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, 2003

                                    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  (432) 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 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]

Indicate  by check mark whether the registrant is an accelerated filer  (as
defined in Exchange Act Rule 12b-2).     Yes     No  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 47.   The  exhibits
begin on page 44.

<PAGE>
                            Table of Contents

Item                                                                   Page

                                  Part I

     Glossary of Oil and Gas Terms                                       3

 1.  Business                                                            5

 2.  Properties                                                          9

 3.  Legal Proceedings                                                  10

 4.  Submission of Matters to a Vote of Security Holders                10

                                 Part II

 5.  Market for Registrant's Common Equity, Related
     Stockholder Matters and Issuer Purchases of Equity Securities      11

 6.  Selected Financial Data                                            12

 7.  Management's Discussion and Analysis of
     Financial Condition and Results of Operations                      13

7A.  Quantitative and Qualitative Disclosures About Market Risk         19

 8.  Financial Statements and Supplementary Data                        20

 9.  Changes in and Disagreements with Accountants
     on Accounting and Financial Disclosure                             35

9A.  Controls and Procedures                                            35

                                 Part III

10.  Directors and Executive Officers of the Registrant                 36

11.  Executive Compensation                                             38

12.  Security Ownership of Certain Beneficial Owners and
     Management and Related Stockholder Matters                         39

13.  Certain Relationships and Related Transactions                     40

14.  Principal Accountant Fees and Services                             40

                                 Part IV

15.  Exhibits, Financial Statement Schedules, and Reports
     on Form 8-K                                                        41

     Signatures                                                         42

<PAGE>

Glossary of Oil and Gas Terms
The  following are abbreviations and definitions of terms commonly used  in
the  oil  and  gas industry that are used in this filing.  All  volumes  of
natural gas referred to herein are stated at the legal pressure base to the
state  or area where the reserves exit and at 60 degrees Fahrenheit and  in
most instances are rounded to the nearest major multiple.

     Bbl. One stock tank barrel, or 42 United States gallons liquid volume.

     Developmental well. A well drilled within the proved area of an oil or
natural gas reservoir to the depth of a stratigraphic horizon known  to  be
productive.

     Exploratory well. A well drilled to find and produce oil or gas in  an
unproved  area to find a new reservoir in a field previously  found  to  be
productive of oil or natural gas in another reservoir or to extend a  known
reservoir.

     Farm-out arrangement. An agreement whereby the owner of a leasehold or
working  interest agrees to assign his interest in certain specific acreage
to  an  assignee,  retaining some interest, such as an  overriding  royalty
interest,  subject  to  the drilling of one (1)  or  more  wells  or  other
specified performance by the assignee.

     Field. An area consisting of a single reservoir or multiple reservoirs
all  grouped  on  or  related to the same individual geological  structural
feature and/or stratigraphic condition.

     Mcf. One thousand cubic feet.

     Oil. Crude oil, condensate and natural gas liquids.

     Overriding  royalty  interest. Interests that  are  carved  out  of  a
working  interest, and their duration is limited by the term of  the  lease
under which they are created.

     Present  value  and  PV-10 Value. When used with respect  to  oil  and
natural gas reserves, the estimated future net revenue to be generated from
the  production of proved reserves, determined in all material respects  in
accordance  with  the  rules and regulations of the  SEC  (generally  using
prices  and costs in effect as of the date indicated) without giving effect
to  non-property  related  expenses  such  as  general  and  administrative
expenses,  debt service and future income tax expenses or to  depreciation,
depletion  and  amortization, discounted using an annual discount  rate  of
10%.

<PAGE>

     Production  costs.  Costs incurred to operate and maintain  wells  and
related  equipment  and facilities, including depreciation  and  applicable
operating  costs  of support equipment and facilities and  other  costs  of
operating and maintaining those wells and related equipment and facilities.

     Proved Area. The part of a property to which proved reserves have been
specifically attributed.

     Proved  developed oil and gas reserves. Reserves that can be  expected
to  be  recovered from existing wells with existing equipment and operating
methods.

     Proved properties. Properties with proved reserves.

     Proved  oil  and gas reserves. The estimated quantities of crude  oil,
natural  gas, and natural gas liquids with geological and engineering  data
that  demonstrate  with  reasonable certainty to be recoverable  in  future
years   from  known  reservoirs  under  existing  economic  and   operating
conditions, i.e., prices and costs as of the date the estimate is made.

     Proved  undeveloped  reserves.  Reserves  that  are  expected  to   be
recovered from new wells on undrilled acreage, or from existing wells where
a relatively major expenditure is required for recompletion.

     Reservoir.  A porous and permeable underground formation containing  a
natural  accumulation  of  producible  oil  or  gas  that  is  confined  by
impermeable  rock  or water barriers and is individual  and  separate  from
other reservoirs.

     Royalty  interest.  An  interest in an oil and  natural  gas  property
entitling  the  owner to a share of oil or natural gas production  free  of
costs of production.

     Working  interest.  The operating interest that gives  the  owner  the
right  to  drill, produce and conduct operating activities on the  property
and a share of production.

     Workover.  Operations  on  a producing well  to  restore  or  increase
production.

<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  81  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.

Introductory Note - Statement of Financial Accounting Standard No. 143
The  Partnership implemented SFAS No. 143 effective January  1,  2003  (See
Note 3 to the Partnership's financial statements).

Introductory Note - Depletion Method
During  2002, the Partnership changed its method of providing for depletion
from  the  units-of-revenue  method to the  units-of-production  method  as
described in Note 4 to the Partnership's financial statements.  This change
in  depletion  method was applied as a cumulative effect  of  a  change  in
accounting principle effective as of January 1, 2002.

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>

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

            Oil       Gas
            ----      ----
  2003      76%       24%
  2002      75%       25%
  2001      72%       28%

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 can be effected by seasonality,  with
higher  demand  in the colder winter months and in very hot summer  months,
the  Partnership has not experienced material price and volume changes  due
to  seasonality  and has been able to sell all of its natural  gas,  either
through  contracts  in place or on the spot market at the  then  prevailing
spot market price.

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
91%  of  the Partnership's total oil and gas production during 2003: Plains
Marketing LP for 60%, Duke Energy Field Services LP 18% and Navajo Refining
Company,  Inc.  for  13%.  Contracts for 2003 with these  major  purchasers
cover  time  periods ranging from month to month contracts up to  year-year
contract periods.  Prices received from these major purchasers ranged  from
a  low  of  $29.51 per Bbl to a high of $29.72 per Bbl and $4.73  per  mcf.
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%.   Contracts
for  2002 with these major purchasers cover time periods ranging from month
to  month contracts up to year-year contract periods.  Prices received from
these  major purchasers ranged from a low of $22.73 per Bbl to  a  high  of
$23.02  per Bbl and $2.86 per mcf.   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%.  Contracts for  2001  with  these  major
purchasers cover time periods ranging from month to month contracts  up  to
year-year  contract periods.  Prices received from these  major  purchasers
ranged  from a low of $27.00 per Bbl to a high of $27.33 per Bbl and  $4.90
per  mcf.   All purchasers of the Partnership's oil and gas production  are
unrelated  third parties.  In the event this purchaser were to  discontinue
purchasing  the  Partnership's  production, the  Managing  General  Partner
believes that a substitute purchaser or purchasers could be located without
undue  delay.   No  other purchaser accounted for an  amount  equal  to  or
greater than 10% of the Partnership's total oil and gas production.

Competition
Because  the  Partnership has utilized all of its funds available  for  the
acquisition  of  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.   The regulatory burden on the oil  and  gas  industry
increases  the  Partnership's  cost of doing business,  and,  consequently,
affects its profitability.

<PAGE>

Regulation  of  Sales  and Transportation of Natural  Gas.   Our  sales  of
natural   gas  are  affected  by  the  availability,  terms  and  cost   of
transportation.  The price and terms for access to pipeline  transportation
are  subject  to  extensive  regulation. In  recent  years,  the  FERC  has
undertaken  various initiatives to increase competition within the  natural
gas industry. As a result of initiatives like FERC Order No. 636, issued in
April  1992, the interstate natural gas transportation and marketing system
has   been  substantially  restructured  to  remove  various  barriers  and
practices  that  historically  limited non-pipeline  natural  gas  sellers,
including  producers, from effectively competing with interstate  pipelines
for  sales  to  local  distribution  companies  and  large  industrial  and
commercial  customers. The most significant provisions  of  Order  No.  636
require   that   interstate  pipelines  provide  firm   and   interruptible
transportation  service  on an open access basis  that  is  equal  for  all
natural  gas supplies. In many instances, the results of Order No. 636  and
related  initiatives  have been to substantially reduce  or  eliminate  the
interstate  pipelines' traditional role as wholesalers of  natural  gas  in
favor  of  providing  only storage and transportation services.  While  the
United  States  Court  of  Appeals upheld most of Order  No.  636,  certain
related  FERC  orders,  including  the  individual  pipeline  restructuring
proceedings,  are still subject to judicial review and may be  reversed  or
remanded in whole or in part. While the outcome of these proceedings cannot
be  predicted  with certainty, we do not believe that we will  be  affected
materially differently than its competitors.

