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

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

For the fiscal year ended December 31, 1998

                                    OR

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

For the transition period from                      to

Commission File Number 33-38511

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

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

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

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

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

                                   None

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

                  limited and general partner interests

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

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

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

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

<PAGE>
                            Table of Contents

Item                                                                   Page

                                  Part I

 1.  Business                                                            3

 2.  Properties                                                          6

 3.  Legal Proceedings                                                   8

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

                                 Part II

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

 6.  Selected Financial Data                                            10

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

 8.  Financial Statements and Supplementary Data                        20

 9.  Changes in and Disagreements with Accountants
     on Accounting and Financial Disclosure                             38

                                 Part III

10.  Directors and Executive Officers of the Registrant                 39

11.  Executive Compensation                                             42

12.  Security Ownership of Certain Beneficial Owners and
     Management                                                         42

13.  Certain Relationships and Related Transactions                     42

                                 Part IV

14.  Exhibits, Financial Statement Schedules, and Reports
     on Form 8-K                                                        43

     Signatures                                                         45

<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  98  individuals,  together  with   certain
independent  consultants  used  on an "as needed"  basis,  perform  various
services on behalf of the Partnership, including the selection of leasehold
interests  upon  which drilling would be performed, and  the  marketing  of
future anticipated production from such properties.  The Partnership has no
employees.

Principal Products, Marketing and Distribution
The  Partnership has acquired undeveloped leasehold interests  and  drilled
oil and gas properties located in Texas and New Mexico.  All activities  of
the Partnership are confined to the continental United States.  All oil and
gas  produced from these properties will be sold to unrelated third parties
in the oil and gas business.

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

<PAGE>

During 1998 oil prices fell to their lowest daily levels since 1986 and  to
their lowest annual average since 1976.  In two years, oil prices have been
sliced  by  more  than half.  The factors that started the decline  in  oil
prices in 1997 are the same ones that have kept them down in 1998.  It  was
believed  that there would be continued heavy consumption coming  from  the
Asian  region, but the collapse of their markets late in 1997 carried  over
to  this year bringing demand down with it.  Asian consumption had all  but
disappeared  in  1998, creating an oversupply of crude oil on  the  market.
That  drop  in  demand has lasted longer than anyone had  anticipated,  but
hopes  of  a  recovery abound.  Another reason for the  continued  drop  in
prices  has  been OPEC's unwillingness to completely comply with production
cuts  established in March and again in June.  Although they have been near
90%  compliance at times, they have also been below 70% on a monthly basis.
Even  a  four-day bombing in December of Iraqi military sites could  create
only a one-day rally in oil prices.  Crude oil closed December 31, 1998  at
$12.05  per  barrel  on the NYMEX and posted prices  closed  at  $9.50  per
barrel.

In  a  year  of fairly optimistic expectations for gas prices, the  average
price  of natural gas wound up declining in 1998 to its lowest level  since
1995.   Although the nationwide average did remain above $2.00  per  MMBTU,
1998's  prices were approximately 17% lower than those seen in  1997.   The
combination  of mild weather throughout the year and a gas storage  surplus
both  contributed to the low prices.  Analysts' predictions for 1999 prices
vary,  ranging from a low of $1.87 per MMBTU to a high of $2.40 per  MMBTU.
Reduced  production  throughout the U.S. industry,  along  with  large  gas
storage  withdrawals during the first weeks of January 1999, are  both  key
factors  in  our belief that the 1999 average gas price will remain  around
$1.80 per MMBTU level.

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

                                  Oil          Gas

                    1998          74%          26%
                    1997          76%          24%
                    1996          76%          24%

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

Seasonality of Business
Although the demand for natural gas is highly seasonal, with higher  demand
in  the colder winter months and in very hot summer months, the Partnership
anticipates  that  it  will  be able to sell all  of  the  expected  future
production  of natural gas, either through contracts or on the spot  market
at the then prevailing spot market price.

<PAGE>

Customer Dependence
No  material portion of the Partnership's business is dependent on a single
purchaser,  or a very few purchasers, where the loss of one  would  have  a
material adverse impact on the Partnership.  Three purchasers accounted for
95% of the Partnership's total oil and gas production during 1998: Scurlock
Permian  Corporation for 59%, Duke Energy Transport and Trad. for  20%  and
Navajo Refining Company, Inc. for 16%.  Three purchasers accounted for  94%
of  the  Partnership's total oil and gas production during  1997:  Scurlock
Permian Corporation for 60%, Aquila Southwest Pipeline Corporation for  19%
and  Navajo Refining Company, Inc. for 15%.  Three purchasers accounted for
96%  of  the  partnership's  total  oil and  gas  production  during  1996:
Scurlock Permian Corporation 60%, Aquila Southwest Pipeline Corporation 19%
and  Navajo Refining Company Inc. 17%.  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.

<PAGE>

Various  aspects of the Partnership's oil and gas activities are  regulated
by  administrative agencies under statutory provisions of the states  where
such  activities  are  conducted and by certain  agencies  of  the  federal
government for operations on Federal leases.  Moreover, certain  prices  at
which  the  Partnership may sell its future expected natural gas production
are  controlled  by  the Natural Gas Policy Act of 1978,  the  Natural  Gas
Wellhead  Decontrol  Act  of 1989 and the regulations  promulgated  by  the
Federal Energy Regulatory Commission.

Environmental  - The Partnership's oil and gas activities  are  subject  to
extensive  federal,  state  and local laws and  regulations  governing  the
generation,  storage, handling, emission, transportation and  discharge  of
materials into the environment.  Governmental authorities have the power to
enforce compliance with their regulations, and violations carry substantial
penalties.   This  regulatory burden on the oil and gas industry  increases
its cost of doing business and consequently affects its profitability.  The
Managing  General  Partner  is  unable to  predict  what,  if  any,  effect
compliance will have on the Partnership.

Industry  Regulations  and  Guidelines - Certain industry  regulations  and
guidelines  apply to the registration, qualification and operation  of  oil
and  gas programs in the form of limited partnerships.  The Partnership  is
subject  to  these  guidelines  which regulate  and  restrict  transactions
between  the Managing General Partner and the Partnership.  The Partnership
complies  with these guidelines and the Managing General Partner  does  not
anticipate that continued compliance will have a material adverse effect on
Partnership operations.

Partnership Employees
The Partnership has no employees; however, the Managing General Partner has
a  staff of geologists, engineers, accountants, landmen and clerical  staff
who  engage in Partnership activities and operations and perform additional
services  for  the  Partnership as needed.  In  addition  to  the  Managing
General  Partner's  staff, the Partnership engages independent  consultants
such  as petroleum engineers and geologists as needed.  As of December  31,
1998,  there were 98 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, 1998, the Partnership possessed an interest in oil  and
gas properties located in Ward County of Texas and Lea and Eddy Counties of
New  Mexico and Ward County of Texas.  These properties consist of  various
interests in 9 wells.

