FORM 10-K/A
                              AMENDMENT
                    NO.1
                    SECURITIES
                    AND
                    EXCHANGE
                    COMMISSION
                         WASHI
                         NGTON
                         ,
                         D.C.
                         20549
(Mark One)

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

For the fiscal year ended December 31, 2002

                        OR

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

For the transition period from
to
Commission File Number   0-18996
                Southwest Oil & Gas Income Fund X-
           A, L.P. (Exact name of registrant as
           specified in
        its limited partnership agreement)

Delaware
75-
2310854
(State or other jurisdiction
(I.R.S. Employer
of incorporation or organization)
Identification No.)

407 N. Big Spring, Suite 300, Midland, Texas

79701 (Address of principal executive office)

(Zip Code) Registrant's telephone number, including

area code (432) 686-9927

       Securities registered pursuant to Section

       12(b) of the Act:

                                   None

  Securities registered pursuant to Section 12(g)

                      of the Act: limited

partnership

                      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       No X




Indicate by check mark if disclosure of delinquent
filers pursuant to  Item 405  of  Regulation S-K is
not contained herein, and will not be contained, to
the  best of
registrant's knowledge, in definitive proxy or
information statements incorporated by reference
in Part III of this Form 10-K  or  any amendment
to this Form 10-K.          [x]
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  50. The  exhibit index is found on page
47.
<PAGE>
                 Table of Contents

Item

Page

                      Part I

     Glossary of Oil and Gas Terms                                       3

 1.  Business                                                            5

 2.  Properties                                                         10

3.   Legal Proceedings                                                  11
4.
 4.  Submission of Matters to a Vote of Security Holders                11

                            Part II
 5.  Market for Registrant's Common Equity and Related
     Stockholder Matters                                                12
 6.  Selected Financial Data                                            13
 7.  Management's Discussion and Analysis of
     Financial Condition and Results of Operations                      14
 8.  Financial Statements and Supplementary Data                        22
 9.  Changes in and Disagreements with Accountants
     on Accounting and Financial Disclosure                             37

                           Part III

10.  Directors and Executive Officers of the Registrant                 38

11.  Executive Compensation                                             40

12.  Security Ownership of Certain Beneficial Owners and
     Management                                                         40

13.  Certain Relationships and Related Transactions                     41

14.  Controls and Procedures                                            41

                            Part IV

15.  Exhibits, Financial Statement Schedules, and Reports
     on Form 8-K                                                        42

     Signatures                                                         43

<PAGE>
Glossary of Oil and Gas Terms
The  following are abbreviations and definitions of terms
commonly used  in the  oil  and  gas industry that
are used in this filing.  All  volumes  of natural
gas referred to herein are stated at the legal
pressure base to the state  or area where the
reserves exit and at 60 degrees Fahrenheit and  in
most instances are rounded to the nearest major
multiple.
  Bbl. One stock tank barrel, or 42 United States
                      gallons
liquid volume.

     Developmental well. A well drilled within the
proved area of an oil or natural gas reservoir to
the depth of a stratigraphic horizon known  to  be
productive.
     Exploratory well. A well drilled to find and
produce oil or gas in  an unproved  area to find a
new reservoir in a field previously  found  to  be
productive of oil or natural gas in another
reservoir or to extend a  known
reservoir.
     Farm-out arrangement. An agreement whereby the
owner of a leasehold or working  interest agrees to
assign his interest in certain specific acreage to
an  assignee,  retaining some interest, such as an
overriding  royalty interest,  subject
to  the drilling of one (1)  or  more  wells  or
other specified performance by the assignee.
     Field. An area consisting of a single
reservoir or multiple reservoirs all  grouped  on
or  related to the same individual geological
structural feature and/or stratigraphic condition.
     Mcf. One thousand cubic feet.
     Oil. Crude oil, condensate and natural gas
     liquids. Overriding  royalty  interest.
     Interests that  are  carved
out  of  a working  interest, and their duration is
limited by the term of  the  lease under which they
are created.
     Present  value  and  PV-10 Value. When used
with respect to  oil  and natural gas reserves, the
estimated future net revenue to be generated from
the  production of proved reserves, determined in
all material respects  in accordance with  the
rules and regulations of the  SEC  (generally
using prices  and costs in effect as of the date
indicated) without giving effect to  non-property
related  expenses  such  as general  and
administrative expenses,  debt service and future
income tax expenses or to  depreciation, depletion
and amortization, discounted using an annual
discount  rate  of 10%.
<PAGE>
     Production  costs.  Costs incurred to operate
and maintain wells  and related  equipment  and
facilities, including depreciation  and  applicable
operating  costs  of support equipment and
facilities and  other  costs  of operating and
maintaining those wells and related equipment and
facilities.
     Proved Area. The part of a property to which
     proved
reserves have been specifically attributed.
     Proved  developed oil and gas reserves.
Reserves that can be  expected to  be  recovered
from existing wells with existing equipment and
operating methods.
Proved properties. Properties with proved reserves.
     Proved  oil  and gas reserves. The estimated
quantities of crude  oil, natural  gas, and natural
gas liquids with geological and engineering  data
that  demonstrate  with reasonable certainty to be
recoverable  in  future years   from known
reservoirs  under  existing  economic  and
operating conditions, i.e., prices and costs as of
the date the estimate is made.
     Proved  undeveloped  reserves.  Reserves  that
are expected  to   be recovered from new wells on
undrilled acreage, or from existing wells where a
relatively major
expenditure is required for recompletion.
     Reservoir.  A porous and permeable
underground formation containing  a natural
accumulation  of  producible  oil  or gas  that
is  confined  by impermeable  rock  or water
barriers and is individual  and  separate  from
other reservoirs.
     Royalty  interest.  An  interest in an oil
and  natural gas  property entitling  the  owner
to a share of oil or natural gas production  free
of costs of production.
Working  interest.  The operating interest that gives  the
owner  the
right  to  drill, produce and conduct operating activities
on
the  property and a share of production.
 Workover.  Operations  on  a producing well  to  restore
or  increase production.
<PAGE>
                            Part I
Item 1.   Business

General
Southwest   Oil  &  Gas  Income  Fund  X-A,  L.P.  (the
"Partnership"
or
"Registrant")  was organized as a Delaware limited
partnership
on  January 29, 1990.  The offering of limited partnership
interests began May 11, 1990 as  part of a shelf offering
registered under the name Southwest Oil &  Gas 1990-91  Income
Program (the "Program").  Minimum capital requirements  for the
Partnership were met on August 15, 1990, with the offering of
limited partnership interests concluding on November 30, 1990.
The Partnership has no subsidiaries.

The Partnership has acquired interests in producing oil and gas
properties, and  produced and marketed the crude oil and
natural gas produced from such properties.  In most cases, the
Partnership purchased working interests  in oil  and  gas
properties.  The Partnership purchased either all or part  of
the rights and obligations under various oil and gas leases.

The  principal executive offices of the Partnership are located
at  407  N. Big Spring, Suite 300, Midland, Texas, 79701.  The
Managing General Partner of  the  Partnership,  Southwest
Royalties,  Inc.  (the  "Managing  General Partner")   and  its
staff  of  82  individuals,  together  with
certain independent  consultants  used  on an "as needed"
basis,
perform  various services on behalf of the
Partnership, including the selection of  oil  and
gas properties and the marketing of production from
such properties.  H. H. Wommack, III, Chairman,
Director, President and Chief Executive Officer of
the  Managing General Partner, is also a general
partner. The  Partnership has no employees.

Introductory Note
During  2002, the Partnership changed its method of
providing
for depletion from  the  units-of-revenue  method to
the  unitsof-production  method  as described in
Note 3 to the Partnership's financial statements.