The FERC has also announced several important transportation-related policy
statements and proposed rule changes, including a statement of policy and a
request  for  comments concerning alternatives to its traditional  cost-of-
service rate making methodology to establish the rates interstate pipelines
may  charge  for their services. A number of pipelines have  obtained  FERC
authorization  to  charge  negotiated rates as  one  such  alternative.  In
February  1997, the FERC announced a broad inquiry into issues  facing  the
natural  gas  industry to assist the FERC in establishing regulatory  goals
and  priorities in the post-Order No. 636 environment. Similarly, the Texas
Railroad Commission has been reviewing changes to its regulations governing
transportation and gathering services provided by intrastate pipelines  and
gatherers.  While the changes being considered by these federal  and  state
regulators  would affect us only indirectly, they are intended  to  further
enhance  competition in natural gas markets. We cannot predict what further
action the FERC or state regulators will take on these matters, however, we
do  not  believe  that it will be affected by any action  taken  materially
differently than other natural gas producers with which it competes.

Additional  proposals  and proceedings that might affect  the  natural  gas
industry are pending before Congress, the FERC, state commissions  and  the
courts.  The  natural  gas  industry historically  has  been  very  heavily
regulated;  therefore,  there  is  no assurance  that  the  less  stringent
regulatory  approach  recently  pursued  by  the  FERC  and  Congress  will
continue.

Oil Price Controls and Transportation Rates. Sales of crude oil, condensate
and  gas  liquids by us are not currently regulated and are made at  market
prices.  The  price  we  receive from the sale of  these  products  may  be
affected by the cost of transporting the products to market.

Environmental  and  Health Controls.  Extensive federal,  state  and  local
regulatory and common laws regulating the discharge of materials  into  the
environment  or  otherwise relating to the protection  of  the  environment
affect   our   oil  and  natural  gas  operations.  Numerous   governmental
departments issue rules and regulations to implement and enforce such laws,
which  are  often  difficult  and costly to comply  with  and  which  carry
substantial  civil and even criminal penalties for failure to comply.  Some
laws, rules and regulations relating to protection of the environment  may,
in   certain  circumstances,  impose  strict  liability  for  environmental
contamination,  rendering  a person liable for  environmental  damages  and
cleanup  costs without regard to negligence or fault on the  part  of  such
person. Other laws, rules and regulations may restrict the rate of oil  and
natural  gas production below the rate that would otherwise exist  or  even
prohibit  exploration  and production activities  in  sensitive  areas.  In
addition,  state  laws often require various forms of  remedial  action  to
prevent  pollution,  such  as  closure of inactive  pits  and  plugging  of
abandoned wells. The regulatory burden on the oil and natural gas  industry
increases  our  cost  of  doing  business  and  consequently  affects   our
profitability.  We  believe  that  we are in  substantial  compliance  with
current  applicable environmental laws and regulations and  that  continued
compliance  with  existing requirements will not have  a  material  adverse
impact on our operations. However, environmental laws and regulations  have
been subject to frequent changes over the years, and the imposition of more
stringent  requirements  could  have a material  adverse  effect  upon  our
capital  expenditures,  earnings  or competitive  position.   Additionally,
given  the  intense litigation environment in the United States,  a  threat
exists  of  lawsuits  alleging personal injury  and  property  damage  from
environmental  contamination  alleged  to  be  created  by  us  or  related
entities.   Potential  liability  in such lawsuits  can  include  not  only
compensatory, but substantial punitive damages as well.  We are  not  aware
of any such suits currently pending or threatened.

<PAGE>

The  Comprehensive Environmental Response, Compensation and  Liability  Act
("CERCLA"),  also known as the "Superfund" law, imposes liability,  without
regard  to  fault on certain classes of persons that are considered  to  be
responsible   for  the  release  of  a  "hazardous  substance"   into   the
environment. These persons include the current or former owner or  operator
of the disposal site or sites where the release occurred and companies that
disposed or arranged for the disposal of hazardous substances. Under CERCLA
such persons may be subject to joint and several liability for the costs of
investigating and cleaning up hazardous substances that have been  released
into the environment, for damages to natural resources and for the costs of
certain  health  studies.  In  addition,  companies  that  incur  liability
frequently also confront third party claims because it is not uncommon  for
neighboring landowners and other third parties to file claims for  personal
injury  and  property  damage allegedly caused by hazardous  substances  or
other  pollutants  released  into the environment  from  a  polluted  site.
Potential  liability also exists under CERCLA for natural resource  damage.
A  Natural  Resource Damage Action (NRDA) could result in  liability  being
assessed for restoration to natural resources.

The  Federal Oil Pollution Act of 1990 ("OPA") regulates the release of oil
into  water  or  other areas designated by the statute.   A  release  could
result  in  our  being  held responsible for the cost  of  remediating  the
release, OPA specified damages and natural resource damages.  The extent of
such liability could be extensive.   A release of oil in harmful quantities
or other materials into water or other specified areas could also result in
our  being held responsible under the Clean Water Act ("CWA") for the costs
of remediation, and any civil and criminal fines and penalties.

The   Federal  Solid  Waste  Disposal  Act,  as  amended  by  the  Resource
Conservation  and Recovery Act of 1976 ("RCRA"), regulates the  generation,
transportation,  storage, treatment and disposal  of  solid  and  hazardous
wastes and can require cleanup of abandoned hazardous waste disposal  sites
as  well  as  waste management areas operating facilities.  RCRA  currently
excludes drilling fluids, produced waters and other wastes associated  with
the  exploration,  development or production of oil and  natural  gas  from
regulation  as  "hazardous waste." Disposal of such non-hazardous  oil  and
natural  gas  exploration, development and production  wastes  usually  are
regulated  by state law. Other wastes handled at exploration and production
sites  or used in the course of providing well services may not fall within
this  exclusion.  Moreover,  stricter  standards  for  waste  handling  and
disposal may be imposed on the oil and natural gas industry in the  future.
From time to time legislation is proposed in Congress that would revoke  or
alter  the  current  exclusion of exploration, development  and  production
wastes  from  the RCRA definition of "hazardous wastes" thereby potentially
subjecting  such  wastes to more stringent handling, disposal  and  cleanup
requirements. If such legislation were enacted it could have a  significant
impact  on the operating costs of Southwest and Sierra, as well as the  oil
and natural gas industry and well servicing industry in general. The impact
of  future  revisions  to  environmental laws  and  regulations  cannot  be
predicted.  In addition, if our operations were to trigger regulation under
RCRA,  we could be required to satisfy certain financial criteria to ensure
financial  ability  to comply with RCRA regulations.   Proof  of  financial
responsibility  could  be required in the form of  dedicated  trust  funds,
irrevocable letters of credit, posting of bonds, etc.

The Federal Clean Water Act ("CWA") contains provisions that may result  in
the imposition of certain water pollution control requirements with respect
to water releases from our operations.  We may be required to incur certain
capital  expenditures in the next several years for water pollution control
equipment  in connection with obtaining and maintaining National  Pollutant
Discharge  Elimination Systems ("NPDES") permits.  However, we believe  our
operations  will  not  be  materially  adversely  affected  by   any   such
requirements,  and  the  requirements are  not  expected  to  be  any  more
burdensome to us than to other similarly situated companies involved in oil
and  natural  gas exploration and production activities or  well  surfacing
activities.

Our  operations are also subject to the federal Clean Air Act  ("CAA")  and
comparable state and local requirements. Amendments to the CAA were adopted
in 1990 and contain provisions that may result in the gradual imposition of
certain  pollution control requirements with respect to air emissions  from
our operations. We may be required to incur certain capital expenditures in
the  next  several years for air pollution control equipment in  connection
with  obtaining  and maintaining operating permits and  approvals  for  air
emissions.  However,  we  believe our operations  will  not  be  materially
adversely affected by any such requirements, and the requirements  are  not
expected  to be any more burdensome to us than to other similarly  situated
companies  involved  in  oil  and natural gas  exploration  and  production
activities or well servicing activities.

We  maintain  insurance against "sudden and accidental" occurrences,  which
may  cover  some, but not all, of the environmental risks described  above.
Most  significantly,  the insurance we maintain will not  cover  the  risks
described above which occur over a sustained period of time. Further, there
can  be  no assurance that such insurance will continue to be available  to
cover  all  such costs or that such insurance will be available at  premium
levels  that  justify its purchase.  The occurrence of a significant  event
not  fully  insured  or indemnified against could have a  material  adverse
effect on our financial condition and operations.

<PAGE>

Limited   partners  should  be  aware  that  the  assessment  of  liability
associated with environmental liabilities is not always correlated  to  the
value of a particular project.  Accordingly, liability associated with  the
environment under local, state, or federal regulations, particularly  clean
ups  under CERCLA, can exceed the value of our investment in the associated
site.

