm's
financial restructuring and distressed situation advisory practice.   Prior
to  joining CIBC World Markets, Mr. Radecki was an Executive Vice President
and  Director of the Financial Restructuring Group of Jefferies &  Company,
Inc.  from 1990 to 1998.  From 1983 until 1990, Mr. Radecki was First  Vice
President  in  the  International Capital Markets Group at  Drexel  Burnham
Lambert,  Inc.,  where  he  specialized  in  financial  restructurings  and
recapitalizations.   Over the past fourteen years,  Mr.  Radecki  has  been
integrally involved in over 120 transactions totaling nearly $50 billion in
recapitalized  securities.  Mr. Radeki currently serves as  a  Director  of
Wherehouse  Entertainment, Inc., a music and video specialty retailer,  and
RBX  Corporation,  a  manufacturer of rubber and  plastic  foam  and  other
polymer  products.  He has previously served as Chairman of  the  Board  of
American Rice, Inc., an international rice miller and marketer, as a member
of  the Board of Directors of Service America Corporation, a national  food
service  management firm, Bucyrus International, Inc., a  mining  equipment
manufacturer,  and ECO-Net, a non-profit engineering related network  firm.
Mr.  Radecki  graduated magna cum laude in 1980 from Georgetown  University
with a B.A. in Government.

Richard  D.  Rinehart has served as a director since April 19,  2002.   Mr.
Rinehart is a founding principal of PetroCap, Inc. and president of Kestrel
Resources,  Inc.   PetroCap, Inc. provides investment and merchant  banking
services  to  a  variety  of clients active in the oil  and  gas  industry.
Kestrel Resources, Inc. is a privately owned oil and gas operating company.
He  served  as Director of Coopers & Lybrand's Energy Systems and  Services
Division prior to the founding of Kestrel Resources, Inc. in 1992. Prior to
joining  Coopers & Lybrand, he was chief executive officer/founder of  Dawn
Information  Resources,  Inc., formed in 1986 and  acquired  by  Coopers  &
Lybrand  in  early  1991.  Mr. Rinehart served as CEO  of  Terrapet  Energy
Corporation during the period 1982 through 1986. Prior to the formation  of
Terrapet in 1982, he was employed as President of the Terrapet Division  of
E.I.  DuPont de Nemours and Company. Before its acquisition by  DuPont,  he
served  as  CEO and President of Terrapet Corp., a privately owned  E  &  P
company. Before the formation of Terrapet Corp. in 1972, he was manager  of
supplementary recovery methods and senior evaluation engineer  with  H.  J.
Gruy and Associates, Inc., Dallas, Texas.

John  M. White has served as a director since April 19, 2002. Mr. White  is
currently  an  oil and gas analyst with BMO Nesbitt Burns, responsible  for
Fixed  Income research on oil, gas and energy companies.  Prior to  joining
BMO  Nesbitt  Burns  in 1998, Mr. White was responsible  for  Fixed  Income
research  on  the  oil  and  gas  industry at  John  S.  Herold,  Inc.,  an
independent  oil  and  gas  research  and  consulting  firm.   Mr.  White's
experience also includes managing a portfolio of oil and gas loans for  The
Bank  of Nova Scotia, which included independent exploration and production
companies,  oil  service  companies,  gas  pipelines,  gas  processors  and
refiners.   Prior  to entering banking, Mr. White was with BP  Exploration,
where he worked primarily in exploration and production.

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

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

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

<PAGE>
Key Employees

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

R.  Douglas  Keathley, age 47, has served as Vice President, Operations  of
the  Managing  General Partner since 1992. Before joining us, Mr.  Keathley
worked  as a senior drilling engineer for ARCO Oil and Gas Company  and  in
similar capacities for Reading & Bates Petroleum Co. and Tenneco Oil Co.

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

Item 11.  Executive Compensation

The  Partnership  does not have any directors or executive  officers.   The
executive officers of the Managing General Partner do not receive any  cash
compensation,  bonuses, deferred compensation or compensation  pursuant  to
any  type  of  plan,  from the Partnership.  The Managing  General  Partner
received  $12,000 during 2002, 2001 and 2000 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 other than as listed below,  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.

                                                 Amount and
                                                 Nature of      Percen
                                                                  t
                        Name and Address of      Beneficial       of
  Title of Class         Beneficial Owner        Ownership      Class
-------------------    ---------------------     ----------     ------
  --------------          --------------           ------       -----
Limited Partnership    John   H.   Beckerle,     90 limited      5.7%
Units                  Estate Trust              partnershi
                       2653 South Kihei Road      p units
                       Unit 211
                       Kihei Maui, HI 96753




The  Managing General Partner owns an eleven percent interest as a Managing
General Partner. Through prior purchases, the Managing General Partner also
owns  5.0  limited  partner units, or .32% 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. Beneficial ownership is determined in accordance with the
rules  of  the  Securities and Exchange Commission and includes  voting  or
investment  power  with  respect  to the limited  partner  units.   To  our
knowledge, except under applicable community property laws or as  otherwise
indicated,  the  persons  named in the table  have  sole  voting  and  sole
investment  control  with regard to all limited partner units  beneficially
owned.  We are presenting ownership information as of March 1, 2003.