Subsequent to the issuance of the Annual Report on
Form 10-K
for  the  year ended  December 31, 2002, the
Partnership determined that the above  change in
accounting  method should have been adopted by the
Partnership  as  a cumulative
effect of a change in accounting principle.   As
described  in Note  9  to  the  Partnership's
financial statements, the Partnership  had
previously  applied  the  change in the method
of providing  for  depletion prospectively as of
October 1, 2002.
Principal Products, Marketing and Distribution
The  Partnership has acquired and holds working
interests in oil  and  gas properties  located  in
New  Mexico and  Texas. All  activities  of  the
Partnership are confined to the continental United
States.  All oil and gas produced  from these
properties is sold to unrelated third parties  in
the oil and gas business.

The  revenues  generated from the Partnership's oil
and gas activities  are dependent upon the current
market for oil and gas.  The prices received  by
the Partnership for its oil and gas production
depend upon numerous factors beyond   the
Partnership's  control,  including  competition,
economic, political  and regulatory developments
and competitive energy sources,  and make it
particularly difficult to estimate future prices of
oil and natural
gas.
<PAGE>
In  2002, fighting and threats of fighting in the
Middle East and a  strike in  a  major  oil
exporting country dominated the direction  of
crude  oil prices.  While OPEC agreed to keep
production constant throughout the year, conflicts
between
the U.S. and Iraq, as well as between  Israel  and
the Palestinians  threatened supplies and caused
oil prices to surge  in  2002. In  addition,  a
strike by oil workers in Venezuela,  the  fourth
largest supplier to the U.S., took a significant
amount of crude oil off the market toward  the end
of the year.  As a result, OPEC agreed in January
2003  to increase output by 1.5 million barrels per
day in an effort to make up  for the lost supply
and stabilize prices.

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

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

         Oil       Gas
2002     87%       13%
2001     85%       15%
2000     85%       15%

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

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

Customer Dependence
No  material portion of the Partnership's business
is dependent on a single purchaser,  or a very few
purchasers, where the loss of one  would  have  a
material  adverse impact on the Partnership. Two
purchasers  accounted  for 75%  of the
Partnership's total oil and gas production during
2002:  Plains Marketing  LP for 50% and Navajo
Refining Company Inc. for 25%. Contracts for  2002
with these major purchasers are month-tomonth
contracts.  Prices received from these major
purchasers ranged from a low of $21.52 per Bbl to a
high  of  $21.95 per Bbl.  Three purchasers
accounted  for  84%  of  the Partnership's  total
oil and gas production during 2001:
Plains  Marketing LP for 52%, Navajo Refining
Company for 22%, Duke Energy Field Services for
10%.  Contracts  for  2001 with these major
purchasers cover  time  periods ranging  from month
to-month contracts up to year-to-year contract
periods. Prices received from these major
purchasers ranged from a low of
$24.16 per Bbl  to  a  high  of  $24.58 per Bbl and
$4.46 per mcf.   Four  purchasers accounted for 85%
of the Partnership's total oil and gas production
during 2000:   Plains Marketing LP for 27%,
Eaglewing Trading Inc. for 23%, Navajo Refining
Company for 22% and Phillips 66 for 13%.  Contracts
for 2000 with
these  major  purchasers  cover time periods
ranging  from month-to-month contracts up to year-
to-year contract periods. Prices received from
these major  purchasers ranged from a low of $26.68
per Bbl to a high  of  $26.91 per  Bbl.
All purchasers of the Partnership's oil and gas
production  are unrelated  third  parties.  In the
event any of these purchasers  were  to discontinue
purchasing the Partnership's production, the
Managing  General Partner believes that a
substitute purchaser or purchasers could be located
without delay.   No other purchaser accounted for
an amount  equal  to or greater than 10% of the
Partnership's sales of oil and gas production.


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

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

Regulation

Oil  and Gas Production - The production and sale
of oil and gas is subject to  federal and state
governmental regulation in several respects, such
as existing price controls on natural gas and
possible price controls on crude oil,  regulation
of
oil and gas production by state and local
governmental agencies, pollution and environmental
controls and various other direct and indirect
regulation.    Many  jurisdictions  have
periodically
imposed
limitations on oil and gas production by
restricting the rate of  flow  for oil  and  gas
wells below their actual capacity to produce and by
imposing acreage limitations for the drilling of
wells.  The federal government  has the  power  to
permit increases in the amount of oil imported
from  other countries and to impose pollution
control measures.  Various aspects of the
Partnership's  oil  and  gas  activities are
regulated  by  administrative agencies under
statutory provisions of the states where such
activities are conducted and by certain agencies of
the federal government for operations on  Federal
leases.     The regulatory burden on the
oil  and  gas  industry increases  the
Partnership's  cost of doing business,  and,
consequently, affects its profitability.

Regulation  of  Sales  and Transportation of
Natural  Gas.
Our  sales  of
natural   gas  are  affected  by  the
availability,  terms
and  cost   of
transportation.  The price and terms for access to
pipeline transportation are  subject  to  extensive
regulation. In recent  years,  the  FERC  has
undertaken  various initiatives to increase
competition within the  natural gas industry. As a
result of initiatives like FERC Order No. 636,
issued in April 1992, the interstate natural gas
transportation and marketing system has   been
substantially  restructured  to  remove various
barriers  and practices  that  historically
limited non-pipeline  natural  gas  sellers,
including  producers, from effectively competing
with interstate  pipelines for  sales  to local
distribution  companies  and  large  industrial
and commercial  customers. The most significant
provisions  of Order  No.  636 require   that
interstate  pipelines  provide firm       and
interruptible
transportation  service  on an open access basis
that  is equal  for  all natural  gas supplies. In
many instances, the results of Order No. 636  and
related  initiatives  have been to substantially
reduce  or  eliminate  the interstate pipelines'
traditional role as wholesalers of  natural  gas
in favor  of  providing  only storage and
transportation services. While  the United  States
Court  of  Appeals upheld most of Order  No.  636,
certain
related  FERC  orders,  including  the  individual
pipeline restructuring proceedings,  are still
subject to judicial review and may be  reversed  or
remanded in whole or in part. While the outcome of
these proceedings cannot be  predicted with
certainty, we do not believe that we will  be
affected materially differently than its
competitors.
The FERC has also announced several important
transportationrelated policy statements and
proposed rule changes, including a statement of
policy and a request  for  comments concerning
alternatives to its traditional  cost-ofservice
rate making methodology to establish the rates
interstate pipelines may charge  for their
services. A number of pipelines have
obtained  FERC authorization  to  charge
negotiated rates as one  such  alternative.  In
February  1997, the FERC announced a broad inquiry
into issues  facing  the natural  gas  industry to
assist the FERC in establishing regulatory  goals
and priorities in the post-Order No. 636
environment. Similarly, the Texas Railroad
Commission has been reviewing changes to its
regulations governing transportation and gathering
services provided by intrastate pipelines  and
gatherers.  While the
changes being considered by these federal  and
state regulators  would affect us only indirectly,
they are intended to  further enhance  competition
in natural gas markets. We cannot predict what
further action the FERC or state regulators will
take on these matters, however, we do  not  believe
that it will be affected by any action  taken
materially differently than other natural gas
producers with which it competes.
Additional  proposals  and proceedings that might
affect  the natural  gas industry are pending
before Congress, the FERC, state commissions  and
the courts.  The  natural  gas
industry historically  has  been  very  heavily
regulated; therefore,  there  is  no assurance
that  the  less  stringent regulatory  approach
recently  pursued  by  the  FERC  and Congress
will continue.
<PAGE>
Oil Price Controls and Transportation Rates. Sales
of crude oil, condensate and  gas  liquids by us
are not currently regulated and are made at  market
prices.  The  price  we receive from the sale of
these  products  may  be affected by the cost of
transporting the products to market.