Regulation  of  Oil  and  Natural  Gas  Exploration  and  Production.   Our
exploration  and  production operations are subject  to  various  types  of
regulation  at  the  federal,  state and local  levels.   Such  regulations
include  requiring  permits and drilling bonds for the drilling  of  wells,
regulating the location of wells, the method of drilling and casing  wells,
and  the  surface  use and restoration of properties upon which  wells  are
drilled.    Many  states  also  have  statutes  or  regulations  addressing
conservation matters, including provisions for the utilization  or  pooling
of  oil  and natural gas properties, the establishment of maximum rates  of
production  from oil and natural gas wells and the regulation  of  spacing,
plugging and abandonment of such wells.  Some state statutes limit the rate
at which oil and natural gas can be produced from our properties.

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,
2003,  there were 81 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, 2003, 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 2003, 2002
and 2001.

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       23,000    4,000
#1
Ward  County,     100%                23,000(1  4,000(1)
Texas                                    )
                 working
                interest

Mobil  Fee  H   12/92 at       1       43,000   158,000
#1
Ward  County,     100%                43,000(1  158,000(
Texas                                    )         1)
                 working
                interest

(1)Amounts  represent  proved developed reserves from  currently  producing
zones.

*Ryder Scott Company, L.P. prepared the reserve and present value data  for
the  Partnership's existing properties as of January 1, 2004.  The  reserve
estimates  were  made  in  accordance with guidelines  established  by  the
Securities and Exchange Commission pursuant to Rule 4-10(a) of Regulation S-
X.   Such guidelines require oil and gas reserve reports be prepared  under
existing economic and operating conditions with no provisions for price and
cost escalation except by contractual arrangements.

<PAGE>

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, 2004 are an average price of $31.76 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, 2004 are  an
average price of $5.30 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 2003.

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.
All  of the proved reserves are included in the engineering reports,  which
evaluate the Partnership's present reserves.

The  Partnership or the owners of properties in which the Partnership  owns
an  interest  can  engage  in workover projects or  supplementary  recovery
projects, for example, to extract behind the pipe reserves.  See  Part  II,
Item  7,  Management's Discussion and Analysis of Financial  Condition  and
Results of Operations.

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 2003 through the solicitation of proxies or otherwise.

<PAGE>
                                 Part II


Item 5.   Market  for  the Registrant's Common Equity, Related  Stockholder
          Matters and Issuer Purchases of Equity Securities

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  in
accordance with the obligations set forth in the partnership agreement,  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  under
the partnership agreement.

                    Issuer Purchases of Equity Securities

                                                   Maximum
                                       Total     Number (or
                                      Number
                                     of Units    Approximat
                                                      e
                                     Purchased    Value) of
                                        as          Units
                                      Part of     that May
                                     Publicly      Yet Be
               Total                 Announced    Purchased
              Number
             of Units     Average    Plans or     Under the
                           Price                    Plans
Period(1)    Purchased   Paid Per    Programs        or
                           Unit                   Programs
October 1-
   31,
   2003          -      $    -           -           N/A
November 1-
   30,
   2003          -           -           -           N/A
December 1-
   31,
   2003          -           -           -           N/A
  TOTALS         -      $    -

(1)  In  July  2003, the Managing General Partner purchased a total  of  10
limited  partner units from limited partners at an average  base  price  of
$453.08  per  unit.   In  2002  and 2001, no  limited  partner  units  were
purchased  by the Managing General Partner.  The discretionary  repurchases
were made based upon the partnership agreement.

Number of Limited and General Partner Interest Holders
As of December 31, 2003, 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  2003,  distributions  were made totaling  $168,665,  with  $150,112
distributed  to  the investor partners and $18,553 to the Managing  General
Partners.   For the year ended December 31, 2003, distributions of  $106.69
per  investor  partner  unit were made, based upon 1,407  investor  partner
units outstanding.  During 2002, 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, 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.

<PAGE>
Item 6.   Selected Financial Data

The following selected financial data for the year ended December 31, 2003,
2002,  2001, 2000 and 1999 should be read in conjunction with the financial
statements included in Item 8:

                                         Year ended December 31,
                              --------------------------------------------
                                                  ----
                               2003      2002     2001     2000      1999
                               ----      ----     ----     ----      ----

Revenues                   $  349,284  275,362  333,192  372,553   249,965

Net     income     before
cumulative effects
 of accounting changes        156,673  120,581  160,893  217,640   112,767

Net income                    153,929  117,581  160,893  217,640   112,767

Partners'  share  of  net
income:

Managing General Partner      18,472   14,804   20,338   25,590    14,274

Investor partners             135,457  102,777  140,555  192,050   98,493

Investor  partners'   net
income per unit
     before    cumulative
effects of
 accounting changes           98.01
                                       75.18    99.90    136.50    70.00

Investor partners' net
 income (loss) per unit       96.27
                                       73.05    99.90    136.50    70.00

Investor partners' cash
 distributions per unit       106.69
                                       71.45    132.08   142.10    53.77

Total assets               $  249,981  235,993  231,369  279,195   286,195



<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  has  approximated  10%  per  year.
Accordingly, if commodity prices remain unchanged, the Partnership  expects
future earnings to decline due to anticipated production declines.

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.

In  2002,  the  Partnership changed methods of accounting for depletion  of
capitalized  costs  from  the  units-of-revenue  method  to  the  units-of-
production method.  The newly adopted accounting principle is preferable in
the  circumstances  because the units-of-production  method  results  in  a
better  matching of the costs of oil and gas production against the related
revenue received in periods of volatile prices for production as have  been
experienced  in  recent  periods.   Additionally,  the  units-of-production
method is the predominant method used by full cost companies in the oil and
gas  industry,  accordingly, the change improves the comparability  of  the
Partnership's financial statements with its peer group.

<PAGE>
Results of Operations

A.  General Comparison of the Years Ended December 31, 2003 and 2002

The  following  table  provides certain information  regarding  performance
factors for the years ended December 31, 2003 and 2002:

                              Year Ended      Percenta
                                                 ge
                             December 31,     Increase
                            2003      2002    (Decreas
                                                 e)
                            ----      ----    --------
                                                  -
Average price per      $   30.12                 23%
barrel of oil                       24.56
Average price per mcf  $    4.67                 53%
of gas                              3.05
Oil production in         8,700     8,410        3%
barrels
Gas production in mcf     17,500    22,000      (20%)
Oil and gas revenue    $  343,751   273,741      26%
Production expense     $  153,850   123,272      25%
Partnership            $  168,665   112,957      49%
distributions
Limited partner        $  150,112   100,532      49%
distributions
Per unit distribution  $  106.69                 49%
to limited partners                 71.45

Number of limited         1,407     1,407
partner units

Revenues

The  Partnership's oil and gas revenues increased to $343,751 from $273,741
for  the  years ended December 31, 2003 and 2002, respectively, an increase
of  26%.  The principal factors affecting the comparison of the years ended
December 31, 2003 and 2002 are as follows:

1.  The  average  price  for a barrel of oil received  by  the  Partnership
    increased  during the year ended December 31, 2003 as compared  to  the
    year ended December 31, 2002 by 23%, or $5.56 per barrel, resulting  in
    an increase of approximately $48,400 in revenues. Oil sales represented
    76%  of total oil and gas sales during the year ended December 31, 2003
    as compared to 75% during the year ended December 31, 2002.

    The  average  price  for  an  mcf of gas received  by  the  Partnership
    increased during the same period by 53%, or $1.62 per mcf, resulting in
    an increase of approximately $28,400 in revenues.

    The  total  increase in revenues due to the change in  prices  received
    from oil and gas production is approximately $76,800.  The market price
    for  oil  and gas has been extremely volatile over the past decade  and
    management  expects a certain amount of volatility to continue  in  the
    foreseeable future.

<PAGE>

2.   Oil  production increased approximately 290 barrels or 3%  during  the
   year ended December 31, 2003 as compared to the year ended December  31,
   2002, resulting in an increase of approximately $7,100 in revenues.

    Gas production decreased approximately 4,500 mcf or 20% during the same
    period, resulting in a decrease of approximately $13,700 in revenues.

    The  net total decrease in revenues due to the change in production  is
    approximately $6,600.  The decrease in gas volumes is due to the  sharp
    production decline on one well.

3. Other  income  in  the  amount of $5,533 for 2003  primarily  represents
   litigation  settlement  income from a class action  lawsuit,  where  two
   purchasers  were  underpaying  for  certain  types  of  oil  in  certain
   locations for the time periods of 1988-1998.

Costs and Expenses

Total  costs and expenses increased to $192,611 from $154,781 for the years
ended  December 31, 2003 and 2002, respectively, an increase of  24%.   The
increase  is the result of the addition of accretion expense, higher  lease
operating costs and general and administrative expense.

1.    Lease  operating  costs  and production taxes  were  25%  higher,  or
   approximately $30,600 more during the year ended December  31,  2003  as
   compared  to  the year ended December 31, 2002.  The increase  in  lease
   operating  costs  are due to increased well repairs  on  two  wells  and
   compressor charges on one well and an increase in production taxes due to
   an increase in oil and gas commodity prices.