<PAGE>

                                                 Amount and
                                                 Nature of      Percen
                                                                  t
                        Name and Address of      Beneficial       of
  Title of Class         Beneficial Owner        Ownership      Class
-------------------    ---------------------     ----------     ------
  --------------          --------------           ------       -----
Limited Partnership    Southwest  Royalties,     Directly        .32%
Interest               Inc.                      Owns
                       Managing      General     5.0 Units
                       Partner
                       407   N.  Big  Spring
                       Street
                       Midland, TX 79701

Limited Partnership    H. H. Wommack, III        Indirectly      .32%
Interest                                         Owns
                       Chairman    of    the     5.0 Units
                       Board,
                       President, and CEO
                       of          Southwest
                       Royalties, Inc.,
                       the  Managing General
                       Partner
                       407   N.  Big  Spring
                       Street
                       Midland, TX 79701


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

Item 13.  Certain Relationships and Related Transactions

In 2002, the Managing General Partner received $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 $23,700 for administrative  overhead
attributable to operating such properties during 2002.

Certain  subsidiaries or affiliates of the Managing General Partner perform
various  oilfield services for properties in which the Partnership owns  an
interest.   There were no such services for the period ended  December  31,
2002.

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

<PAGE>
                                 Part IV


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

          (a)(1)  Financial Statements:

                  Included in Part II of this report --

                  Independent Auditors Report
                  Balance 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).

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

          (b)     Reports on Form 8-K

                                 No report on Form 8-K was filed during the
                  quarter ended December 31, 2002.

<PAGE>
                                Signatures


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


                          Southwest Developmental Drilling Fund 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 28, 2003


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

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

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


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

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


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

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


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

Date:     March 28, 2003

<PAGE>
                         CERTIFICATIONS

          I, H.H. Wommack, III, certify that:

          1.   I have reviewed this annual report on Form 10-K of Southwest
Developmental Drilling Fund 92-A, L.P.;

          2.   Based on my knowledge, this annual report does not contain
any  untrue  statement of a material fact  or  omit  to  state  a
material fact necessary to make the statements made, in light  of
the  circumstances  under which such statements  were  made,  not
misleading  with  respect to the period covered  by  this  annual
report;

          3.   Based on my knowledge, the financial statements, and other
financial  information  included in this  annual  report,  fairly
present in all material respects the financial condition, results
of  operations and cash flows of the registrant as of,  and  for,
the periods presented in this annual report;

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

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

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

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

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

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

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

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

Date:  March 28, 2003

/s/ H.H. Wommack, III
H. H. Wommack, III
Chairman, President, Director and Chief Executive Officer
  of Southwest Royalties, Inc., the
  Managing General Partner of
  Southwest Developmental Drilling Fund 92-A, L.P.
<PAGE>
                         CERTIFICATIONS

          I, Bill E. Coggin, certify that:

          1.   I have reviewed this annual report on Form 10-K of Southwest
Developmental Drilling Fund 92-A, L.P.;

          2.   Based on my knowledge, this annual report does not contain
any  untrue  statement of a material fact  or  omit  to  state  a
material fact necessary to make the statements made, in light  of
the  circumstances  under which such statements  were  made,  not
misleading  with  respect to the period covered  by  this  annual
report;

          3.   Based on my knowledge, the financial statements, and other
financial  information  included in this  annual  report,  fairly
present in all material respects the financial condition, results
of  operations and cash flows of the registrant as of,  and  for,
the periods presented in this annual report;

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

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

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

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

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

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

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

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

Date:  March 28, 2003

/s/ Bill E. Coggin
Bill E. Coggin
Executive Vice President
  and Chief Financial Officer of
  Southwest Royalties, Inc., the
  Managing General Partner of
  Southwest Developmental Drilling Fund 92-A, L.P.


<PAGE>

                          Exhibit Index


Item No.     Description                                           Page No.

             Exhibit 99.1 Certification pursuant to 18 U.S.C.       40
             Section 1350, as adopted pursuant to Section 906
             of the Sarbanes-Oxley Act of 2002

             Exhibit 99.2 Certification pursuant to 18 U.S.C.       41
             Section 1350, as adopted pursuant to Section 906
             of the Sarbanes-Oxley Act of 2002

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


       In   connection  with  the  Annual  Report  of   Southwest
Developmental  Drilling  Fund  92-A,  Limited  Partnership   (the
"Company") on Form 10-K for the period ending December  31,  2002
as  filed with the Securities and Exchange Commission on the date
hereof  (the  "Report"), I, H.H. Wommack,  III,  Chief  Executive
Officer  of the Managing General Partner of the Company, certify,
pursuant to 18 U.S.C.  1350, as adopted pursuant to  906  of  the
Sarbanes-Oxley Act of 2002, that:

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

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


Date:  March 28, 2003




/s/ H.H. Wommack, III
H. H. Wommack, III
Chairman, President, Director and Chief Executive Officer
  of Southwest Royalties, Inc., the
  Managing General Partner of
  Southwest Developmental Drilling Fund 92-A, L.P.

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


  In connection with the Annual Report of Southwest Developmental
Drilling Fund 92-A, Limited Partnership (the "Company")  on  Form
10-K  for  the period ending December 31, 2002 as filed with  the
Securities  and  Exchange  Commission on  the  date  hereof  (the
"Report"),  I,  Bill E. Coggin, Chief Financial  Officer  of  the
Managing General Partner of the Company, certify, pursuant to  18
U.S.C.   1350,  as adopted pursuant to  906 of the Sarbanes-Oxley
Act of 2002, that:

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

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


Date:  March 28, 2003




/s/ Bill E. Coggin
Bill E. Coggin
Executive Vice President
  and Chief Financial Officer of
  Southwest Royalties, Inc., the
  Managing General Partner of
  Southwest Developmental Drilling Fund 92-A, L.P.


<PAGE>