Environmental  and  Health Controls.  Extensive
federal,  state and  local regulatory and common
laws regulating the discharge of materials  into
the environment  or  otherwise relating to the
protection  of  the  environment affect
our oil  and  natural  gas  operations.  Numerous
governmental
departments issue rules and regulations to
implement and enforce such laws, which  are  often
difficult  and costly to comply  with  and  which
carry substantial  civil and even criminal
penalties for failure to comply.  Some laws, rules
and regulations relating to protection of the
environment  may, in certain  circumstances,
impose  strict  liability  for environmental
contamination,  rendering  a person liable for
environmental  damages  and cleanup  costs without
regard to negligence or fault on the  part  of
such person. Other laws, rules and regulations may
restrict the rate of oil  and natural gas
production below the rate that would otherwise
exist  or even prohibit  exploration  and
production activities  in sensitive  areas.  In
addition,  state  laws often require various forms
of  remedial  action  to prevent  pollution,
such  as  closure of inactive  pits  and  plugging
of abandoned wells. The regulatory burden on the
oil and natural gas  industry increases  our  cost
of  doing  business  and consequently  affects
our
profitability.  We  believe  that  we are in
substantial compliance  with current  applicable
environmental laws and regulations and  that
continued compliance  with  existing requirements
will not have  a  material  adverse impact on our
operations. However, environmental laws and
regulations  have been subject to frequent changes
over the years, and the imposition of more
stringent  requirements  could  have a material
adverse  effect  upon  our capital  expenditures,
earnings  or competitive  position.   Additionally,
given  the intense litigation environment in the
United States,  a  threat exists  of  lawsuits
alleging personal injury  and  property damage
from environmental  contamination  alleged  to  be
created  by  us  or  related entities.
Potential  liability  in such lawsuits  can
include  not  only compensatory, but substantial
punitive damages as well.  We are not  aware of any
such suits currently pending or threatened. The
Comprehensive Environmental Response, Compensation
and Liability  Act ("CERCLA"),  also known as the
"Superfund" law, imposes liability,  without regard
to  fault on certain
classes of persons that are considered  to  be responsible
for  the  release  of  a  "hazardous  substance"   into
the environment. These persons include the current or former
owner
or  operator of the disposal site or sites where
the release occurred and companies that disposed or
arranged for the disposal of hazardous substances.
Under CERCLA such persons may be subject to joint
and several liability for the costs of
investigating and cleaning up hazardous substances
that have been  released into the environment, for
damages to natural resources and for the costs of
certain  health  studies.  In addition,  companies
that  incur  liability frequently also confront
third party claims because it is not uncommon  for
neighboring landowners and other third parties to
file claims for  personal injury  and  property
damage allegedly caused by hazardous  substances
or other  pollutants  released  into the
environment  from  a  polluted  site. Potential
liability also exists under CERCLA for natural
resource  damage. A  Natural Resource Damage Action
(NRDA) could result in  liability  being assessed
for restoration to natural resources.

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

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

<PAGE>
The Federal Clean Water Act ("CWA") contains
provisions that may result  in the imposition of
certain water pollution control requirements with
respect to water releases from our operations.  We
may be required to incur certain capital
expenditures in the next several years for water
pollution control equipment  in connection with
obtaining and maintaining National  Pollutant
Discharge  Elimination Systems ("NPDES") permits.
However, we believe  our operations  will  not  be
materially  adversely  affected  by   any   such
requirements,  and  the  requirements are  not
expected  to
be  any  more burdensome to us than to other
similarly situated companies involved in oil and
natural  gas exploration and production activities
or  well  surfacing activities.
Our  operations are also subject to the federal
Clean Air Act ("CAA")  and comparable state and
local requirements. Amendments to the CAA were
adopted in 1990 and contain provisions that may
result in the gradual imposition of certain
pollution control requirements with respect to air
emissions from our operations. We may be required
to incur certain capital expenditures in the  next
several years for air pollution control equipment
in  connection with  obtaining  and maintaining
operating permits and  approvals  for  air
emissions.  However,  we  believe our operations
will  not  be materially adversely affected by any
such requirements, and the requirements  are  not
expected  to be any more burdensome to us than to
other similarly  situated companies  involved  in
oil  and natural gas  exploration  and  production
activities or well servicing activities.
We  maintain  insurance against "sudden and
accidental" occurrences,  which may  cover  some,
but not all, of the environmental risks described
above. Most  significantly,  the insurance we
maintain will not  cover  the  risks described
above which occur over a sustained period of time.
Further, there can  be  no assurance that such
insurance will continue to be available  to cover
all  such costs or that such insurance will be
available at  premium levels  that  justify its
purchase.  The occurrence of a significant  event
not
fully  insured  or indemnified against could have a  material adverse
effect on our financial condition and operations. Limited   partners
should  be  aware  that  the  assessment of  liability associated with
environmental liabilities is not always correlated  to  the value of a
particular project. Accordingly, liability associated with  the
environment under local, state, or federal regulations, particularly
clean ups under CERCLA, can exceed the value of our investment in the
associated site.
Regulation  of  Oil  and  Natural  Gas  Exploration  and Production.
Our
exploration  and  production operations are subject  to various  types
of regulation  at  the  federal,  state and local  levels.   Such
regulations include  requiring  permits and drilling bonds for the
drilling  of  wells, regulating the location of wells, the method of
drilling and casing  wells,
and  the  surface  use and restoration of properties upon which
wells  are drilled.                                              Many
states  also
have  statutes  or  regulations  addressing
conservation matters, including provisions for the utilization
or  pooling of  oil  and natural gas properties,
the establishment of maximum rates  of production
from oil and natural gas wells and the regulation
of  spacing, plugging and abandonment of such
wells.  Some state statutes limit the rate at which
oil and natural gas can be produced from our
properties.

Partnership Employees
The  Partnership has no employees; however the
Managing General
Partner has a  staff of geologists, engineers,
accountants, landmen and clerical  staff who
engage in Partnership activities and operations and
perform additional services  for the  Partnership
as needed.  In  addition  to  the  Managing General
Partner's  staff, the Partnership engages
independent consultants such  as petroleum
engineers and geologists as needed.  As of December
31, 2002,  there were 82 individuals directly
employed by the Managing  General Partner in
various capacities.
<PAGE>
Item 2.   Properties
In  determining whether an interest in a particular
producing property  was to  be  acquired, the
Managing General Partner considered such criteria
as estimated  oil  and  gas reserves, estimated
cash flow  from  the  sale  of production,  present
and  future prices of oil  and  gas,  the  extent
of undeveloped  and  unproved reserves, the
potential for secondary,  tertiary
and other enhanced recovery projects and the
availability of markets.
As  of December 31, 2002, the Partnership possessed
an interest in oil  and gas  properties  located in
Eddy and Lea Counties of  New  Mexico,  Duval,
Hockley,  Midland,  Pecos,  Runnels and  Ward
Counties  of  Texas.   These properties  consist
of various interests in approximately  160  wells
and units.
Due  to  the  Partnership's  objective of
maintaining  current operations without engaging in
the drilling of any developmental or exploratory
wells, or additional acquisitions of producing
properties, there have not been any significant
changes in properties during 2002, 2001 and 2000.
During  2002,  one lease was sold for approximately
$230.
There  were  no property sales during 2001 and
2000. Significant Properties
The  following  table  reflects the significant
properties  in which  the Partnership has an
interest:

                   Date
            Purchased    No. of  Proved Reserves**
Name      and  and Interest   Wells
Oil       Gas
Location
(bbls)    (mcf)
-------------  -------------  ------  ---
---
--  --------------------
--------  -----
Texas Crude      12/90* at
8 75,000  14,000
                   17.5%
Acquisition       to 50%
75,000(1  14,000(1
              working                )
) Gaines,        interest
Hockley,
Terry     and
Culberson
Counties,
Texas
Lea   County,
New
Mexico

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

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

Oil  price  adjustments were made in the individual
evaluations to  reflect oil quality, gathering and
transportation costs. The results of the reserve
report as of January 1, 2003 are an average price of
$28.31 per barrel.