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 29%
    or  approximately  $5,100 during the year ended December  31,  2003  as
    compared to the year ended December 31, 2002.  The increase in  general
    and  administrative  expense  is  due to  an  increase  in  independent
    accounting review and audit fees.

3.  Depletion expense was $14,000 for the year ended December 31, 2003  the
    same  as 2002.  The year ended December 31, 2003, was $1.21 applied  to
    11,617  BOE  as compared to $1.16 applied to 12,077 BOE  for  the  same
    period in 2002.

Cumulative effect of change in accounting principle

On  January  1,  2003,  the  Partnership  adopted  Statement  of  Financial
Accounting  Standards No. 143, Accounting for Asset Retirement  Obligations
("SFAS  No. 143").  Adoption of SFAS No. 143 is required for all  companies
with fiscal years beginning after June 15, 2002.  The new standard requires
the Partnership to recognize a liability for the present value of all legal
obligations  associated with the retirement of tangible  long-lived  assets
and to capitalize an equal amount as a cost of the asset and depreciate the
additional cost over the estimated useful life of the asset.  On January 1,
2003,  the  Partnership  recorded  additional  costs,  net  of  accumulated
depreciation,   of  approximately  $23,838,  a  long  term   liability   of
approximately $26,582 and a loss of approximately $2,744 for the cumulative
effect on depreciation of the additional costs and accretion expense on the
liability related to expected abandonment costs of its oil and natural  gas
producing   properties.   At  December  31,  2003,  the  asset   retirement
obligation  was  $28,708, and the increase in the balance from  January  1,
2003  of $2,126 is due to accretion expense.  The pro forma amounts of  the
asset  retirement obligation as of December 31, 2002, 2001 and  2000,  were
approximately  $26,582, $24,626 and $22,814, respectively.  The  pro  forma
amounts of the asset retirement obligation were measured using information,
assumptions and interest rates as of the adoption date of January 1, 2003.


<PAGE>


Results of Operations

B.  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%)
Oil and gas revenue    $  273,741   332,643     (18%)
Production expense     $  123,272   131,781     (6%)
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.

2.    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%.   In  the fourth quarter of  2002,  the  Partnership
    changed  methods of accounting for depletion of capitalized costs  from
    the  units-of-revenue  method to the units-of-production  method.   The
    newly  adopted  accounting principle is preferable in the circumstances
    because the units-of-production method results in a better matching  of
    the  costs  of  oil  and  gas production against  the  related  revenue
    received  in  periods of volatile prices for production  as  have  been
    experienced  in  recent periods.  Additionally, the units-of-production
    method is the predominant method used by full cost companies in the oil
    and gas industry, accordingly, the change improves the comparability of
    the Partnership's financial statements with its peer group.  The effect
    of  this  change  in  method resulted in no change  to  2002  depletion
    expense, however, it decreased 2002 net income by $3,000.  See  Note  4
    of the notes to the Partnership's financial statements.

   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,  which provided more economically recoverable proved  reserves
   at  January 1, 2003 which caused the depletion rate per equivalent  unit
   produced  to  decline.  Also, as discussed above, the  total  equivalent
   units produced in 2002 declined from 2001.



<PAGE>


C.   Revenue and Distribution Comparison

Partnership net income for the years ended December 31, 2003, 2002 and 2001
was   $153,929,   $117,581   and   $160,893,   respectively.    Partnership
distributions  for the years ended December 31, 2003, 2002  and  2001  were
$168,665,  $112,957  and  $208,798, respectively.   These  differences  are
indicative  of the changes in oil and gas prices, production  and  property
during 2003, 2002 and 2001.

The  sources  for  the  2003 distributions of $168,665  were  oil  and  gas
operations  of  approximately  $172,300 and  the  change  in  oil  and  gas
properties   of  approximately  $(600),  resulting  in  excess   cash   for
contingencies  or  subsequent distributions.   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.

Total  distributions during the year ended December 31, 2003 were  $168,665
of  which $150,112 was distributed to the investor partners and $18,553  to
the  Managing  General  Partners.  The per unit  distribution  to  investor
partners  during  the same period was $106.69.  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.

Cumulative  cash distributions of $1,867,975 have been made to the  general
and  limited  partners as of December 31, 2003.  As of December  31,  2003,
$1,662,874 or $1,181.68 per investor partner unit, has been distributed  to
the  investor  partners, representing a 100% return of capital  and  a  18%
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 $172,300  in
2003 compared to $124,000 in 2002 and approximately $197,000 in 2001.

Cash  flows  (used in) provided by investing activities were  approximately
$(600) in 2003 compared to $(10) in 2002 and approximately $1,400 in  2001.
The  primary  use of the 2003 cash flow from investing activities  was  the
change in oil and gas properties.

Cash flows used in financing activities were approximately $168,600 in 2003
compared to $113,000 in 2002 and approximately $208,700 in 2001.  The  only
use in the 2003 financing activities was the distributions to partners.

As  of  December 31, 2003, the Partnership had $70,700 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 Partnership cannot develop  its  non  producing
properties, if any.  Without continued development, the producing  reserves
continue  to  deplete.  Accordingly, as the Partnership's  properties  have
matured  and  depleted,  the  net  cash  flows  from  operations  for   the
Partnership  has  steadily  declined, except in  periods  of  substantially
increased  commodity pricing.  Maintenance of properties and administrative
expenses for the Partnership are increasing relative to production.  As the
properties   continue   to   deplete,   maintenance   of   properties   and
administrative costs as a percentage of production are expected to continue
to increase.

<PAGE>
Liquidity - Managing General Partner

As  of  December 31, 2003, the Managing General Partner is in violation  of
several covenants pertaining to their Amended and Restated Revolving Credit
Agreement  due  June  1, 2006 and their Senior Second Lien  Secured  Credit
Agreement  due  October  15,  2008.  Due to the  covenant  violations,  the
Managing  General  Partner is in default under their Amended  and  Restated
Revolving  Credit  Agreement  and the Senior  Second  Lien  Secured  Credit
Agreement,  and all amounts due under these agreements have been classified
as  a current liability on the Managing General Partner's balance sheet  at
December 31, 2003.  The significant working capital deficit and debt  being
in default at December 31, 2003, raise substantial doubt about the Managing
General Partner's ability to continue as a going concern.

Subsequent  to  December 31, 2003, the Board of Directors of  the  Managing
General  Partner announced its decision to explore a merger,  sale  of  the
stock  or  other transaction involving the Managing General  Partner.   The
Board  has  formed a Special Committee of independent directors to  oversee
the   sales  process.   The  Special  Committee  has  retained  independent
financial  and  legal advisors to work closely with the management  of  the
Managing General Partner to implement the sales process.  There can  be  no
assurance  that a sale of the Managing General Partner will be  consummated
or what terms, if consummated, the sale will be on.

Recent Accounting Pronouncements

The  EITF is considering two issues related to the reporting of oil and gas
mineral  rights.  Issue No. 03-O, "Whether Mineral Rights Are  Tangible  or
Intangible Assets," is whether or not mineral rights are intangible  assets
pursuant  to  SFAS  No.  141,  "Business  Combinations."  Issue  No.  03-S,
"Application of SFAS No. 142, Goodwill and Other Intangible Assets, to  Oil
and  Gas  Companies,"  is, if oil and gas drilling  rights  are  intangible
assets,  whether  those  assets  are  subject  to  the  classification  and
disclosure provisions of SFAS No. 142.  The Partnership classifies the cost
of oil and gas mineral rights as properties and equipment and believes that
this is consistent with oil and gas accounting and industry practice.   The
disclosures required by SFAS Nos. 141 and 142 would be made in the notes to
the  financial  statements. There would be no effect on  the  statement  of
income  or  cash  flows as the intangible assets related  to  oil  and  gas
mineral rights would continue to be amortized under the full cost method of
accounting.

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                                            21

Balance Sheets                                                          22

Statement of Operations                                                 23

Statement of Changes in Partners' Equity                                24

Statements of Cash Flows                                                25

Notes to Financial Statements                                           26

<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, 2003  and  2002,
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,  2003.   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, 2003 and 2002 and the results of  its
operations  and  its cash flows for each of the years  in  the  three  year
period  ended  December  31, 2003 in conformity with accounting  principles
generally accepted in the United States of America.

As discussed in Note 4 to the financial statements, the Partnership changed
its method of computing depletion in 2002.  Also, as discussed in Note 3 to
the  financial statements, the Partnership changed its method of accounting
for asset retirement obligations as of January 1, 2003.