Due  to  the  Partnership's  objective of  maintaining  current  operations
without  engaging  in  the  additional drilling  of  any  developmental  or
exploratory  wells,  or  additional acquisitions of  producing  properties,
there has not been any significant changes in properties during 1998,  1997
and 1996.

<PAGE>

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

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

Mobil Fee G #1        12/92 at            1         22,000         42,000
Ward County,          100%
Texas                 working
                      interest

Mobil Fee H #1        12/92 at            1         48,000        119,000
Ward County,          100%
Texas                 working
                      interest

*Ryder  Scott Company Petroleum Engineers prepared the reserve and  present
value data for 96.4% of the Partnership's existing properties as of January
1,  1999.   Another independent petroleum engineer prepared  the  remaining
3.6%  of the Partnership's properties.  The reserve estimates were made  in
accordance  with  guidelines  established by the  Securities  and  Exchange
Commission  pursuant  to Rule 4-10(a) of Regulation S-X.   Such  guidelines
require oil and gas reserve reports be prepared under existing economic and
operating  conditions  with  no provisions for price  and  cost  escalation
except by contractual arrangements.

The  New York Mercantile Exchange price at December 31, 1998 of $12.05  was
used  as the beginning basis for the oil price.  Oil price adjustments from
$12.05  per  barrel were made in the individual evaluations to reflect  oil
quality,  gathering and transportation costs.  The results are  an  average
price received at the lease of $10.83 per barrel in the preparation of  the
reserve report as of January 1, 1999.

In  the  determination of the gas price, the New York  Mercantile  Exchange
price  at December 31, 1998 of $1.95 was used as the beginning basis.   Gas
price   adjustments  from  $1.95  per  Mcf  were  made  in  the  individual
evaluations to reflect BTU content, gathering and transportation costs  and
gas processing and shrinkage.  The results are an average price received at
the  lease of $1.99 per Mcf in the preparation of the reserve report as  of
January 1, 1999.

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 1998.

<PAGE>

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

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

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

Item 3.   Legal Proceedings

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

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

No  matter  was submitted to a vote of security holders during  the  fourth
quarter of 1998 through the solicitation of proxies or otherwise.

<PAGE>
                                 Part II


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

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

The  Managing  General Partner has the right, but not  the  obligation,  to
purchase limited partnership units should an investor desire to sell.   The
value  of  the  unit is determined by adding the sum of (1) current  assets
less  liabilities  and  (2) the present value of the  future  net  revenues
attributable to proved reserves and by discounting the future net  revenues
at  a rate not in excess of the prime rate charged by Nations Bank, N.A. of
Midland, Texas, plus one percent (1%), which value shall be further reduced
by  a risk factor discount of no more than one-third (1/3) to be determined
by  the Managing General Partner in its sole and absolute discretion. As of
December  31, 1998, 1997 and 1996, no limited partner units were  purchased
by the Managing General Partner.


Number of Limited and General Partner Interest Holders
As of December 31, 1998, there were 104 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  monthly basis.  "Net Cash Flow" is defined  as  "the  cash
generated  by the Partnership's drilling activities, less (i)  General  and
Administrative  Costs,  (ii)  Operating  Costs,  and  (iii)  any   reserves
necessary  to  meet  current  and anticipated  needs  of  the  Partnership,
including, but not limited to drilling cost overruns, as determined in  the
sole discretion of the Managing General Partner."

<PAGE>
During  1998,  distributions  were  made  totaling  $92,200,  with  $82,058
distributed  to  the investor partners and $10,142 to the Managing  General
Partners.   For the year ended December 31, 1998, distributions  of  $58.32
per  investor  partner  unit were made, based upon 1,407  investor  partner
units  outstanding.  The decline in distributions experienced in 1998  will
be  expected  to continue into 1999 based on the continued  low  oil  price
economy.  During  1997,  twelve monthly distributions  were  made  totaling
$205,500, with $182,895 distributed to the investor partners and $22,605 to
the  Managing  General  Partners.  For the year ended  December  31,  1997,
distributions  of $129.99 per investor partner unit were made,  based  upon
1,407  investor  partner units outstanding.  During  1996,  twelve  monthly
distributions were made totaling $250,000, with $222,500 distributed to the
investor  partners and $27,500 to the Managing General Partners.   For  the
year ended December 31, 1996, distributions of $158.14 per investor partner
unit were made, based upon 1,407 investor partner units outstanding.

Item 6.   Selected Financial Data

The following selected financial data for the year ended December 31, 1998,
1997,  1996, 1995 and 1994 should be read in conjunction with the financial
statements included in Item 8:

                                       Year ended December 31,
                           ------------------------------------------------
                               1998    1997      1996      1995     1994
                               ----    ----      ----      ----     ----

Revenues              $   201,370     335,791   425,671  455,640  405,099

Net income (loss)       (331,847)      93,437   178,706  165,968  103,054

Partners' share of net
 income (loss):

  Managing General
   Partner                  6,863      19,601    28,208   29,338   22,747

  Investor partners     (338,710)      73,836   150,498  136,630   80,307

Investor partners' net
  income (loss) per unit              (240.73)     52.48   106.96     97.11
57.08

Investor partners' cash
  distributions per unit                 58.32    129.99   158.14    170.79
63.21

Total assets          $   258,508     682,573   794,538  865,832  969,949

<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  it's
historical decline of approximately 7% per year.

<PAGE>
Results of Operations

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

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

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

Average price per barrel of oil            $   12.75    20.06    (36%)
Average price per mcf of gas               $    1.93     2.65    (27%)
Oil production in barrels                     11,700   12,700     (8%)
Gas production in mcf                         26,800   30,000    (11%)
Gross oil and gas revenue                  $ 200,761  334,355    (40%)
Net oil and gas revenue                    $  86,072  195,115    (56%)
Partnership distributions                  $  92,200  205,500    (55%)
Limited partner distributions              $  82,058  182,895    (55%)
Per unit distribution to limited partners  $   58.32   129.99    (55%)
Number of limited partner units                1,407    1,407

Revenues

The  Partnership's oil and gas revenues decreased to $200,761 from $334,355
for the years ended December 31, 1998 and 1997, respectively, a decrease of
40%.   The  principal factors affecting the comparison of the  years  ended
December 31, 1998 and 1997 are as follows:

1.  The  average  price  for a barrel of oil received  by  the  Partnership
    decreased  during the year ended December 31, 1998 as compared  to  the
    year ended December 31, 1997 by 36%, or $7.31 per barrel, resulting  in
    a decrease of approximately $92,800 in revenues.  Oil sales represented
    74%  of total oil and gas sales during the year ended December 31, 1998
    as compared to 76% during the year ended December 31, 1997.

    The  average  price  for  an  mcf of gas received  by  the  Partnership
    decreased during the same period by 27%, or $.72 per mcf, resulting  in
    a decrease of approximately $21,600 in revenues.