Gas  price  adjustments were made in the individual
evaluations to  reflect BTU  content,  gathering and
transportation costs and  gas  processing  and
shrinkage. The results of the reserve report as of
January 1, 2003  are  an average price of $4.71 per
Mcf.

<PAGE>
As  also discussed in Part II, Item 7, Management's
Discussion and Analysis of  Financial Condition and
Results of Operations, oil and gas prices  were
subject to frequent changes in 2002.
The  evaluation  of  oil and gas properties is not
an  exact science  and inevitably involves a
significant degree of uncertainty, particularly
with respect to the quantity of oil or gas that any
given property is capable of producing. Estimates
of  oil and gas reserves  are  based  on  available
geological and engineering data, the extent and
quality of
which  may  vary in  each  case  and,  in  certain
instances, may prove  to  be  inaccurate.
Consequently,  properties may be depleted more
rapidly than the  geological and engineering data
have indicated.
Unanticipated  depletion, if it occurs, will result
in lower reserves  than previously  estimated; thus
an ultimately lower return for the Partnership.
Basic  changes in past reserve estimates occur
annually.  As  new  data  is gathered  during the
subsequent year, the engineer must revise his
earlier estimates.  A year of new information,
which is pertinent to the estimation of  future
recoverable volumes, is available during  the
subsequent  year evaluation.
In  applying industry standards and procedures, the
new data may cause  the previous  estimates to be
revised.  This revision may increase or  decrease
the  earlier estimated volumes.  Pertinent
information gathered during  the year  may include
actual production and decline  rates,  production
from offset wells drilled to the same geologic
formation, increased or decreased water
production, workovers, and changes in lifting
costs,  among  others. Accordingly,  reserve
estimates are often different from the quantities
of oil and gas that are ultimately recovered.
The  Partnership has reserves, which are classified
as proved developed and proved  undeveloped.   All
of  the proved reserves  are  included  in  the
engineering reports, which evaluate the
Partnership's present reserves.
Because  the  Partnership  does  not engage  in
drilling activities,  the development of proved
undeveloped reserves in conducted pursuant  to
farmout  arrangements  with  the Managing General
Partner  or  unrelated  third parties. Generally,
the Partnership retains a carried interest such as
an overriding royalty interest under the terms of a
farm-out. The  Partnership or the owners of
properties in which the Partnership  owns an
interest  can  engage  in workover projects or
supplementary  recovery projects, for example, to
extract behind the pipe reserves.  See  Part  II,
Item  7, Management's Discussion and Analysis of
Financial  Condition and Results of Operations.
Item 3.   Legal Proceedings
There are no material pending legal proceedings to
which the Partnership is a party.
Item 4.   Submission of Matters to a Vote of
Security Holders
No  matter  was submitted to a vote of security
holders during the  fourth quarter of 2002 through
the solicitation of proxies or otherwise.
<PAGE>
                      Part II


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

Market Information
Limited  partnership interests, or units, in the
Partnership were initially offered and sold for a
price of $500.  Limited partner units are not
traded on  any  exchange  and there is no public or
organized trading  market  for them.  The Managing
General Partner has become aware of certain limited
and sporadic transfers of units between limited
partners and third parties, but has no verifiable
information regarding the prices at which such
units have been  transferred.   Further,  a
transferee may  not  become  a  substitute limited
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 NationsBank, N.A.  of Midland, Texas plus one
percent (1%), which value shall be further  reduced
by  a risk factor discount of no more than onethird
(1/3) to be determined by the Managing General
Partner in its sole and absolute discretion.  As of
December  31, 2002, no limited partner units were
purchased by the Managing General Partner.
Southwest, as Managing General Partner, evaluated
several liquidity alternatives for the partnerships
in 2001 and 2002.  During 2002, Southwest
specifically pursued the
possible roll-up and merger of  twentyone
(21)  partnerships with  the  general  partner.
Because                             of   the
complexities and conflicts of interest in such a
transaction,
the  Managing General  Partner  did not make a
formal repurchase offer in  2002  but  has
responded  to  limited partners  desiring  to  sell
their  units  in  the partnerships  on  an "as
requested" basis.  Southwest anticipates  that  it
will  not make a formal repurchase offer during
2003 because the merger  is still being
contemplated and Southwest's Registration Statement
on Form S-4 relating  to the merger is still in the
review process with the  Securities and Exchange
Commission.  Repurchases by Southwest, however,
will continue to  be made on an "as requested"
basis.   In 2001, 15 limited partner units were
tendered  to  and  purchased by the Managing
General  Partner  at  an average  base price of
$26.86 per unit.  In 2000, 32 limited partner
units were  tendered
to  and  purchased by the Managing General  Partner
at  an
average base price of $13.75 per unit.
Number of Limited Partner Interest Holders
As of December 31, 2002, there were 569 holders of
limited partner units in the Partnership.

Distributions
Pursuant to Article III, Section 3.05 of the
Partnership's Certificate  and Agreement  of
Limited Partnership "Net Cash Flow" is  distributed
to  the partners  on  a quarterly basis. "Net Cash
Flow" is defined as  "the  cash generated  by  the
Partnership's investments  in  producing  oil  and
gas properties,  less  (i)  General and
Administrative  Costs,
(ii)  Operating Costs,  and  (iii) any reserves
necessary to meet current  and  anticipated needs
of  the  Partnership, as determined in the sole
discretion  of  the Managing General Partner."


<PAGE>
There were no distributions due to a decrease in
revenues as a result of  a decline  in oil
production and a decrease in gas prices for the
year  ended December  31, 2002.  During 2001,
distributions were made totaling $60,000, with
$54,000 distributed to the limited partners and
$6,000 to the general partners.  For the year ended
December 31, 2001, distributions of $5.15 per
limited  partner  unit were made, based upon 10,484
limited  partner  units outstanding.   During
2000, quarterly distributions  were  made  totaling
$74,026,  with $73,769 distributed to the limited
partners.  For  the  year ended  December 31, 2000,
distributions of $7.04 per limited partner  unit
were made, based upon 10,484 limited partner units
outstanding.

Item 6.   Selected Financial Data
The  following  selected financial data for the
years  ended December  31, 2002,  2001,  2000,
1999, and 1998 should be read in conjunction  with
the financial statements included in Item 8:
                                       Years ended
December
                            31, -------------------
                            -----------------------
                            --
                                               ----
----
                              2002      2001
2000
1999        1998
                     (Restate
                       d)(1)
                              -----    -----     --
---                          ----
-  -----
Revenues                  $ 312,150   346,930
447,515
273,357   288,218

Net income (loss) before
 cumulative effect          (27,700)  8,927
125,731
(26,816   (263,85

)         0)

Net income (loss)           (30,700)  8,927     125,731
(26,816   (263,85

)         0)

Partners' share
 of net income (loss):

General partners            (1,770)   2,092     13,373
(1,782)   (11,946
                                                                   )
Limited partners            (28,930)  6,834     112,358
(25,034   (251,90

) 4)

Limited partners'
  net income (loss)  per
unit
    before    cumulative     (2.47)      .65
effect                                          10.72
(2.39)    (24.03)
Limited partners'
  net income (loss)  per     (2.76)      .65
unit                                            10.72
(2.39)    (24.03)

Limited partners'
  cash distributions per         -
-
unit                                  5.15      7.04               2.75
Total assets              $ 113,662   131,713   176,340
124,769   183,103
(1)  See  Notes  3  and 9 to the Partnership's financial
statements  for  a description of the Partnership's change in
accounting principle.
<PAGE>
Item 7.   Management's  Discussion and Analysis of Financial
Condition  and
          Results of Operations
General
The  Partnership was formed to acquire interests in producing
oil  and  gas properties,  to produce and market crude oil and
natural gas produced  from such  properties and to distribute
any net proceeds from operations to  the general  and  limited
partners.  Net revenues from producing  oil  and  gas
properties are not reinvested in other revenue producing assets
except  to the  extent  that  producing facilities and wells
are  reworked  or  where methods are, employed to improve or
enable more efficient recovery  of  oil and gas reserves.  The
economic life of the Partnership thus depends on the period
over  which the Partnership's oil and gas reserves are
economically recoverable.