                                                  KPMG LLP



Midland, Texas
March 19, 2004, except as to Note 9, which is as of May 3, 2004

<PAGE>

             Southwest Developmental Drilling Fund 92-A, L.P.
                     (a Delaware limited partnership)
                              Balance Sheets
                        December 31, 2003 and 2002

                                   2003      2002
                                   ----      ----
Assets
------

Current assets:
 Cash and cash equivalents    $  30,713    27,569
  Receivable  from  Managing     39,984    39,532
General Partner
                                 --------  --------
                                 ----      ----
   Total current assets          70,697    67,101
                                 --------  --------
                                 ----      ----
Oil  and  gas  properties  -
using the full-
 cost method of accounting       1,326,16  1,313,13
                                 8         2
       Less      accumulated
depreciation,
         depletion       and     1,146,88  1,144,24
amortization                     4         0
                                 --------  --------
                                 ----      ----
      Net   oil   and    gas     179,284   168,892
properties
                                 --------  --------
                                 ----      ----
                              $  249,981   235,993
                                 =======   =======

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

Current     liability      -  $  95        79
distribution payable
                                 --------  --------
                                 ----      ----

Asset retirement obligation      28,708    9
                                 --------  --------
                                 ----      ----
Partners' equity:
 Managing General Partner        30,222    30,303
 Investor partners               190,956   205,611
                                 --------  --------
                                 ----      ----
   Total partners' equity        221,178   235,914
                                 --------  --------
                                 ----      ----
                              $  249,981   235,993
                                 =======   =======










                  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, 2003, 2002 and 2001

                                     2003      2002      2001
                                     ----      ----      ----
Revenues
------------
 Oil and gas sales              $  343,751   273,741   332,643
    Interest    income    from     -         92        549
operations
 Other                             5,533     1,529     -
                                   --------  --------  --------
                                   --        --        --
                                   349,284   275,362   333,192
                                   --------  --------  --------
                                   --        --        --
Expenses
------------
 Production                        153,850   123,272   131,781
 General and administrative        22,635    17,509    16,518
 Accretion of asset retirement     2,126     -         -
obligation
  Depreciation, depletion  and     14,000    14,000    24,000
amortization
                                   --------  --------  --------
                                   --        --        --
                                   192,611   154,781   172,299
                                   --------  --------  --------
                                   --        --        --
Net  income  before cumulative
effect
 of accounting changes             156,673   120,581   160,893

Cumulative effect of change in
accounting
 principle - SFAS No. 143 -        (2,744)   -         -
See Note 3
Cumulative effect of change in
accounting principle
 - change in depletion method      -         (3,000)   -
- See Note 4
                                   --------  --------  --------
                                   --        --        --
Net income                      $  153,929   117,581   160,893
                                   ======    ======    ======
Net income allocated to:

 Managing General Partner       $  18,472    14,804    20,338
                                   ======    ======    ======
 Investor partners              $  135,457   102,777   140,555
                                   ======    ======    ======
   Per  investor partner  unit  $    98.01
before cumulative effect                     75.18     99.90
    Cumulative   effects   per      (1.74)    (2.13)   -
investor partner unit
                                   --------  --------  --------
                                   --        --        --
  Per investor partner unit     $    96.27
                                             73.05     99.90
                                   ======    ======    ======
Pro   forma  amounts  assuming
changes are applied
  retroactively (See  Notes  3
and 4 for details):
  Net income before cumulative  $  -         118,625   163,081
effect
                                   ======    ======    ======
   Per  investor partner  unit  $  -           73.94   101.59
(1,407.0 units)
                                   ======    ======    ======




                  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, 2003, 2002 and 2001

                                 Managing
                                 General   Investor
                                 Partner   Partners   Total
                                 --------  --------   -----
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    102,777   117,581

 Distributions                   (12,425)  (100,532  (112,957
                                           )         )
                                 --------  --------  --------
                                 --        ---       ---
Balance at December 31, 2002     30,303    205,611   235,914

 Net income                      18,472    135,457   153,929

 Distributions                   (18,553)  (150,112  (168,665
                                           )         )
                                 --------  --------  --------
                                 --        ---       ---
Balance at December 31, 2003  $  30,222    190,956   221,178
                                 ======    ======    ======
























                  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, 2003, 2002 and 2001

                                      2003      2002      2001
                                      ----      ----      ----
Cash   flows   from   operating
activities:
 Cash received from oil and gas  $  337,671   257,856   353,274
sales
  Cash paid to Managing General
Partner
   for administrative fees  and
general
  and administrative overhead       (170,857  (135,451  (156,854
                                    )         )         )
 Interest received                  -         92        549
 Miscellaneous settlement           5,533     1,529     -
                                    --------  --------  --------
                                    --        --        --
     Net   cash   provided   by     172,347   124,026   196,969
operating activities
                                    --------  --------  --------
                                    --        --        --
Cash   flows   from   investing
activities:
   Addition  to  oil  and   gas     (554)     (8)       -
properties
 Sale of equipment                  -         -         1,393
                                    --------  --------  --------
                                    --        --        --
   Net  cash (used in) provided     (554)     (8)       1,393
by investing activities
                                    --------  --------  --------
                                    --        --        --
Cash  flows  used in  financing
activities:
 Distributions to partners          (168,649  (112,957  (208,719
                                    )         )         )
                                    --------  --------  --------
                                    --        --        --
Net increase (decrease) in cash     3,144     11,061    (10,357)
and cash equivalents

Beginning of period                 27,569    16,508    26,865
                                    --------  --------  --------
                                    --        --        --
End of period                    $  30,713    27,569    16,508
                                    ======    ======    ======
Reconciliation of net income to
net
  cash  provided  by  operating
activities:

Net income                       $  153,929   117,581   160,893

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

  Depreciation,  depletion  and     14,000    14,000    24,000
amortization
  Accretion of asset retirement     2,126     -         -
obligation
 Cumulative effect of change in     2,744     3,000     -
accounting principle
    (Increase)   decrease    in     (6,080)   (15,885)  20,631
receivables
    Increase   (decrease)    in     5,628     5,330     (8,555)
payables
                                    --------  --------  --------
                                    --        --        --
Net  cash provided by operating  $  172,347   124,026   196,969
activities
                                    ======    ======    ======
Noncash investing and financing
activities:

 Increase in oil and gas
properties - Adoption
  of SFAS No. 143                $  23,838    -         -
                                    ======    ======    ======

                  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.

     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 year ended December 31, 2001, 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,  2003, 2002 and 2001, the net capitalized costs did not exceed the
     estimated present value of oil and gas reserves.

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

                      Notes to Financial Statements

2.   Summary of Significant Accounting Policies - continued

     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, 2003 and 2002, 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,
     2003  and 2002 was $170,944 and $172,009, respectively, less than that
     shown  on the accompanying Balance Sheets in accordance with generally
     accepted accounting principles.

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

     Investor Partner Units
     As  of  December  31, 2003, 2002 and 2001, there were  1,407  investor
     units outstanding held by 105 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.

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

                      Notes to Financial Statements

2.   Summary of Significant Accounting Policies - continued

     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 EITF is considering two issues related to the reporting of oil and
     gas  mineral  rights.  Issue  No. 03-O, "Whether  Mineral  Rights  Are
     Tangible  or Intangible Assets," is whether or not mineral rights  are
     intangible  assets pursuant to SFAS No. 141, "Business  Combinations."
     Issue  No.  03-S,  "Application of SFAS No. 142,  Goodwill  and  Other
     Intangible  Assets,  to Oil and Gas Companies," is,  if  oil  and  gas
     drilling  rights  are  intangible assets,  whether  those  assets  are
     subject  to the classification and disclosure provisions of  SFAS  No.
     142.   The  Partnership classifies the cost of  oil  and  gas  mineral
     rights  as  properties  and  equipment  and  believes  that  this   is
     consistent  with  oil and gas accounting and industry  practice.   The
     disclosures  required by SFAS Nos. 141 and 142 would be  made  in  the
     notes  to  the financial statements. There would be no effect  on  the
     statement of income or cash flows as the intangible assets related  to
     oil  and  gas mineral rights would continue to be amortized under  the
     full cost method of accounting.

     Depletion Policy
     In  2002,  the Partnership changed methods of accounting for depletion
     of capitalized costs from the units-of-revenue method to the units-of-
     production method. (See Note 4)

3.   Cumulative effect of change in accounting principle - SFAS No. 143
     On  January  1, 2003, the Partnership adopted Statement  of  Financial
     Accounting   Standards  No.  143,  Accounting  for  Asset   Retirement
     Obligations  ("SFAS No. 143").  Adoption of SFAS No. 143  is  required
     for  all  companies with fiscal years beginning after June  15,  2002.
     The new standard requires the Partnership to recognize a liability for
     the  present  value  of  all  legal obligations  associated  with  the
     retirement  of tangible long-lived assets and to capitalize  an  equal
     amount as a cost of the asset and depreciate the additional cost  over
     the  estimated  useful  life of the asset.  On January  1,  2003,  the
     Partnership    recorded   additional   costs,   net   of   accumulated
     depreciation,  of  approximately $23,838, a  long  term  liability  of
     approximately  $26,582  and  a loss of approximately  $2,744  for  the
     cumulative  effect  on  depreciation  of  the  additional  costs   and
     accretion  expense  on  the liability related to expected  abandonment
     costs  of  its oil and natural gas producing properties.  At  December
     31,  2003,  the  asset  retirement obligation  was  $28,708,  and  the
     increase  in  the  balance from January 1, 2003 of $2,126  is  due  to
     accretion  expense.   The pro forma amounts of  the  asset  retirement
     obligation  as of December 31, 2002, 2001 and 2000, were approximately
     $26,582, $24,626 and $22,814, respectively.  The pro forma amounts  of
     the  asset  retirement  obligation were  measured  using  information,
     assumptions and interest rates as of the adoption date of  January  1,
     2003.  The pro forma amounts for the years ended December 31, 2002 and
     2001,  which  are presented below, reflect the effect  of  retroactive
     application of SFAS No. 143.