    The  total  decrease in revenues due to the change in  prices  received
    from  oil  and  gas production is approximately $114,400.   The  market
    price  for oil and gas has been extremely volatile over the past decade
    and  management expects a certain amount of volatility to  continue  in
    the foreseeable future.

<PAGE>

2.  Oil production decreased approximately 1,000 barrels or 8% during the
   year ended December 31, 1998 as compared to the year ended December 31,
   1997, resulting in a decrease of approximately $12,800 in revenues.

    Gas production decreased approximately 3,200 mcf or 11% during the same
    period, resulting in a decrease of approximately $6,200 in revenues.

    The  total  decrease  in revenues due to the change  in  production  is
    approximately $19,000.

Costs and Expenses

Total  costs and expenses increased to $533,217 from $242,354 for the years
ended  December 31, 1998 and 1997, respectively, an increase of 120%.   The
increase   is   the  result  of  higher  depletion  expense,  general   and
administrative expense and provision for impairment, partially offset by  a
decrease in lease operating costs.

1.    Lease  operating  costs  and production  taxes  were  18%  lower,  or
   approximately $24,600 less during the year ended December  31,  1998  as
   compared to the year ended December 31, 1997.  Decrease is due primarily to
   a decrease in advalorem and production taxes.

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
    32% or approximately $5,900 during the year ended December 31, 1998  as
    compared to the year ended December 31, 1997.  The increase in  general
    and  administrative costs are the result of higher accounting fees  due
    to the necessity of contracting out preparation of tax depletion and K-
    1 schedules.

3.  Depletion expense increased to $80,000 for the year ended December  31,
    1998  from  $76,000  for the same period in 1997.  This  represents  an
    increase  of  5%.  Depletion is calculated using the units  of  revenue
    method  of  amortization based on a percentage of current period  gross
    revenues  to  total future gross oil and gas revenues, as estimated  by
    the Partnership's independent petroleum consultants.

    A  contributing factor to the increase in depletion expense between the
    comparative periods was the decrease in the price of oil and  gas  used
    to determine the Partnership's reserves for January 1, 1999 as compared
    to  1998.   Another  contributing factor  was  due  to  the  impact  of
    revisions  of  previous estimates on reserves.  Revisions  of  previous
    estimates  can be attributed to the changes in production  performance,
    oil  and  gas  price and production costs.  The impact of the  revision
    would  have  increased depletion expense approximately  $16,000  as  of
    December 31, 1997.

4.  The  Partnership  reduced the net capitalized  costs  of  oil  and  gas
    properties  by $314,240.  This provision for impairment had the  effect
    of  reducing  net  income,  but did not affect  cash  flow  or  partner
    distributions.   See Summary of Significant Accounting Policies  -  Oil
    and Gas Properties.


<PAGE>


Results of Operations

B.  General Comparison of the Years Ended December 31, 1997 and 1996

The  following  table  provides certain information  regarding  performance
factors for the years ended December 31, 1997 and 1996:

                                                  Year Ended     Percentage
                                                 December 31,     Increase
                                                1997      1996   (Decrease)
                                                ----      ----   ---------

Average price per barrel of oil            $   20.06    20.64     (3%)
Average price per mcf of gas               $    2.65     2.99    (11%)
Oil production in barrels                     12,700   15,600    (19%)
Gas production in mcf                         30,000   34,300    (13%)
Gross oil and gas revenue                  $ 334,355  424,676    (21%)
Net oil and gas revenue                    $ 195,115  274,432    (29%)
Partnership distributions                  $ 205,500  250,000    (18%)
Limited partner distributions              $ 182,895  222,500    (18%)
Per unit distribution to limited partners  $  129.99   158.14    (18%)
Number of limited partner units                1,407    1,407

Revenues

The  Partnership's oil and gas revenues decreased to $334,355 from $424,676
for the years ended December 31, 1997 and 1996, respectively, a decrease of
21%.   The  principal factors affecting the comparison of the  years  ended
December 31, 1997 and 1996 are as follows:

1.  The  average  price  for a barrel of oil received  by  the  Partnership
    decreased  during the year ended December 31, 1997 as compared  to  the
    year ended December 31, 1996 by 3%, or $.58 per barrel, resulting in  a
    decrease  of  approximately $9,000 in revenues.  Oil sales  represented
    76%  of total oil and gas sales during the year ended December 31, 1997
    as compared to 76% during the year ended December 31, 1996.

    The  average  price  for  an  mcf of gas received  by  the  Partnership
    decreased during the same period by 11%, or $.34 per mcf, resulting  in
    a decrease of approximately $11,700 in revenues.

    The  total  decrease in revenues due to the change in  prices  received
    from oil and gas production is approximately $20,700.  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 2,900 barrels or 19% during the
   year ended December 31, 1997 as compared to the year ended December 31,
   1996, resulting in a decrease of approximately $58,200 in revenues.

    Gas production decreased approximately 4,300 mcf or 13% during the same
    period, resulting in a decrease of approximately $11,400 in revenues.

    The  total  decrease  in revenues due to the change  in  production  is
    approximately $69,600.  The decrease is attributable to normal decline.

Costs and Expenses

Total  costs and expenses decreased to $242,354 from $246,965 for the years
ended  December  31, 1997 and 1996, respectively, a decrease  of  2%.   The
decrease  is  the  result of lower lease operating costs  and  general  and
administrative expense, partially offset by depletion expense.

2.    Lease  operating  costs  and  production  taxes  were  7%  lower,  or
   approximately $11,000 less during the year ended December  31,  1997  as
   compared to the year ended December 31, 1996.

2.  General and administrative costs consist of independent accounting  and
    engineering  fees,  computer services, postage,  and  Managing  General
    Partner  personnel costs.    General and administrative costs decreased
    3%  or  approximately $600 during the year ended December 31,  1997  as
    compared to the year ended December 31, 1996.

3.  Depletion expense increased to $76,000 for the year ended December  31,
    1997  from  $69,000  for the same period in 1996.  This  represents  an
    increase  of 10%.  Depletion is calculated using the units  of  revenue
    method  of  amortization based on a percentage of current period  gross
    revenues  to  total future gross oil and gas revenues, as estimated  by
    the Partnership's independent petroleum consultants.

    A  contributing factor to the increase in depletion expense between the
    comparative periods was the decrease in the price of oil and  gas  used
    to determine the Partnership's reserves for January 1, 1998 as compared
    to  1997.   Another  contributing factor  was  due  to  the  impact  of
    revisions  of  previous estimates on reserves.  Revisions  of  previous
    estimates  can be attributed to the changes in production  performance,
    oil  and  gas  price and production costs.  The impact of the  revision
    would  have  increased depletion expense approximately  $13,000  as  of
    December 31, 1996.

<PAGE>

C.   Revenue and Distribution Comparison

Partnership net income (loss) for the years ended December 31,  1998,  1997
and 1996 was $(331,847), $93,437 and $178,706, respectively.  Excluding the
effects  of  depreciation,  depletion and amortization  and  provision  for
impairment, net income (loss) for the years ended December 31,  1998,  1997
and  1996,  would have been $(62,393), $178,193 and $256,442, respectively.
Correspondingly, Partnership distributions for the years ended December 31,
1998,  1997  and  1996 were $92,200, $205,500 and  $250,000,  respectively.
These  differences  are indicative of the changes in oil  and  gas  prices,
production and property during 1998, 1997 and 1996.