Increases   or   decreases   in  Partnership   revenues   and,
therefore,
distributions  to partners will depend primarily on changes in
the  prices received  for  production,  changes in volumes of
production  sold,  lease operating  expenses, enhanced recovery
projects, offset drilling activities pursuant  to  farm-out
arrangements and on the depletion of  wells.   Since
wells  deplete over time, production can generally be expected
to  decline from year to year.
Well  operating costs and general and administrative costs
usually decrease with   production   declines;  however,  these
costs  may   not   decrease proportionately.   Net  income
available for distribution  to  the  limited partners  is
therefore expected to fluctuate in later years based on  these
factors.
Based  on  current  conditions, management anticipates
performing  drilling projects  and  workovers  during  the
years  2003  and  2004  to                                          enhance
production.  The partnership may have an increase in production
volumes for the  years  2003  and  2004, otherwise,
the partnership  will  most  likely experience  the
historical production decline, which have
approximated   9% per year.

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

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

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

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

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

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

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

                                Year Ended
Percenta

ge
                               December 31,
Increase
                              2002      2001
(Decreas
                                                   e) ---
                             --      ----            ----
                             ----
                                                  ---
Average price per $         23.31                  5%
barrel of oil                         22.24
Average price per mcf    $    3.06               (33%)
of gas                                4.58
Oil production in           11,400    13,300     (14%)
barrels
Gas production in mcf       13,500    11,100      22%
Gross oil and gas        $  307,104
346,699                  (11%)
revenue
Net oil and gas revenue  $  61,695
104,976                  (41%)
Partnership              $  -
60,000     (100%)
distributions
Limited partner          $  -
54,000     (100%)
distributions
Per unit distribution    $       -
(100%)
to limited partners                   5.15
Number of limited           10,484    10,484
partner units

Revenues

The  Partnership's oil and gas revenues decreased to $307,104
from $346,699 for the years ended December 31, 2002 and 2001,
respectively, a decrease of 11%.   The  principal factors
affecting the comparison of the  years  ended December 31, 2002
and 2001 are as follows:

1.  The  average  price  for a barrel of oil received  by  the
    Partnership increased  during the year ended December 31,
    2002 as compared  to  the year  ended December 31, 2001 by
    5%, or $1.07 per barrel, resulting  in an increase of
    approximately $12,200 in revenues. Oil sales represented
    87%  of total oil and gas sales during the year ended
    December 31, 2002 as compared to 85% during the year ended
    December 31, 2001.

    The  average  price  for  an  mcf of gas received  by  the
Partnership
    decreased during the same period by 33%, or $1.52 per mcf,
    resulting in a decrease of approximately $20,500 in
    revenues.

    The net total decrease in revenues due to the change in
    prices received from  oil and gas production is
    approximately $8,300.  The market price for  oil  and gas
    has been extremely volatile over the past decade  and
    management  expects a certain amount of volatility to
    continue  in  the foreseeable future.
<PAGE>
2.  Oil  production decreased approximately 1,900 barrels or
    14% during the year ended December 31, 2002 as compared to
    the year ended December 31,
   2001, resulting in a decrease of approximately $42,300 in
                           revenues.
    Gas production increased approximately 2,400 mcf or 22%
      during the same period, resulting in an increase of
    approximately $11,000 in revenues.
    The  net total decrease in revenues due to the change in
    production  is approximately $31,300.  The decrease in oil
    production is mainly due to a  well with a hole in the
    casing, which was repaired and production is coming back to
    normal.  The increase in gas production is in connection
    with a change in estimate, which was reflected in the
    fourth quarter of 2001  for  the  production  month July.
    The Partnership  had  a  small interest  in  a  well, which
    it was discovered was  not  producing  the larger portion
    of gas for the lease, but another well on the same lease
    was  the  major  producer, which the Partnership  owned  a
    very  small interest.   The increase in gas was partially
    offset by a lease,  which has a steep natural decline.
Costs and Expenses
Total  costs and expenses increased to $339,850 from $338,003
for the years ended  December 31, 2002 and 2001, respectively,
an increase  of  1%.
The
increase  is  the result of higher general and administrative
expense  and lease operating costs, partially
offset by a decrease in depletion expense.

1.    Lease  operating  costs  and production
   taxes  were  2% higher,  or approximately
   $3,700 more during the year ended December  31,
   2002  as compared to the year ended December 31,
   2001.

2.  General and administrative costs consist of
    independent accounting  and engineering  fees,
    computer services, postage,  and  Managing
    General Partner  personnel costs. General and
    administrative  costs  increased less  than 1%
    or approximately $200 during the year ended
    December  31, 2002 as compared to the year
    ended December 31, 2001.

3.  Depletion expense decreased to $10,000 for the
    year ended December  31, 2002  from  $12,000
    for the same period in 2001.   This  represents
    a decrease  of  17%.   In  the fourth quarter
    of  2002,  the  Partnership changed  methods of
    accounting for depletion of capitalized costs
    from the units-of-revenue  method to the units-
    of-production
    method.
The
    newly  adopted  accounting principle is preferable in the
   circumstances because the units-of-production method
    results in a better matching  of the  costs  of  oil
    and gas production against  the  related  revenue
    received  in periods of volatile prices for production
    as  have  been experienced  in  recent periods.
    Additionally, the unitsof-production method is the
    predominant method used by full cost companies in the
    oil and gas industry, accordingly, the change improves
    the comparability of the Partnership's financial
    statements with its peer group.  The change in method
    had no effect on depletion expense in 2002 however
  the effect did decrease 2002 net income by $3,000.  See
    Note 3 of the notes to the Partnership's financial
    statements.
   The  major  factor  in  the decrease in depletion
expense
   between  the comparative  periods was the increase in
   the price of oil and  gas                used to
   determine the Partnership's
   reserves for January 1, 2003 as compared to  2002,
   which provided more economically recoverable proved
   reserves at January 1, 2003 which caused the depletion
   rate per equivalent  unit produced  to  decline.  Also,
   as discussed above, the  total  equivalent units
   produced in 2002 declined from 2001.