                                     2002      2001
                                     ----      ----
Pro   forma  amounts  assuming
change is applied
 retroactively:
  Net income before cumulative
effect
  for change in depletion       $  118,625   159,081
                                   ======    ======
   Per  investor partner  unit  $    73.94   98.75
(1,407.0 units)
                                   ======    ======
 Net income                     $  115,625   159,081
                                   ======    ======
   Per  investor partner  unit  $    71.80   98.75
(1,407.0 units)
                                   ======    ======

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

                      Notes to Financial Statements

4.    Cumulative  effect of a change in accounting principle  -  change  in
depletion method
     In  2002,  the Partnership changed methods of accounting for depletion
     of capitalized costs from the units-of-revenue method to the units-of-
     production   method.   The  newly  adopted  accounting  principle   is
     preferable in the circumstances because the units-of-production method
     results  in  a better matching of the costs of oil and gas  production
     against the related revenue received in periods of volatile prices for
     production  as have been experienced in recent periods.  Additionally,
     the  units-of-production method is the predominant method used by full
     cost  companies in the oil and gas industry, accordingly,  the  change
     improves  the comparability of the Partnership's financial  statements
     with  its peer group.  The Partnership adopted the units-of-production
     method  through the recording of a cumulative effect of  a  change  in
     accounting  principle in the amount of $3,000 effective as of  January
     1,  2002.   The Partnership's depletion for the years ended  2003  and
     2002  have  been calculated using the units-of-production  method  and
     2001 has not been restated.  The pro forma amounts for 2001, which are
     presented below, reflect the effect of retroactive application of  the
     units-of-production method.  See Note 11 for the effects of the change
     in depletion method on the individual quarters of 2002.

                                     2001

                                     ----
Pro   forma  amounts  assuming
change is applied
 retroactively:
 Net income                     $  164,893
                                   ======
   Per  investor partner  unit  $  102.74
(1,407.0 units)
                                   ======

5.   Liquidity - Managing General Partner
     As  of December 31, 2003, the Managing General Partner is in violation
     of   several  covenants  pertaining  to  their  Amended  and  Restated
     Revolving  Credit Agreement due June 1, 2006 and their  Senior  Second
     Lien  Secured  Credit  Agreement due October 15,  2008.   Due  to  the
     covenant violations, the Managing General Partner is in default  under
     their  Amended and Restated Revolving Credit Agreement and the  Senior
     Second Lien Secured Credit Agreement, and all amounts due under  these
     agreements have been classified as a current liability on the Managing
     General Partner's balance sheet at December 31, 2003.  The significant
     working  capital  deficit and debt being in default  at  December  31,
     2003,  raise  substantial doubt about the Managing  General  Partner's
     ability to continue as a going concern.

     Subsequent  to  December  31, 2003, the  Board  of  Directors  of  the
     Managing  General Partner announced its decision to explore a  merger,
     sale  of the stock or other transaction involving the Managing General
     Partner.   The  Board  has formed a Special Committee  of  independent
     directors  to  oversee the sales process.  The Special  Committee  has
     retained independent financial and legal advisors to work closely with
     the  management of the Managing General Partner to implement the sales
     process.   There  can  be no assurance that a  sale  of  the  Managing
     General Partner will be consummated or what terms, if consummated, the
     sale will be on.

6.   Commitments and Contingent Liabilities
     The Managing General Partner has the right, but not the obligation, to
     purchase limited partnership units should an investor desire to  sell.
     The  value of the unit is determined by adding the sum of (1)  current
     assets  less liabilities and (2) the present value of the  future  net
     revenues attributable to proved reserves and by discounting the future
     net  revenues  at  a rate not in excess of the prime rate  charged  by
     Nations  Bank,  N.A. of Midland, Texas, plus one percent  (1%),  which
     value  shall be further reduced by a risk factor discount of  no  more
     than  one-third (1/3) to be determined by the Managing General Partner
     in its sole and absolute discretion.

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

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

                      Notes to Financial Statements

6.   Commitments and Contingent Liabilities - continued
     As  of December 31, 2003, 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.

7.   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  $23,100,
     $23,700  and $23,600 for the years ended December 31, 2003,  2002  and
     2001,  respectively.   In addition, the Managing General  Partner  and
     certain  officers and employees may have an interest in  some  of  the
     properties that the Partnership also participates.

     Southwest Royalties, Inc., the Managing General Partner, was  paid  an
     administrative  fee  of  $12,000  during  2003,  2002  and  2001   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 $43,600 and $39,500 are from oil  and  gas
     production, net of lease operating costs and production taxes,  as  of
     December 31, 2003 and 2002, respectively.

8.   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  91% of the Partnership's total oil and gas  production
     during  2003: Plains Marketing LP for 60%, Duke Energy Field  Services
     LP  18%  and  Navajo Refining Company, Inc. for 13%.  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%.   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.

9.   Subsequent Event
     Subsequent  to  December  31,  2003,  the  Managing  General   Partner
     announced that its Board of Directors had decided to explore a  merger
     or  sale  of  the  stock of the Company.  The Board formed  a  Special
     Committee  of independent directors to oversee the sale process.   The
     Special Committee retained independent financial and legal advisors to
     work closely with management to implement the sale process.

     On  May  3,  2004, the Managing General Partner entered  into  a  cash
     merger  agreement to sell all of its stock to Clayton Williams Energy,
     Inc.  The cash merger price is being negotiated, but is expected to be
     approximately  $45 per share.  The transaction, which  is  subject  to
     approval  by the Managing General Partner's shareholders, is  expected
     to close no later than May 21, 2004.


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

                      Notes to Financial Statements

10.  Estimated Oil and Gas Reserves (unaudited)

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

                                Oil       Gas
                               (bbls)    (mcf)
                              --------  --------
                                 --        -
Total Proved -

January 1, 2001               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

 Production                   (9,000)   (18,000)
  Revisions of estimates  in  1,000     48,000
place
                              --------  --------
                              --        --
December 31, 2003             80,000    266,000
                              ======    ======

Proved developed reserves -

December 31, 2001             79,000    245,000
                              ======    ======
December 31, 2002             88,000    236,000
                              ======    ======
December 31, 2003             80,000    266,000
                              ======    ======

     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

10.  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, 2004.  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, 2004, 2003 and  2002  are  an
     average price of $31.76, $29.67 and $18.90 per barrel, respectively.

     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,  2004, 2003 and 2002 are an average price of $5.30,  $4.49
     and $2.34 per Mcf, respectively.

     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.  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

10.  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, 2003, 2002 and 2001 is
     presented below:

                                   2003      2002      2001
                                   ----      ----      ----

Future cash inflows           $  3,955,00  3,682,00  2,059,00
                                 0         0         0
Production, development and
 abandonment costs               2,113,00  1,945,00  1,334,00
                                 0         0         0
                                 --------  --------  --------
                                 ----      ----      ----
Future net cash flows            1,842,00  1,737,00  725,000
                                 0         0
10%   annual  discount   for
estimated
 timing of cash flows            767,000   680,000   260,000
                                 --------  --------  --------
                                 ----      ----      ----
Standardized   measure    of
discounted
 future net cash flows        $  1,075,00  1,057,00  465,000
                                 0         0
                                 =======   =======   =======

     The  principal  sources  of  change in  the  standardized  measure  of
     discounted  future  net cash flows for the years  ended  December  31,
     2003, 2002 and 2001 are as follows:

                                   2003      2002      2001
                                   ----      ----      ----

Sales   of   oil   and   gas
produced,
 net of production costs      $  (190,000  (150,000  (201,000
                                 )         )         )
Changes   in   prices    and     94,000    549,000   (1,178,0
production costs                                     00)
Changes of production rates
 (timing) and others             (69,000)  (12,000)  177,000
Revisions of previous
 quantities estimates            78,000    159,000   (69,000)
Accretion of discount            105,000   46,000    158,000
Discounted future net
 cash flows -
Beginning of year                1,057,00  465,000   1,578,00
                                 0                   0
                                 --------  --------  --------
                                 ----      ----      ----
End of year                   $  1,075,00  1,057,00  465,000
                                 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

11.  Selected Quarterly Financial Results - (unaudited)

                                             Quarter
                              --------------------------------------
                              --------------------------------------
                                                -
                               First     Second    Third     Fourth
                               ------   --------  -------   --------
                                          ---                  -
2003:
 Total revenues             $ 102,069   88,470    75,271    83,474
 Total expenses               38,013    52,123    53,468    49,007

 Cumulative effect of SFAS    (2,744)   -         -         -
No. 143
                              --------  --------  --------  --------
                              ----      ----      ----      ----
 Net income                 $ 61,312    36,347    21,803    34,467
                              =======   =======   =======   =======
  Per limited partner unit
amounts:
    Net    income   before  $  40.21
cumulative effect                       22.68     13.56     21.56
 Cumulative effect of SFAS    (1.74)         -         -         -
No. 143
                              --------  --------  --------  --------
                              ----      ----      ----      ----
 Net income                 $  38.47
                                        22.68     13.56     21.56
                              =======   =======   =======   =======

     As  discussed  in Note 4, in 2002 the Partnership changed  methods  of
     accounting  for  depletion  of capitalized costs  from  the  units-of-
     revenue  method to the units-of-production method.  The 2002 quarterly
     financial  results  presented below reflect the  change  in  depletion
     method effective as of January 1, 2002.