The  sources  for  the  1998  distributions of $92,200  were  oil  and  gas
operations  of  approximately  $90,900  and  the  change  in  oil  and  gas
properties of approximately $900, with the balance from available  cash  on
hand   at  the  beginning  of  the  period.   The  sources  for  the   1997
distributions  of  $205,500  were oil and gas operations  of  approximately
$195,400  and  the change in oil and gas properties of approximately  $200,
with  the  balance  from available cash on hand at  the  beginning  of  the
period.  The source for the 1996 distributions of $250,000 were oil and gas
operations   of  approximately  $260,100  resulting  in  excess   cash   of
contingencies or subsequent distributions.

Total distributions during the year ended December 31, 1998 were $92,200 of
which  $82,058 was distributed to the investor partners and $10,142 to  the
Managing  General Partners.  The per unit distribution to investor partners
during  the  same period was $58.32.  Total distributions during  the  year
ended December 31, 1997 were $205,500 of which $182,895 was distributed  to
the  investor  partners and $22,605 to the Managing General Partners.   The
per  unit  distribution to investor partners during  the  same  period  was
$129.99.  Total distributions during the year ended December 31, 1996  were
$250,000  of  which $222,500 was distributed to the investor  partners  and
$27,500  to  the  Managing General Partners.  The per unit distribution  to
investor partners during the same period was $158.14.

Since  inception of the Partnership, cumulative monthly cash  distributions
of  $1,067,915  have been made to the partners.  As of December  31,  1998,
$950,820 or $675.78 per investor partner unit, has been distributed to  the
investor partners, representing a 68% return of the capital contributed.

<PAGE>
Liquidity and Capital Resources

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

Cash  flows provided by operating activities were approximately $90,900  in
1998 compared to $195,400 in 1997 and approximately $260,100 in 1996.   The
primary  source  of  the  1998  cash flow  from  operating  activities  was
profitable operations.

Cash flows provided by investing activities were approximately $900 in 1998
compared  to  $200  in  1997.   There were no  cash  flows  from  investing
activities during 1996.

Cash  flows used in financing activities were approximately $92,200 in 1998
compared to $205,400 in 1997 and approximately $250,000 in 1996.  The  only
use in the 1998 financing activities was the distributions to partners.

As  of  December 31, 1998, the Partnership had $15,200 in working  capital.
The  Managing  General Partner knows of no unusual contractual  commitments
and believes the revenue generated from operations are adequate to meet the
needs of the Partnership.

Liquidity - Managing General Partner

The  Managing General Partner has a highly leveraged capital structure with
over   $21.0  million  of  interest  payments  due  in  1999  on  its  debt
obligations.   Due  to  severely depressed commodity prices,  the  Managing
General  Partner  is experiencing difficulty in generating sufficient  cash
flow  to  meet  its obligations and sustain its operations.   The  Managing
General  Partner is currently in the process of renegotiating the terms  of
its  various obligations with its creditors and/or attempting to  seek  new
lenders  or  equity investors.  Additionally, the Managing General  Partner
would   consider  disposing  of  certain  assets  in  order  to  meet   its
obligations.

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

Information Systems for the Year 2000

The  Managing  General Partner provides all data processing  needs  of  the
Partnership.  The Managing General Partner is continuing in its  effort  to
identify  and  assess its exposure to the potential Year 2000 software  and
imbedded  chip processing and date sensitivity issue.  Through the Managing
General  Partners  data processing subsidiary, Midland Southwest  Software,
Inc., the Managing General Partner proactively initiated a plan to identify
applicable hardware and software, assess impact and effect, estimate costs,
construct and implement corrective actions, and prepare contingency plans.

<PAGE>
Identification & Assessment

The  Managing  General  Partner currently believes it  has  identified  the
internal  and external software and hardware that may have date sensitivity
problems.  Four critical systems and/or functions were identified:  (1) the
proprietary software of the Partnership (OGAS) that is used for oil  &  gas
property management and financial accounting functions, (2) the DEC VAX/VMS
hardware and operating system, (3) various third-party application software
including  lease  economic  analysis, fixed  asset  management,  geological
applications, and payroll/human resource programs, and (4) External Agents.

The  proprietary  software of the Partnership is currently  in  process  of
meeting  compliance requirements with an estimated completion date of  mid-
year  1999.   Since this is an internally generated software  package,  the
Managing General Partner has estimated the cost to be approximately $25,000
by  estimating the necessary man-hours.  These modifications are being made
by internal staff and do not represent additional costs to the Partnership.
The  Managing General Partner has not made contingency plans at  this  time
since  the  conversion is ahead of schedule and being handled  by  Managing
General  Partner controlled internal programmers.  Given the complexity  of
the systems being modified, it is anticipated that some problems may arise,
but  with  an expected early completion date, the Managing General  Partner
feels that adequate time is available to overcome unforeseen delays.

DEC has released a fully compliant version of its operating system that  is
used  by  the  Partnership on the DEC VAX system.  It will be installed  in
August 1999, the Managing General Partner believes that this will solve any
potential problems on the system.

The  Managing  General Partner has identified various third-party  software
that may have date sensitivity problems and is working with the vendors  to
secure  solutions as well as prepare contingency plans.  After  review  and
evaluation  of  the vendor plans and status, the Managing  General  Partner
believes that the problems will be resolved prior to the year 2000  or  the
alternate  contingency plan will sufficiently and adequately remediate  the
problem so that there is no material disruption to business functions.

The  External  Agents  of  the  Partnership include  suppliers,  customers,
owners,  vendors, banks, product purchasers including pipelines, and  other
oil  and  gas property operators.  The Managing General Partner is  in  the
process of identifying and communicating with each critical External  Agent
about  its  plan  and progress thereof in addressing the Year  2000  issue.
This process is on schedule and the Managing General Partner, at this time,
believes  that  there  should  be no material  interference  or  disruption
associated with any of the critical External Agent's functions necessary to
the   Partnership's  business.   The  Managing  General  Partner  estimates
completion of this audit by mid-year 1999 and believes that alternate plans
can  be  devised to circumvent any material problems arising from  critical
External Agent noncompliance.

Cost

To  date,  the Managing General Partner has incurred only minimal  internal
man-hour costs for identification, planning, and maintenance.  The Managing
General  Partner believes that the necessary additional costs will also  be
minimal  and most will fall under normal and general maintenance procedures
and updates.  An accurate cost cannot be determined at this time, but it is
expected  that  the total cost to remediate all systems  to  be  less  than
$50,000.