<PAGE>

Results of Operations

B.  General Comparison of the Years Ended December 31,
2001 and 2000
The  following  table  provides certain information
regarding performance factors for the years ended December
31, 2001 and 2000:
                           Year Ended      Percenta
                                              ge
                          December 31,     Increase
                         2001      2000    (Decreas
                                              e)
                        -----     -----    --------
                                             ----
Average price per   $    22.24              (21%)
barrel of oil                    28.15
Average price per   $     4.58                7%
mcf of gas                       4.28
Oil production in      13,300    13,500      (1%)
barrels
Gas production in      11,100    15,700     (29%)
mcf
Gross oil and gas   $  346,699   447,179    (22%)
revenue
Net oil and gas     $  104,976   216,159    (51%)
revenue
Partnership         $  60,000    74,026     (19%)
distributions
Limited partner     $  54,000    73,769     (27%)
distributions
Per unit            $     5.15              (27%)
distribution to                  7.04
limited partners
Number of limited      10,484    10,484
partner units

Revenues

The  Partnership's oil and gas revenues decreased to
$346,699 from $447,179 for the years ended December 31,
2001 and 2000, respectively, a decrease of 22%.   The
principal factors affecting the comparison of the  years
ended December 31, 2001 and 2000 are as follows:

1.  The  average  price  for a barrel of oil received  by
the
Partnership
    decreased  during the year ended December 31, 2001 as
    compared  to  the year ended December 31, 2000 by 21%,
    or $5.91 per barrel, resulting  in a  decrease of
    approximately $78,600 in revenues. Oil sales
    represented 85%  of total oil and gas sales during the
    year ended December 31, 2001 as compared to 85% during
    the year ended December 31, 2000.
    The  average  price  for  an  mcf of gas received  by
the Partnership
    increased  during the same period by 7%, or $.30 per
    mcf, resulting  in an increase of approximately $3,300
    in revenues.

  The net total decrease in revenues due to the change in
    prices received from oil and gas production is
    approximately $75,300.  The market price for  oil  and
    gas has been extremely volatile over the past decade
    and management  expects a certain amount of volatility
    to continue  in  the foreseeable future.

<PAGE>
2.  Oil  production decreased approximately 200 barrels or
    1% during  the year ended December 31, 2001 as
    compared to the year ended December 31, 2000,
    resulting in a decrease of approximately $5,600 in
    revenues.

  Gas production decreased approximately 4,600 mcf or 29%
    during the same period, resulting in a decrease of
    approximately $19,700 in revenues.

    The  total  decrease  in revenues due to the change
    in production  is approximately $25,300.  The decrease
    in gas production is in connection with a change in
    estimate, which was reflected in the fourth quarter of
    2001.   The Partnership had a small interest in a
    well, which  it  was discovered  was not producing the
    larger portion of gas for the  lease, but  another
    well on the same lease was the major producer,  which
    the Partnership owned a very small interest.
Costs and Expenses
Total  costs and expenses increased to $338,003 from
$321,784 for the years ended  December 31, 2001 and 2000,
respectively,
an increase  of  5%.
The increase  is  the  result  of  higher general and
administrative  expense, depletion expense and
lease operating costs.

1.  Lease  operating  costs  and  production  taxes
were  5% higher,    or
    approximately $10,700 more during the year
    ended December 31,  2001  as compared to the
    year ended December 31, 2000.

2.  General and administrative costs consist of
    independent accounting  and engineering  fees,
    computer services, postage,  and  Managing
    General Partner personnel costs. General and
    administrative costs increased 2% or
    approximately  $1,500 during the year ended
    December  31, 2001  as compared to the year
    ended December 31, 2000.

3.  Depletion expense increased to $12,000 for the
    year ended December  31, 2001  from  $8,000
    for the same period in 2000.   This  represents
    an increase  of  50%.   Depletion is calculated
    using the units-of-revenue method  of
    amortization based on a percentage of current
    period  gross revenues  to  total future gross
    oil and gas revenues, as estimated  by the
    Partnership's independent petroleum
    consultants.

     The  major  factor  in  the increase in depletion expense

    between  the comparative periods was the decrease in the price

    of oil and  gas  used to determine the Partnership's reserves

    for January 1, 2002 as compared to  2001,  and the decrease in

    oil and gas revenues  received  by  the Partnership  during

    2001 as compared to 2000.  Revisions

of  previous estimates  can be attributed to the changes in

production  performance, oil  and  gas  price and production costs.

The impact of the  revision would  have increased  depletion

expense approximately  $3,000  as  of December 31, 2000.





<PAGE>

C.  Revenue and Distribution Comparison

Partnership income (loss) for the years ended December 31, 2002,
2001  and 2000  was  $(30,700),  $8,927  and $125,731,
respectively.   Excluding  the effects  of  depreciation, depletion
and amortization,  net  income  (loss) would  have been (20,700) in
2002, $20,927 in 2001, and $133,731  in  2000. Correspondingly,
Partnership distributions for the years ended December 31, 2002,
2001 and 2000 were $0, $60,000 and $74,026, respectively.




The  sources  for  the  2001  distributions of $60,000  were oil
and  gas operations  of  approximately  $86,100  and  the change
in  oil  and  gas properties  of  approximately $(20,900),
resulting  in  excess  cash  for contingencies  or subsequent
distributions.   The  sources  for  the  2000 distributions  of
$74,026  were oil and gas  operations  of approximately $83,100
and the change in oil and gas properties of approximately  $6,300,
resulting in excess cash for contingencies or subsequent
distributions.




There were no distributions due to a decrease in revenues as a
result of  a decline  in oil production and a decrease in gas
prices for the year  ended December 31, 2002.  Total distributions
during the year ended December  31,
2001  were $60,000 of which $54,000 was distributed to the limited
partners and  $6,000 to the general partners.  The per unit
distribution to  limited partners  during the same period was
$5.15. Total distributions during  the year  ended December 31,
2000 were $74,026 of which $73,769 was distributed to  the limited
partners and $257 to the general partners.  The  per unit
distribution to limited partners during the same period was $7.04.
Since  inception of the Partnership, cumulative monthly cash
distributions of  $2,827,732  have been made to the partners. As of
December  31,  2002, $2,602,574 or $248.24 per limited partner unit
has been distributed to  the limited partners, representing a 50%
return of capital contributed.
<PAGE>
Liquidity and Capital Resources
The  primary source of cash is from operations, the receipt of
income  from interests in oil and gas properties.  The Partnership
knows of no  material change, nor does it anticipate any such
change.

Cash  flows  (used in) provided by operating activities were
approximately $(5,100)  in 2002 compared to $86,100 in 2001 and
approximately $83,100  in 2000.   The  principal use of the 2002
cash flow from operating  activities was for operations.

Cash  flows  (used in) provided by investing activities were
approximately $(12,100) in 2002 compared to $(20,900) in 2001 and
approximately $6,300 in 2000.   The  principal use of the 2002 cash
flow from investing  activities was the additions of oil and gas
properties.

Cash  flows  provided by (used in) financing activities were
approximately $100  in 2002 compared to $(60,300) in 2001 and
approximately $(74,200)  in 2000.

As  of  December  31,  2002, the Partnership had approximately
$15,600  in negative working capital.  The Managing General Partner
knows of no unusual contractual  commitments.  Although
the Partnership  held  many  long-lived properties               at
inception, because  of  the  restrictions   on   property
development  imposed by the partnership agreement, the Partnership
cannot develop   its   non  producing  properties, if  any.   Without
continued development,  the producing reserves continue to deplete.
Accordingly,  as the Partnership's properties have matured and depleted,
the net cash flows from  operations  for  the  Partnership has steadily
declined,  except  in periods  of  substantially  increased commodity
pricing.   Maintenance  of properties  and administrative expenses for
the Partnership are  increasing relative to production.  As the
properties continue to deplete, maintenance of  properties  and
administrative costs as a percentage of production  are expected to
continue to increase.

The  Managing General Partner has examined various alternatives to
address the  issue of depleting producing reserves.
Continuing operations  exposes the
Partnership to  an  inevitable  decline  in  operating  results  and
distributions  of  cash.   Liquidating  the  Partnership  would
result  in immediate  realization of cash for limited partners,
but  prices  paid  by purchasers  of Partnership property in
liquidation would likely  include  a substantial discount for
risks and uncertainties of future cash  flows,  as well  as
any development risks.  After reviewing various alternatives,
we initiated a plan to merge the Partnership and 20 other
limited partnerships with  and  into  the Managing General
Partner.  On October  17,  2002,  the Managing  General Partner
filed a Registration Statement on form  S-4  with the
Securities  and Exchange Commission relating to this proposed
merger. There is no assurance, however, that this merger will
be consummated.