                                             Quarter
                              --------------------------------------
                              --------------------------------------
                                                -
                               First     Second    Third     Fourth
                               ------   --------  -------   --------
                                          ---                  -
2002:
 Total revenues             $ 53,515    70,937    76,111    74,799
 Total expenses               37,583    34,294    40,738    42,166
                              --------  --------  --------  --------
                              ----      ----      ----      ----
    Net    income   before
cumulative effect of
   a  change in accounting    15,932    36,643    35,373    32,633
principle
   Cumulative  effect   on
prior years (to
   December 31,  2001)  of
changing to a
     different   depletion    (3,000)   -         -         -
method
                              --------  --------  --------  --------
                              ----      ----      ----      ----
 Net income                 $ 12,932    36,643    35,373    32,633
                              =======   =======   =======   =======
  Per limited partner unit
amounts:
    Net    income   before
cumulative effect of a
    change  in  accounting  $   9.77
principle                               22.87     22.14     20.40
   Cumulative  effect   on
prior years (to
   December 31,  2001)  of
changing to a
     different   depletion    (2.13)         -         -         -
method
                              --------  --------  --------  --------
                              ----      ----      ----      ----
Net income                  $   7.64
                                        22.87     22.14     20.40
                              =======   =======   =======   =======


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

None

Item 9A.  Controls and Procedures

Disclosure Controls and Procedures
As  of  the year ended December 31, 2003, H.H. Wommack, III, President  and
Chief  Executive  Officer  of the Managing General  Partner,  and  Bill  E.
Coggin,  Executive  Vice  President and  Chief  Financial  Officer  of  the
Managing  General Partner, evaluated the effectiveness of the Partnership's
disclosure  controls  and  procedures.  Based  on  their  evaluation,  they
believe that:

     The disclosure controls and procedures of the Partnership were
     effective in ensuring that information required to be disclosed by the
     Partnership in the reports it files or submits under the Exchange Act
     was recorded, processed, summarized and reported within the time
     periods specified in the SEC's rules and forms; and

     The  disclosure  controls  and  procedures  of  the  Partnership  were
     effective  in  ensuring  that  material  information  required  to  be
     disclosed by the Partnership in the report it filed or submitted under
     the  Exchange  Act was accumulated and communicated  to  the  Managing
     General  Partner's  management,  including  its  President  and  Chief
     Executive Officer and Chief Financial Officer, as appropriate to allow
     timely decisions regarding required disclosure.

Internal Control Over Financial Reporting
There  has  not been any change in the Partnership's internal control  over
financial reporting that occurred during the year ended December  31,  2003
that has materially affected, or is reasonably likely to materially affect,
it internal control over financial reporting.

<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  of  the
Managing General Partner serves for a term of one year.

         Name               Age               Position
H. H. Wommack, III          48      Chairman   of   the    Board,
                                    President, Director
                                    and Chief Executive Officer
James N. Chapman(1)         41      Director
William P. Nicoletti(2)     58      Director
Joseph J. Radecki,  Jr.     45      Director
(2)
Richard D. Rinehart(1)      68      Director
John M. White(2)            48      Director
Herbert  C. Williamson,     55      Director
III(1)
Bill E. Coggin              49      Executive Vice President  and
                                    Chief Financial Officer
J. Steven Person            45      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.  SRH holds an equity investment in Southwest and  in
Basic  Energy Services.  Since 1997 Mr. Wommack has served as  chairman  of
the  board  of directors of Midland Red Oak Realty, Inc.  Midland  Red  Oak
Realty  owns  and  manages  commercial real  estate  properties,  including
shopping centers and office buildings, in secondary real estate markets  in
the Southwestern United States.  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.  Basic provides certain well services for oil and gas companies.
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 is associated with Regiment Capital Advisors, LLC, which he  joined
in January 2003.  Prior to Regiment, Mr. Chapman acted as a capital markets
and  strategic  planning consultant with private and public  companies,  as
well as hedge funds, across a range of industries. Prior to establishing an
independent  consulting practice, Mr. Chapman worked for The  Renco  Group,
Inc. from December 1996 to December 2001.  Prior to Renco, Mr. Chapman  was
a  founding  principal of Fieldstone Private Capital Group in August  1990.
Prior  to joining Fieldstone, Mr. Chapman worked for Bankers Trust  Company
from  July 1985 to August 1990, most recently in the BT Securities  capital
markets area.  Mr. Chapman serves as a member of the board of directors  of
Anchor  Glass  Container Corporation, Davel Communications, Inc.,  Coinmach
Corporation, as well as a number of private companies.

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 founded in 1991.  He was previously
a  senior officer and head of the Energy Investment Banking Groups of E. F.
Hutton  &  Company Inc. and Paine Webber, Incorporated.   From  March  1998
until June 1990 he was a managing director and co-head of Energy Investment
Banking  at  McDonald Investments Inc.  Mr. Nicoletti  is  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.  He is also a director  of  MarkWest  Energy
Partners,  L.P.,  a  business engaged in the gathering  and  processing  of
natural  gas and the fractionation and storage of natural gas liquids,  and
Russell-Stanley Holdings, Inc., a manufacturer and marketer  of  steel  and
plastic  industrial containers.  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 in 1998, Mr. Radecki was an Executive  Vice
President and Director of the Financial Restructuring Group of Jefferies  &
Company,  Inc.  beginning in 1990.  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. Radecki currently serves as a  Director  of
RBX  Corporation,  a  manufacturer of rubber and  plastic  foam  and  other
polymer  products.   He  previously served  as  a  Director  of  Wherehouse
Entertainment, Inc., a music and video specialty retailer, 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 White has served as a director since April 19, 2002.  Mr. White became
an  equity  analyst for Harris Nesbitt Gerard following the acquisition  by
BMO  Financial  Group in 2003.  He had joined BMO Nesbitt  Burns  in  1998,
responsible  for  high  yield research on oil, gas  and  energy  companies.
Previously,  Mr.  White worked at John S. Herold, Inc., an independent  oil
and  gas  research and consulting firm, where he was responsible for  fixed
income  research  on the oil and gas industry.  His prior  experience  also
included four years managing a portfolio of oil and gas loans for The  Bank
of Nova Scotia.  Before entering financial services, Mr. White was with BP,
where he worked in exploration and production for seven years.  At BP,  his
experience  was  primarily  in the basins of the  Mid-Continent  and  Rocky
Mountain regions.  Mr. White is a graduate of The University of Oklahoma.

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  46, 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 48, 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.

Code of Ethics

Neither the Partnership nor the Managing General Partner has adopted a code
of  ethics  for  employees, or any principal executive officers,  principal
financial officers, principal accounting officers or the Board of Directors
of the Managing General Partner.  The Board of the Managing General Partner
believes  that  the Partnership's existing internal control procedures  and
current business practices are adequate to promote ethical conduct  and  to
deter  wrongdoing  on the part of these executives.  The  Managing  General
Partner  of  the  Partnership intends to implement during 2004  a  code  of
ethics  that will apply to these executives.  In accordance with applicable
SEC rules, the code of ethics will be made publicly available.

Audit Committee

The  current members of the Audit Committee of the Managing General Partner
are  William  P. Nicoletti, John M. White and Joseph J. Radecki,  Jr.   The
Board of Directors of the Managing General Partner has determined that  Mr.
Nicoletti, the Chairman of the Audit Committee, meets the definition of  an
"audit  committee financial expert" under Item 401(h)(2) of Regulation  S-K
and  has  also  determined that all of the members of the Audit  Committee,
including  Mr.  Nicoletti, meet the independence  requirements  of  Section
10A(m)(3) of the Securities Exchange Act of 1934, as amended, and the rules
and regulations promulgated thereunder.