<PAGE>
Risks/Contingency

The  failure to correct critical systems of the Partnership, or the failure
of  a  material business partner or External Agent to resolve critical Year
2000  issues  could  have a serious adverse impact on the  ability  of  the
Partnership  to  continue operations and meet obligations.   Based  on  the
Managing  General  Partner's  evaluation and  assessment  to  date,  it  is
believed  that any interruption in operation will be minor and  short-lived
and  pose no material monetary loss, safety, or environmental risk  to  the
Partnership.   However, until all assessment is complete, it is  impossible
to accurately identify the risks, quantify potential impacts or establish a
final  contingency  plan. The Managing General Partner  believes  that  its
assessment and contingency planning will be complete no later than mid-year
1999.

Worst Case Scenario

The  Securities and Exchange Commission requires that public companies must
forecast the most reasonably likely worst case Year 2000 scenario, assuming
that  the  Managing  General Partner's Year 2000  plan  is  not  effective.
Analysis  of the most reasonably likely worst case Year 2000 scenarios  the
Partnership  may face leads to contemplation of the following possibilities
which,  though  considered  highly  unlikely,  must  be  included  in   any
consideration  of worst cases: widespread failure of electrical,  gas,  and
similar   supplies   by  utilities  serving  the  Partnership;   widespread
disruption  of  the  services of communications  common  carriers;  similar
disruption to means and modes of transportation for the Partnership and its
employees, contractors, suppliers, and customers; significant disruption to
the  Partnership's  ability to gain access to,  and  continue  working  in,
office  buildings  and other facilities; and the failure, of  third-parties
systems,  the  effects  of which would have a cumulative  material  adverse
impact  on  the  Partnership's  critical systems.   The  Partnership  could
experience  an inability by customers, traders, and others  to  pay,  on  a
timely  basis or at all, obligations owed to the Partnership.  Under  these
circumstances, the adverse effect on the Partnership, and the diminution of
Partnership revenues, could be material, although not quantifiable at  this
time.



<PAGE>
Item 8.  Financial Statements and Supplementary Data

                      Index to Financial Statements

                                                                       Page

Independent Auditors Reports                                            21

Balance Sheets                                                          23

Statement of Operations                                                 24

Statement of Changes in Partners' Equity                                25

Statements of Cash Flows                                                26

Notes to Financial Statements                                           28

<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, 1998  and  1997,
and  the related statements of operations, changes in partners' equity  and
cash  flows for the years then ended.  These financial statements  are  the
responsibility of the Partnership's management.  Our responsibility  is  to
express an opinion on these financial statements based on our audits.

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

In  our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Southwest Developmental
Drilling Fund 92-A as of December 31, 1998 and 1997 and the results of  its
operations  and its cash flows for the years then ended in conformity  with
generally accepted accounting principles.



                        KPMG LLP



Midland, Texas
March 18, 1999

<PAGE>










                    REPORT OF INDEPENDENT ACCOUNTANTS


To the Partners
Southwest Developmental Drilling
 Fund 92-A, L.P.
Midland, Texas

We  have  audited  the  accompanying statements of operations,  changes  in
partners' equity and cash flows of Southwest Developmental Drilling Fund 92-
A,  L.P.  for the year ended December 31, 1996.  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 audit.

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

In  our  opinion, the statements of operations, changes in partners  equity
and  cash flows referred to above present fairly, in all material respects,
the  results  of  operations  and  cash flows  of  Southwest  Developmental
Drilling  Fund  92-A,  L.P.  for  the year  ended  December  31,  1996,  in
conformity with generally accepted accounting principles.


                        JOSEPH DECOSIMO AND COMPANY
                           A   Tennessee   Registered   Limited   Liability
Partnership


Chattanooga, Tennessee
March 14, 1997

<PAGE>


             Southwest Developmental Drilling Fund 92-A, L.P.
                     (a Delaware limited partnership)
                              Balance Sheets
                        December 31, 1998 and 1997


                                                     1998        1997
                                                     ----        ----
  Assets

Current assets:
 Cash and cash equivalents                   $         7,512        7,887
 Receivable from Managing General Partner              7,814       36,334

---------                                    ---------
                                                 Total    current    assets
15,326                                       44,221

---------                                    ---------
Oil and gas properties - using the full-
 cost method of accounting                         1,314,422    1,315,352
  Less accumulated depreciation,
                                               depletion  and  amortization
1,071,240                                    677,000

---------                                    ---------
                                              Net  oil  and gas  properties
243,182                                      638,352

---------                                    ---------
                                                                          $
258,508                                      682,573

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

  Liabilities and Partners' Equity

Current liability - Distribution payable     $            80           98

---------                                    ---------
Partners' equity:
 Investor partners                                   233,678      654,446
 Managing General Partner                             24,750       28,029

---------                                    ---------
                                                Total    partners'   equity
258,428                                      682,475

---------                                    ---------
                                                                          $
258,508                                      682,573

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























                  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, 1998, 1997 and 1996


                                                 1998      1997     1996
                                                 ----      ----     ----
  Revenues

Oil and gas sales                         $    200,761   334,355  424,676
Interest income from operations                    609     1,436      995
                                                                    -------
-------                                   -------
                                                                    201,370
335,791                                   425,671
                                                                    -------
-------                                   -------

  Expenses

Production                                     114,689   139,240  150,244
General and administrative                      24,288    18,358   18,985
Depreciation, depletion and amortization        80,000    84,756   77,736
Provision for impairment of oil and gas
 properties                                    314,240         -        -
                                                                    -------
-------                                   -------
                                                                    533,217
242,354                                   246,965
                                                                    -------
-------                                   -------
Net income (loss)                         $  (331,847)    93,437  178,706
                                                                    =======
=======                                   =======
Net income (loss) allocated to:

 Managing General Partner                 $      6,863    19,601   28,208
                                                                    =======
=======                                   =======
 Investor partners                        $  (338,710)    73,836  150,498
                                                                    =======
=======                                   =======
  Per investor partner unit               $    (240.73)    52.48   106.96
                                                                    =======
=======                                   =======

























                  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, 1998, 1997 and 1996


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

Balance at December 31, 1995              $     30,325   835,507  865,832

 Net income                                     28,208   150,498  178,706

 Distributions                                (27,500) (222,500)(250,000)
                                                                     ------
---------                                 ---------
Balance at December 31, 1996                    31,033   763,505  794,538

 Net income                                     19,601    73,836   93,437

 Distributions                                (22,605) (182,895)(205,500)
                                                                     ------
---------                                 --------
Balance at December 31, 1997                    28,029   654,446  682,475

 Net income (loss)                               6,863 (338,710)(331,847)

 Distributions                                (10,142)  (82,058) (92,200)
                                                                     ------
---------                                 --------
Balance at December 31, 1998              $     24,750   233,678  258,428
                                                                     ======
=========                                 ==========






























                  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, 1998, 1997 and 1996


                                                 1998      1997     1996
                                                 ----      ----     ----

Cash flows from operating activities:

 Cash received from oil and gas sales     $    223,677   355,046  429,745
 Cash paid to Managing General Partner
  for administrative fees and general
                                            and   administrative   overhead
(133,373)                                 (161,103)(170,624)
 Interest received                                 609     1,436      995
                                                                    -------
-------                                   -------
   Net  cash provided by operating activities               90,913  195,379
260,116
                                                                    -------
-------                                   -------
Cash flows from investing activities:

 Sale of oil and gas properties                    930       180        -
                                                                    -------
-------                                   -------
Cash flows used in financing activities:

 Distributions to partners                    (92,218) (205,402)(250,000)
                                                                    -------
-------                                   -------
Net increase (decrease) in cash and cash
 equivalents                                     (375)   (9,843)   10,116

 Beginning of period                             7,887    17,730    7,614
                                                                    -------
-------                                   -------
 End of period                            $      7,512     7,887   17,730
                                                                    =======
=======                                   =======


(continued)

























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

<PAGE>
             Southwest Developmental Drilling Fund 92-A, L.P.
                     (a Delaware limited partnership)
                   Statements of Cash Flows, continued
               Years ended December 31, 1998, 1997 and 1996


                                                  1998     1997      1996
                                                  ----     ----      ----

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

Net income (loss)                         $  (331,847)    93,437  178,706

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

   Depreciation, depletion and amortization                80,000    84,756
77,736
  Provision for impairment of oil and gas
                                           properties     314,240         -
-
  Decrease in receivables                       22,916    20,691    5,069
  Increase (decrease) in payables                5,604   (3,505)  (1,395)
                                                                    -------
-------                                   -------
Net cash provided by operating activities $     90,913   195,379  260,116
                                                                    =======
=======                                   =======




































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

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

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

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

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

                      Notes to Financial Statements


2.   Summary of Significant Accounting Policies

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

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

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

     Should the net capitalized costs exceed the estimated present value of
     oil  and  gas reserves, discounted at 10%, such excess costs would  be
     charged  to  current  expense.   As of  December  31,  1998,  the  net
     capitalized cost exceeded the estimated present value of oil  and  gas
     reserves,  thus  an adjustment of $314,240 was made to  the  financial
     statement.   As  of  December 31, 1997 and 1996, the  net  capitalized
     costs  did  not  exceed the estimated present value  of  oil  and  gas
     reserves.

     Estimates and Uncertainties
     The  preparation of financial statements in conformity with  generally
     accepted  accounting principles requires management to make  estimates
     and  assumptions  that  affect  the reported  amounts  of  assets  and
     liabilities and disclosure of contingent assets and liabilities at the
     date  of the financial statements and the reported amounts of revenues
     and expenses during the reporting period.  Actual results could differ
     from those estimates.

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

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

                      Notes to Financial Statements


2.   Summary of Significant Accounting Policies - continued

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

     Gas Balancing
     The  Partnership utilizes the sales method of accounting for  over  or
     under  deliveries of gas.  Under this method, the Partnership  records
     revenues  based  on  the  payments it  has  received  for  sales  from
     purchasers.   As of December 31, 1998, 1997 and 1996, 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 assets at December 31, 1998  and  1997
     was  $172,613 and $531,228, 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, 1998, 1997 and 1996, there were  1,407  investor
     units outstanding held by 104 partners.

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

                      Notes to Financial Statements


2.   Summary of Significant Accounting Policies - continued

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

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

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

3.   Liquidity - Managing General Partner
     The  Managing General Partner has a highly leveraged capital structure
     with  over $21.0 million of interest payments due in 1999 on its  debt
     obligations.  Due to severely depressed commodity prices, the Managing
     General  Partner  is experiencing difficulty in generating  sufficient
     cash  flow  to  meet its obligations and sustain its operations.   The
     Managing  General Partner is currently in the process of renegotiating
     the  terms  of  its  various  obligations with  its  creditors  and/or
     attempting to seek new lenders or equity investors.  Additionally, the
     Managing General Partner would consider disposing of certain assets in
     order to meet its obligations.
     
     There  can  be  no assurance that the Managing General Partner's  debt
     restructuring  efforts  will be successful or that  the  lenders  will
     agree  to  a  course  of action consistent with the  Managing  General
     Partners requirements in restructuring the obligations.  Even if  such
     agreement  is reached, it may require approval of additional  lenders,
     which is not assured.  Furthermore, there can be no assurance that the
     sales  of  assets can be successfully accomplished on terms acceptable
     to  the  Managing  General Partner.  Under current circumstances,  the
     Managing  General  Partner's ability to continue as  a  going  concern
     depends   upon  its  ability  to  (1)  successfully  restructure   its
     obligations  or  obtain additional financing as may be  required,  (2)
     maintain  compliance with all debt covenants, (3) generate  sufficient
     cash  flow to meet its obligations on a timely basis, and (4)  achieve
     satisfactory  levels  of  future earnings.  If  the  Managing  General
     Partner  is unsuccessful in its efforts, it may be unable to meet  its
     obligations making it necessary to undertake such other actions as may
     be appropriate to preserve asset values.

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

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

                      Notes to Financial Statements


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

     As  of December 31, 1998, the Partnership has not been fined, cited or
     notified  of any environmental violations and management is not  aware
     of  any  unasserted  violations which would have  a  material  adverse
     effect upon capital expenditures, earnings or the competitive position
     in the oil and gas industry.

     However,  the  Managing  General Partner does recognize  by  the  very
     nature  of its business, material costs could be incurred in the  near
     term  to  bring the Partnership into total compliance.  The amount  of
     such  future expenditures is not reliably determinable due to  several
     factors,  including the unknown magnitude of possible  contaminations,
     the  unknown timing and extent of the corrective actions which may  be
     required,   the  determination  of  the  Partnership's  liability   in
     proportion  to other responsible parties and the extent to which  such
     expenditures  are recoverable from insurance or indemnifications  from
     prior owners of Partnership's properties.

5.   Related Party Transactions
     A  significant  portion  of the oil and gas properties  in  which  the
     Partnership  has  an interest are operated by and purchased  from  the
     Managing General Partner.  As is usual in the industry and as provided
     for  in  the  operating  agreement for each  respective  oil  and  gas
     property  in  which the Partnership has an interest, the  operator  is
     paid  an  amount for administrative overhead attributable to operating
     such  properties,  with such amounts to Southwest Royalties,  Inc.  as
     operator  approximating $20,900, $19,000 and  $19,000  for  the  years
     ended  December 31, 1998, 1997 and 1996, respectively.   In  addition,
     the  Managing  General Partner and certain officers and employees  may
     have  an interest in some of the properties that the Partnership  also
     participates.

     Certain  subsidiaries  or affiliates of the Managing  General  Partner
     perform  various  oilfield  services  for  properties  in  which   the
     Partnership  owns an interest.  Such services aggregated approximately
     $100, $1,400 and $400 for the years ended December 31, 1998, 1997  and
     1996,  respectively,  and the Managing General Partner  believes  that
     these  costs are comparable to similar charges paid by the Partnership
     to unrelated third parties.