Liquidity - Managing General Partner
The  Managing General Partner has a highly leveraged capital
structure with approximately $124.0 million of principal due
between December 31, 2002 and December  31, 2004.  The Managing
General Partner is constantly  monitoring
its cash position and its ability to meet its financial
obligations as they become due, and in this effort, is
continually exploring various strategies for  addressing  its
current  and future liquidity  needs.   The  Managing General
Partner regularly pursues and evaluates recapitalization
strategies and  acquisition  opportunities  (including
opportunities  to  engage   in mergers,  consolidations or
other business combinations) and at  any  given time may be in
various stages of evaluating such opportunities.
Based   on  current  production,  commodity  prices  and  cash
flow from
operations,  the Managing General Partner has adequate cash
flow  to  fund debt  service, developmental projects and day to
day operations, but it  is not  sufficient  to  build a cash
balance which would  allow  the  Managing General  Partner to
meet its debt principal maturities scheduled for  2004.
Therefore  the Managing General Partner is currently seeking to
renegotiate the  terms  of its obligations, including extending
maturity dates,  or  to engage  new  lenders or equity
investors in order to satisfy its  financial obligations
maturing in 2004.

There  can  be  no  assurance  that  the Managing  General
Partner's  debt restructuring efforts will be successful.  In
the event these  efforts  are unsuccessful,  the Managing
General Partner would need  to  look  to  other alternatives
to  meet its debt obligations, including potentially  selling
its  assets.  There can be no assurance, however, that the
sales of  assets can  be  successfully  accomplished on terms
acceptable  to  the  Managing General Partner.  Please see the
Partnership's Quarterly Report on Form 10Q  for  the quarterly
period ended September 30, 2003, which will be  filed with the
Commission on or before November 14, 2003, for updated
information on  the  liquidity of the Managing General Partner.
The liquidity  of  the Managing General Partner, however, does
not have a material impact  on  the operations   of  the
Partnership.   The  partnership  agreement
of   the Partnership  allows  the  limited partners to elect  a
successor  managing general partner to continue
Partnership operations.

<PAGE>
Recent Accounting Pronouncements
The  FASB  has  issued Statement No. 143
"Accounting for  Asset Retirement Obligations"
which establishes requirements for the accounting
of  removaltype  costs  associated with asset
retirements.  The standard is  effective for
fiscal  years beginning after June 15, 2002, with
earlier  application encouraged.   The  new
standard requires the Partnership  to recognize  a
liability  for  the present value of all legal
obligations associated  with the  retirement  of
tangible longlived assets and to capitalize  an
equal amount  as  a cost of the asset and allocate
the additional cost  over  the estimated useful
life of the asset.  On January 1, 2003,  the
Partnership recorded  additional costs, net of
accumulated depreciation, depletion  and
amortization,  of  approximately $159,604,  a  long
term   liability   of approximately $139,208  and
a  gain  of  approximately  $20,396  for  the
cumulative  effect  on  depreciation, depletion
and amortization  of  the additional costs and
accretion expense on the liability related to
expected abandonment costs of its oil and natural
gas producing properties.

Item 7A.  Quantitative and Qualitative Disclosures
About Market Risk

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


<PAGE>
Item 8.   Financial Statements and Supplementary Data

                 Index to Financial Statements
   Page
Independent  Auditors Report   23

Balance Sheets                                                          24

Statements of Operations                                                25

Statement of Changes in Partners' Equity                                26

Statements of Cash Flows                                                27

Notes to Financial Statements                                           28

<PAGE>

































                  INDEPENDENT AUDITORS REPORT

The Partners
Southwest Oil & Gas Income Fund X-A, L.P.
(A Delaware Limited Partnership):


We  have  audited the accompanying balance sheets
of Southwest Oil  &  Gas Income Fund X-A, L.P. (the
"Partnership") as of December 31, 2002 and 2001,
and  the related statements of operations, changes
in partners' equity  and cash  flows  for each of
the years in the three year period ended  December
31, 2002.   These  financial  statements are  the
responsibility of  the Partnership's management.
Our responsibility is to express an  opinion  on
these financial statements based on our audits.

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

to above present fairly, in  all  material

respects, the financial position of Southwest Oil

&  Gas Income  Fund X-A, L.P. as of December 31,

2002 and 2001 and the results  of its  operations

and its cash flows for each of the years in the

three  year period  ended  December  31, 2002 in

conformity with accounting principles generally

accepted in the United States of America. As

discussed in Notes 3 and 9 to the financial

statements, the Partnership changed its method of

computing depletion in 2002.








KPMG LLP Midland, Texas
March  14,  2003, except as to Notes 3, 9 and 10,
which is as of  July  11, 2003

<PAGE>
                Southwest Oil & Gas Income Fund X-
A, L.P.
                     (a Delaware limited

partnership
                              )
Balance
                              Sheets
                        December 31,
2002
and 2001

2002     2001

(Restate

d)
                                  ---
--      -----

Assets
------

Current assets:
  Cash and cash equivalents    $
4,131
                 21,313
                                 ----
                                 ----
                                 ----
                                 ---
                                 ---       -----
  Total current assets
4,131  21,313
                                 ----
                                 ----
                                 ----
                                 ---
                                 ---       -----
Oil  and  gas  properties  -
using the full-
cost method of accounting
3,829,91
                3,817,78
                                 7         6
       Less      accumulated
depreciation,
  depletion and amortization
3,720,38
3,707,38
                                 6         6
                                 -----
---
                                 -----
---
                                 ---       -----
  Net oil and gas properties
109,531         110,400
                                 -----
---
                                 -----
---
                                 ---       -----
                              $
113,662        131,713

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

Current liabilities:
 Distributions payable        $  410       336
 Payable to Managing General
19,363          6,787
Partner
                                 -----
---
                                 -----
---
                                 ---       ----
  Total current liabilities
19,773          7,123
                                 -----
---
                                 -----
---
                                 ---       ----

Partners' equity:
 General partners
(21,139)
(19,368)
           Limited partners
           115,028   143,958
                                 -----
---
                                 -----
---
                                 ---       ----
  Total partners' equity
93,889          124,590
                                 -----
---
                                 -----
---
                                 ---       ----
                              $
113,662        131,713

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


                  The accompanying
notes are
                   an integral
                   part of these
                   financial
                   statements.
<PAGE>
                Southwest Oil &
                     Gas Income
                     Fund X-A,
                     L.P. (a
                     Delaware
                     limited
                     partnership
                     )
                         Stateme
                         nts of
                         Operati
                         ons
        Years ended December 31, 2002, 2001
and 2000
                                       2002
                                     2001      2000
                                     (Restate
                                        d)
                                      -----      --
--
-   -----
Revenues
-------------
Oil and gas income               $  307,104
346,699
                       447,179
 Interest                            -         231
336
 Miscellaneous                       5,046     -
-
                                     --------  ------
                                     --  ----------
                                     ---  --312,150
346,930        447,515
                                     --------  ------
                                     --  ----------
---  ---
Expenses
------------
 Production                          245,409
241,723        231,020
 General and administrative          84,441    84,280    82,764
   Depreciation,  depletion  and     10,000    12,000    8,000
amortization
                                     --------  ------
                                     --  ----------      ---  ---
                                     339,850
338,003        321,784
                                     --------  ------
                                     --  ----------      ---  ---
Net    income   (loss)    before     (27,700)  8,927     125,731
cumulative effect