Item 11.  Executive Compensation

The  Partnership  does  not  employ any directors,  executive  officers  or
employees.  The Managing General Partner receives an administrative fee for
the  management of the Partnership.  The Managing General Partner  received
$12,000 during 2003, 2002 and 2001 as an administrative fee.  The executive
officers  of  the  Managing General Partner do  not  receive  any  form  of
compensation,  from  the Partnership; instead, their compensation  is  paid
solely  by  Southwest.  The executive officers, however,  may  occasionally
perform administrative duties for the Partnership but receive no additional
compensation for this work.

<PAGE>
Item  12.   Security Ownership of Certain Beneficial Owners and  Management
and Related Stockholder Matters

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  15.0  limited partner units, or .95% limited partner  interest.   The
Managing  General  Partner  total  percentage  interest  ownership  in  the
Partnership is 11.9%.

No  officer or director of the Managing General Partner directly 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 December
31,  2003.  A list of beneficial owners of limited partner units, known  to
the Managing General Partner, is as follows:

                                                 Amount and
                                                 Nature of      Percen
                                                                  t
                        Name and Address of      Beneficial       of
  Title of Class         Beneficial Owner        Ownership      Class
-------------------    ---------------------     ----------     ------
  --------------          --------------           ------       -----
Limited Partnership    Southwest  Royalties,     Directly        .95%
Interest               Inc.                      Owns
                       Managing      General     15.0 Units
                       Partner
                       407   N.  Big  Spring
                       Street
                       Midland, TX 79701

Limited Partnership    H. H. Wommack, III        Indirectly      .95%
Interest                                         Owns
                       Chairman    of    the     15.0 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.

<PAGE>
Item 13.  Certain Relationships and Related Transactions

In 2003, 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 $23,100 for administrative  overhead
attributable to operating such properties during 2003.

The  terms of the above transactions are similar to ones, which would  have
been  obtained  through arm's length negotiations with  unaffiliated  third
parties.

Item 14.  Principal Accountant Fees and Services

The following table presents fees for professional audit services rendered
by KPMG, LLP for the audit of the Partnership's annual financial statements
for the years ended December 31, 2003 and 2002 and fees billed for other
services rendered by KPMG during those periods.

 For the Year Ended December    2003
             31,                         2002

Audit Fees                     $9,056    $
                                         4,763
Audit Related Fees                  -
                                         -
Tax Fees                            -
                                         -
All Other Fees                      -
                                         -

    TOTAL                      $9,056    $
                                         4,763

The  Audit Committee of the Managing General Partner reviewed and approved,
in advance, all audit and non-audit services provided by KPMG, LLP.



<PAGE>
                                 Part IV


Item 15.  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).

          31.1 Rule 13a-14(a)/15d-14(a) Certification
          31.2 Rule 13a-14(a)/15d-14(a) Certification
           32.1  Certification of Chief Executive Officer  Pursuant  to  18
U.S.C. Section 1350, as
              adopted Pursuant to Section 906 of the Sarbanes-Oxley Act  of
2002
           32.2  Certification of Chief Financial Officer  Pursuant  to  18
U.S.C. Section 1350, as
              adopted Pursuant to Section 906 of the Sarbanes-Oxley Act  of
2002

          (b)     Reports on Form 8-K

                                 No report on Form 8-K was filed during the
                  quarter ended December 31, 2003.

<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:    May 12, 2004

<PAGE>

In  accordance with the Exchange Act, this report has been signed below  by
the following persons on behalf of the Registrant and in the capacities and
on the dates indicated.

/s/ H. H. Wommack, III                       /s/ Bill E. Coggin
---------------------------                  ------------------------
--------------------                         -----------------------
H.    H.   Wommack,    III,                  Bill      E.     Coggin,
Chairman of the Board,                       Executive Vice President
President,   Director   and                  and    Chief   Financial
Chief Executive Officer                      Officer

Date:     May 12, 2004                       Date:     May 12, 2004


/s/ William P. Nicoletti                     /s/ James N. Chapman
---------------------------                  ------------------------
--------------------                         -----------------------
William    P.    Nicoletti,                  James     N.    Chapman,
Director                                     Director

Date:     May 10, 2004                       Date:     May 12, 2004


/s/ Richard D. Rinehart                      /s/  Joseph J.  Radecki,
                                             Jr.
---------------------------                  ------------------------
--------------------                         -----------------------
Richard     D.    Rinehart,                  Joseph J. Radecki,  Jr.,
Director                                     Director

Date:     May 12, 2004                       Date:     May 12, 2004


/s/  Herbert C. Williamson,
III
---------------------------                  ------------------------
--------------------                         -----------------------
Herbert C. Williamson, III,                  John M. White, Director
Director

Date:     May 11, 2004                       Date:



<PAGE>
                    SECTION 302 CERTIFICATION                Exhibit 31.1


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 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 report;

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

4.The  registrant's other certifying officer(s) and I are  responsible  for
  establishing  and  maintaining disclosure  controls  and  procedures  (as
  defined  in  Exchange  Act  Rules 13a-15(e) and  15-15(e))  and  internal
  control  over financial reporting (as defined in Exchange Act Rules  13a-
  15(f) and 15d-15(f) for the registrant and have:

  a)Designed  such  disclosure  controls and  procedures,  or  caused  such
     disclosure   controls  and  procedures  to  be  designed   under   our
     supervision,  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 report is being prepared;

  b)Designed  such  internal control over financial  reporting,  or  caused
     such  internal  control over financial reporting to be designed  under
     our   supervision,  to  provide  reasonable  assurance  regarding  the
     reliability  of financial reporting and the preparation  of  financial
     statements for external purposes in accordance with generally accepted
     accounting principles;

  c)Evaluated  the  effectiveness of the registrant's  disclosure  controls
     and  procedures and presented in this report our conclusions about the
     effectiveness of the disclosure controls and procedures, as of the end
     of the period covered by this report based on such evaluation; and

  d)Disclosed  in  this  report  any change in  the  registrant's  internal
     control over financial reporting that occurred during the registrant's
     most recent fiscal quarter (the registrant's fourth fiscal quarter  in
     the  case  of  an annual report) that has materially affected,  or  is
     reasonably  likely  to  materially affect, the  registrant's  internal
     control over financial reporting; and

5.The  registrant's other certifying officer(s) and I have disclosed, based
  on  our  most  recent  evaluation  of  internal  control  over  financial
  reporting,  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 and material weaknesses in the design  or
     operation   of  internal  controls  over  financial  reporting   which
     reasonably  likely  to  adversely affect the registrant's  ability  to
     record, process, summarize and report financial information; 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 over financial reporting.


Date:  May 12, 2004                /s/ H. H. Wommack, III
                                   H. H. Wommack, III
                                    Chairman, President and Chief Executive
Officer
                                   of Southwest Royalties, Inc., the
                                   Managing General Partner of
                                   Southwest Developmental Drilling Fund 92-
A, L.P.



<PAGE>
                    SECTION 302 CERTIFICATION                Exhibit 31.2


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 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 report;

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

4.The  registrant's other certifying officer(s) and I are  responsible  for
  establishing  and  maintaining disclosure  controls  and  procedures  (as
  defined  in  Exchange  Act  Rules 13a-15(e) and  15-15(e))  and  internal
  control  over financial reporting (as defined in Exchange Act Rules  13a-
  15(f) and 15d-15(f) for the registrant and have:

  a)Designed  such  disclosure  controls and  procedures,  or  caused  such
     disclosure   controls  and  procedures  to  be  designed   under   our
     supervision,  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 report is being prepared;

  b)Designed  such  internal control over financial  reporting,  or  caused
     such  internal  control over financial reporting to be designed  under
     our   supervision,  to  provide  reasonable  assurance  regarding  the
     reliability  of financial reporting and the preparation  of  financial
     statements for external purposes in accordance with generally accepted
     accounting principles;

  c)Evaluated  the  effectiveness of the registrant's  disclosure  controls
     and  procedures and presented in this report our conclusions about the
     effectiveness of the disclosure controls and procedures, as of the end
     of the period covered by this report based on such evaluation; and

  d)Disclosed  in  this  report  any change in  the  registrant's  internal
     control over financial reporting that occurred during the registrant's
     most recent fiscal quarter (the registrant's fourth fiscal quarter  in
     the  case  of  an annual report) that has materially affected,  or  is
     reasonably  likely  to  materially affect, the  registrant's  internal
     control over financial reporting; and

5.The  registrant's other certifying officer(s) and I have disclosed, based
  on  our  most  recent  evaluation  of  internal  control  over  financial
  reporting,  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 and material weaknesses in the design  or
     operation   of  internal  controls  over  financial  reporting   which
     reasonably  likely  to  adversely affect the registrant's  ability  to
     record, process, summarize and report financial information; 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 over financial reporting.


Date:  May 12, 2004                /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>

           CERTIFICATION PURSUANT TO               Exhibit 32.1
                          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, L.P. (the "Company") on Form 10-K for the period ending
December  31, 2003 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:  May 12, 2004




/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        Exhibit 32.2
                          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, L.P. (the "Company") on Form 10-K for the period ending December
31,  2003 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:

     (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:  May 12, 2004




/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>