     Southwest Royalties, Inc., the Managing General Partner, was  paid  an
     administrative  fee  of  $12,000  during  1998,  1997  and  1996   for
     reimbursement   of   indirect  general  and  administrative   overhead
     expenses.


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

                      Notes to Financial Statements


5.   Related Party Transactions - continued
     In addition, a director and officer of the Managing General Partner is
     a  partner  in a law firm, with such firm providing legal services  to
     the  Partnership.  There were no legal services for December 31,  1998
     and  1997.   As of December 31, 1996 there were approximately  $50  in
     legal services.

     Receivables  from  Southwest  Royalties, Inc.,  the  Managing  General
     Partner,  of  approximately $7,814 and $36,334 are from  oil  and  gas
     production, net of lease operating costs and production taxes,  as  of
     December 31, 1998 and 1997, respectively.

6.   Major Customers
     No  material portion of the Partnership's business is dependent  on  a
     single purchaser, or a very few purchaser, where the loss of one would
     have  a  material adverse impact on the Partnership.  Three purchasers
     accounted  for  95% of the Partnership's total oil and gas  production
     during  1998:  Scurlock  Permian  Corporation  for  59%,  Duke  Energy
     Transport and Trad. for 20% and Navajo Refining Company, Inc. for 16%.
     Three purchasers accounted for 94% of the Partnership's total oil  and
     gas  production during 1997: Scurlock Permian Corporation  60%, Aquila
     Southwest Pipeline Corporation  19% and Navajo Refining Company,  Inc.
     15%.   Three  purchasers accounted for 96% of the partnership's  total
     oil and gas production during 1996:  Scurlock Permian Corporation 60%,
     Aquila  Southwest Pipeline Corporation 19% and Navajo Refining Company
     Inc.  17%.  All purchasers of the Partnership's oil and gas production
     are  unrelated  third parties.  In the event this  purchaser  were  to
     discontinue  purchasing  the Partnership's  production,  the  Managing
     General  Partner  believes that a substitute purchaser  or  purchasers
     could  be  located without undue delay.  No other purchaser  accounted
     for  an amount equal to or greater than 10% of the Partnership's total
     oil and gas production.

7.   Estimated Oil and Gas Reserves (unaudited)

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

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

     January 1, 1996                                 151,000     317,000

       Production                                   (16,000)    (34,000)
       Revisions of estimates in place                29,000      53,000
                                                     -------     -------
     December 31, 1996                               164,000     336,000

       Production                                   (13,000)    (30,000)
       Revisions of estimates in place              (33,000)    (18,000)
                                                     -------     -------
     December 31, 1997                               118,000     288,000

       Production                                   (12,000)    (27,000)
       Revisions of estimates in place              (30,000)    (93,000)
                                                     -------     -------
     December 31, 1998                                76,000     168,000
                                                     =======     =======


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

                      Notes to Financial Statements


7.   Estimated Oil and Gas Reserves (unaudited) - continued

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

     December 31, 1996                               163,000     335,000
                                                     =======     =======
     December 31, 1997                               117,000     288,000
                                                     =======     =======
     December 31, 1998                                76,000     168,000
                                                     =======     =======

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

     *Ryder  Scott  Company Petroleum Engineers prepared  the  reserve  and
     present  value data for 96.4% of the Partnership's existing properties
     as  of  January  1,  1999.   Another  independent  petroleum  engineer
     prepared  the  remaining  3.6% of the Partnership's  properties.   The
     reserve  estimates were made in accordance with guidelines established
     by  the Securities and Exchange Commission pursuant to Rule 4-10(a) of
     Regulation  S-X.  Such guidelines require oil and gas reserve  reports
     be  prepared under existing economic and operating conditions with  no
     provisions  for  price  and  cost  escalation  except  by  contractual
     arrangements.

     The  New York Mercantile Exchange price at December 31, 1998 of $12.50
     was  used  as  the  beginning basis for  the  oil  price.   Oil  price
     adjustments  from  $12.50  per  barrel were  made  in  the  individual
     evaluations  to  reflect  oil  quality, gathering  and  transportation
     costs.   The  results are an average price received at  the  lease  of
     $10.83  per  barrel  in the preparation of the reserve  report  as  of
     January 1, 1999.

     In  the  determination  of  the gas price,  the  New  York  Mercantile
     Exchange price at December 31, 1998 of $1.95 was used as the beginning
     basis.   Gas  price adjustments from $1.95 per Mcf were  made  in  the
     individual   evaluations  to  reflect  BTU  content,   gathering   and
     transportation  costs and gas processing and shrinkage.   The  results
     are  an  average price received at the lease of $1.99 per Mcf  in  the
     preparation of the reserve report as of January 1, 1999.


<PAGE>

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

                      Notes to Financial Statements


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

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

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

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

                      Notes to Financial Statements


7.   Estimated Oil & Gas Reserves (unaudited) - continued
     The  standardized measure of discounted future net cash flows relating
     to  proved oil and gas reserves at December 31, 1998, 1997 and 1996 is
     presented below:

                                              1998       1997        1996
                                              ----       ----        ----

     Future cash inflows                $  1,160,000  2,801,000  5,563,000
     Production and development costs        819,000  1,637,000  2,738,000
                                           ---------  ---------  ---------
     Future net cash flows                   341,000  1,164,000  2,825,000
     10% annual discount for estimated
       timing of cash flows                   98,000    430,000  1,186,000
                                           ---------  ---------  ---------
     Standardized measure of discounted
       future net cash flows            $    243,000    734,000  1,639,000
                                           =========  =========  =========

     The  principal  sources  of  change in  the  standardized  measure  of
     discounted  future  net cash flows for the years  ended  December  31,
     1998, 1997 and 1996 are as follows:

                                               1998       1997        1996
                                               ----       ----        ----

     Sales of oil and gas produced,
       net of production costs          $   (86,000)  (195,000)  (364,000)
      Changes in prices and production costs           (410,000)  (754,000)
692,000
     Changes of production rates
       (timing) and others                    38,000     41,000     74,000
     Revisions of previous
       quantities estimates                (106,000)  (161,000)     44,000
     Accretion of discount                    73,000    164,000    139,000
     Discounted future net
       cash flows -
      Beginning of year                      734,000  1,639,000  1,054,000
                                           ---------   --------   --------
      End of year                       $    243,000    734,000  1,639,000
                                           =========   ========   ========

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

<PAGE>

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

      On  June 9, 1997 Southwest Royalties, Inc. the Partnership's Managing
General  Partner (Southwest Royalties, Inc.) dismissed Joseph Decosimo  and
Company as the Partnership's independent accountants.  The Managing General
Partner's   Board  of  Directors  approved  the  decision  to  change   the
Partnership's independent accountants.

The  report of Joseph Decosimo and Company on the financial statements  for
the  fiscal  year ended December 31, 1996 contained no adverse  opinion  or
disclaimer  of opinion and was not qualified or modified as to uncertainty,
audit scope or accounting principle.

In  connection with its audit for the fiscal year ended December  31,  1996
and  through  June  9, 1997, there have been no disagreements  with  Joseph
Decosimo  and Company on any matter of accounting principles or  practices,
financial  statements  disclosure, or auditing scope  or  procedure,  which
disagreements  if not resolved to the satisfaction of Joseph  Decosimo  and
Company would have caused them to make reference thereto in their report on
the financial statements for such year.

The  Registrant has requested that Joseph Decosimo and Company  furnish  it
with  a  letter addressed to the SEC stating whether or not is agrees  with
the  above statements.  A copy of that letter is included as Exhibit 16 and
has been filed with the Securities and Exchange Commission.




<PAGE>
                                 Part III

Item 10.  Directors and Executive Officers of the Registrant

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

     Name                   Age                      Position
--------------------        ---         -----------------------------------
-------
H. H. Wommack, III                      43     Chairman   of   the   Board,
                                        President,
                                        Chief Executive Officer, Treasurer
                                        and Director

H. Allen Corey              42          Secretary and Director

Bill E. Coggin                          44     Vice  President  and   Chief
                                        Financial Officer

Jon P. Tate                             41     Vice  President,  Land   and
                                        Assistant Secretary

R. Douglas Keathley         43          Vice President, Operations

J. Steven Person            40          Vice President, Marketing

Paul L. Morris              57          Director

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

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

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

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

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

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

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


<PAGE>
Key Employees

Accounting  and Administrative Officer - Debbie A. Brock, age  46,  assumed
her  position with the Managing General Partner in 1991.  Prior to  joining
the Managing General Partner, Ms. Brock was employed with Western Container
Corporation   as  Accounting  Manager  (1982-1990),  Synthetic   Industries
(Texas), Inc. as Accounting Manager (1976-1982) and held various accounting
positions in the manufacturing industry (1971-1975).  Ms. Brock received  a
B.B.A. from the University of Houston.

Controller - Robert A. Langford, age 49, assumed his responsibilities  with
the  Managing  General Partner in 1992.  Mr. Langford received  his  B.B.A.
degree  in  Accounting  in 1975 from the University  of  Central  Arkansas.
Prior  to  joining the Managing General Partner,  Mr. Langford was employed
with Forest Oil Corporation as Corporate Coordinator, Regional Coordinator,
Accounting  Manager.  He held various other positions  from  1982-1992  and
1976-1980  and was Assistant Controller of National Oil Company from  1980-
1982.

Financial  Reporting  Manager - Bryan Dixon, C.P.A., age  32,  assumed  his
responsibilities  with the Managing General Partner  in  1992.   Mr.  Dixon
received his B.B.A. degree in Accounting in 1988 from Texas Tech University
in  Lubbock,  Texas.   Prior to joining the Managing General  Partner,  Mr.
Dixon was employed as a Senior Auditor with Johnson, Miller & Company  from
1991-1992 and Audit Supervisor for Texas Tech University and the Texas Tech
University Health Sciences Center from 1988-1991.

Production   Superintendent  -  Steve  C.  Garner,  age  57,  assumed   his
responsibilities   with   the  Managing  General  Partner   as   Production
Superintendent  in  July,  1989.  Prior to  joining  the  Managing  General
Partner,  Mr. Garner was employed 16 years by Shell Oil Company working  in
all  phases of oil field production as operations foreman, one and one-half
years  with Petroleum Corporation of Delaware as Production Superintendent,
six  years  as  an independent engineering consultant, and  one  year  with
Citation  Oil & Gas Corp. as a workover, completion and production foreman.
Mr.  Garner has worked extensively in the Permian Basin oil field  for  the
last 25 years.

Tax  Manager  -  Carolyn  Cookson, age 42, assumed her  position  with  the
Managing  General  Partner in April, 1989.  Prior to joining  the  Managing
General  Partner,  Ms. Cookson was employed as Director of  Taxes  at  C.F.
Lawrence  &  Associates,  Inc. from 1983 to  1989,  and  worked  in  public
accounting  at McCleskey, Cook & Green, P.C. from 1981 to 1983  and  Deanna
Brady,  C.P.A.  from 1980 to 1981.  She is a member of  the  Permian  Basin
Chapter  of the Petroleum Accountants' Society, and serves on its Board  of
Directors  and  is  liaison to the Tax Committee.  Ms. Cookson  received  a
B.B.A. in accounting from New Mexico State University.

<PAGE>
Investor  Relations Manager - Sandra K. Flournoy, age 52, came to Southwest
Royalties,  Inc.  in 1988 from Parker & Parsley Petroleum,  where  she  was
Assistant Manager of Investor Services and Broker/Dealer Relations for  two
years.   Prior  to that, Ms. Flournoy was Administrative Assistant  to  the
Superintendent at Greenwood ISD for four years.

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

Item 11.  Executive Compensation

The  Partnership  does not have any directors or executive  officers.   The
executive officers of the Managing General Partner do not receive any  cash
compensation,  bonuses, deferred compensation or compensation  pursuant  to
any  type  of  plan,  from the Partnership.  The Managing  General  Partner
received  $12,000 during 1998, 1997 and 1996 as an administrative  fee  for
reimbursement of indirect general and administrative expenses.

Item 12.  Security Ownership of Certain Beneficial Owners and Management

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

The  Managing General Partner owns an eleven percent interest as a  general
partner.

No  officer or director of the Managing General Partner owns Units  in  the
Partnership.   There  are  no arrangements known to  the  Managing  General
Partner which may at a subsequent date result in a change of control of the
Partnership.

Item 13.  Certain Relationships and Related Transactions

In 1998, 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 $20,900 for administrative  overhead
attributable to operating such properties during 1998.

Certain  subsidiaries or affiliates of the Managing General Partner perform
various  oilfield services for properties in which the Partnership owns  an
interest.  Such services aggregated approximately $100 for the period ended
December 31, 1998.

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

<PAGE>
                                 Part IV


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

          (a)(1)  Financial Statements:

                  Included in Part II of this report --

                  Reports of Independent Accountants
                  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).

<PAGE>
Item 14.  Exhibits, Financial Statement Schedules and Reports on Form 8-K -
          continued

                                       Exhibit  4(e):  Second  Amended  and
                                 Restated     Certificate    of     Limited
                                 Partnership   of  Southwest  Developmental
                                 Drilling  Fund  92-A. L.P.,  dated  as  of
                                 January   12,   1994.   (Incorporated   by
                                 reference from Partnership's Form 10-K for
                                 the fiscal year ended December 31, 1993).

                  27 Financial Data Schedule

                  Reports on Form 8-K

                  (b)            No report on Form 8-K was filed during the
                  quarter ended December 31, 1998.

<PAGE>
                                Signatures


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


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


                                        By:    Southwest  Royalties,  Inc.,
                                 Managing
                                 General Partner


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


                          Date:    March 31, 1999


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


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


Date:     March 31, 1999


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


Date:     March 31, 1999

<PAGE>