Cumulative effect of  change  in     (3,000)   -         -
accounting principle
                                     --------  ------
                                     --  ----------      ---  ---
Net income (loss)                 $  (30,700)  8,927     125,731
                                     ======
======         ======
Net income (loss) allocated to:

 Managing General Partner         $  (1,593)   1,883
                 12,036

======
======         ======
  General Partner                  $
(177)           210
                  1,337

======
======         ======
 Limited partners                 $
(28,930)  6,834
                 112,358

======
======         ======
Per   limited  partner  unit  $   (2.47)
..65
before cumulative effect                                 10.72
   Cumulative effect per limited       (.29)   -         -
partner unit
                                     --------  ------
                                     --  ----------      ---  ---
  Per limited partner unit        $   (2.76)
..65

                                     10.72 ====== ======
                                     ======
Pro   forma   amounts   assuming
change is applied
 retroactively (See Note 3):
   Net   income  (loss)   before  $  -         9,927     124,731
cumulative effect
                                     ======
======         ======
    Per   limited  partner  unit  $        -
..75
(10,484.0 units)                                         10.62
                                     ======
======         ======
Net income (loss)                 $  -         9,927     124,731
                                     ======
======         ======
    Per   limited  partner  unit  $        -
..75
(10,484.0 units)                                         10.62
                                     ====== ======
======
                  The accompanying
notes are an integral
                   part of these
financial statements. <PAGE>
                Southwest Oil & Gas
                     Income Fund X-
                     A, L.P. (a
                     Delaware
                     limited
                     partnership)
                 Statement of
               Changes in Partners'
               Equity Years ended
               December 31, 2002,
               2001 and 2000


                            General   Limited
                            Partner
                            s
                            Partner
                            s Total
                            -------
                            -  ----
                            ---  --
                            -----
                              ----      ----
Balance at December 31,  $  (28,577)
152,535   123,958 1999

 Net income                 13,373
112,358
                125,731

 Distributions              (257)
(73,769)
               (74,026)
                            --------
---------------
                            --
--        --
Balance at December 31,     (15,461)
191,124         175,663
2000

 Net income                 2,093
6,834
                    8,927

     Distributions              (6,000)
             (54,000)  (60,000)
                            --------  ------
                            --  ---------
--        -Balance at December 31,   (19,368)
143,958         124,590
2001

     Net loss (Restated)        (1,770)
             (28,930)  (30,700)

 Distributions              -         -
-
                            --------  ------
                            --  ---------
--        -Balance at December 31,  $  (21,139)
115,028         93,889
2002 (Restated)
                            ======    ======
======






                  The
                   accompanying
                   notes are an
                   integral part
                   of these
                   financial
                   statements.
<PAGE>
                Southwest Oil &
                     Gas Income
                     Fund X-A,
                     L.P. (a
                     Delaware
                     limited
                     partnership
                     )
                         Stateme
                         nts of
                         Cash
                         Flows
               Years ended December 31, 2002, 2001
and
2000
                                        2002
2001      2000
                                      (Restate
                                         d)
                                       -----     ---
--     -----
Cash    flows   from    operating
activities:
  Cash received from oil and  gas  $  299,730
391,231        415,489
sales
  Cash  paid to Managing  General
Partner
     for    production   expense,
administrative
     fees    and   general    and     (309,901
(305,357  (332,733
administrative overhead               )         )
)
 Interest received                    -         231
336
 Miscellaneous settlement             5,046     -
-
                                      --------  ----
--
                                      --  --------
   --   -Net cash (used in) provided by (5,125) 86,105
   83,092
operating activities
                                      --------  ------
                                      --  --------
--   -Cash      flows                 from    investing
activities:
   Additions  to  oil   and   gas     (12,359)
(20,899)  -
properties
   Sale of oil and gas properties       228       -
                         6,312
                                      --------  ------
                                      --  --------
   --   -Net cash (used in) provided by (12,131)
(20,899)  6,312
investing activities
                                      --------  ------
                                      --  --------
--   -Cash flows provided by (used  in)
financing activities:
        Distributions to partners            74
                  (60,341)  (74,160)
                                      --------  ------
                                      --  --------
--   -Net  (decrease) increase in  cash (17,182)
4,865          15,244
and cash equivalents

     Beginning of year                    21,313
             16,448    1,204
                                      ---
-----  -----
                                      ---  --------
--   -End of year                         $  4,131
21,313
                       16,448
                                      ======
======          ======
Reconciliation  of   net   income
(loss) to
 net cash provided by (used in)
 operating activities:

Net income (loss)                  $  (30,700)  8,927
125,731

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

   Depreciation,  depletion   and     10,000    12,000
8,000
amortization
  Cumulative effect of change  in     3,000     -
-
accounting principle
     (Increase)    decrease    in     (7,375)   44,532
(31,690)
receivables
 Increase (decrease) in payables      19,950    20,646
                       (18,949)
                                      --------  ------
                                      --  --------
-    Net          cash  (used in) provided  by
operating
    activities                        $  (5,125)
                  86,105    83,092
                                      ====== ======
=====



                  The accompanying
notes are an integral
                    part of these
financial statements. <PAGE>
                Southwest Oil & Gas
Income
                 Fund X-A, L.P. (a
                 Delaware limited
                     partnership)
                Notes to Financial
Statements

1.   Organization
     Southwest  Oil and Gas Income Fund X-A, L.P.
     was organized under  the laws of the state of
     Delaware on January 29, 1990, for the purpose
     of acquiring  producing oil and gas properties
     and to produce and  market crude oil and
     natural gas produced from such properties for
     a term  of 50  years, unless terminated at an
     earlier date as provided for in the
     Partnership  Agreement.   The Partnership
     sells  its  oil  and   gas production  to  a
     variety of purchasers with the prices  it
     receives being dependent  upon the oil and gas
     economy.  Southwest Royalties, Inc.
     serves the Managing General Partner and
     H. H. Wommack,  III,  as the  individual
     general partner.  Revenues, costs, and
expenses  are
     allocated as follows:
                 Limited   General
                              Partners  Partners
                              --------  --------

--       --Interest  income on
capital  100%      contributions
Oil and gas sales             90%
10% All other revenues
90%
10%
Organization
and   offering
100%
-
costs (1)
Syndication
costs
100%
-
Amortization of
organization
100%
-
costs
Property
acquisition
costs 100%                         Gain/loss    on
property  90%
10% disposition
Operating and
administrative
90%       10%
costs (2)
Depreciation,
depletion  and
amortization
 of oil and as
properties 100%                    All other costs
90%       10%
          (1)   All  organization costs in excess of 3% 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 3%  of  initial capital contributions for such organization
          costs.

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

2.   Summary of Significant Accounting Policies

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

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


<PAGE>
                Southwest Oil & Gas Income Fund X-A, L.P.
                    (a Delaware limited partnership)

                      Notes to Financial Statements

2.   Summary of Significant Accounting Policies - continued

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

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

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

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

     Gas Balancing
     The  Partnership  utilizes the sales method
     of accounting       for  gasbalancing
     arrangements.  Under this
     method the Partnership recognizes sales
     revenue  on all gas sold.  As of December 31,
     2002,  2001  and 2000,
there were no significant amounts of imbalance in
terms of units or value.

     Income Taxes
     No  provision  for  income  taxes  is
reflected  in
     these  financial statements, since the tax effects of the
     Partnership's income or  loss are passed through to the
     individual partners.

    In   accordance  with  the  requirements  of  Statement
of  Financial
     Accounting  Standards  No. 109, "Accounting  for  Income
     Taxes",  the Partnership's tax basis in its net oil and
     gas properties at  December 31, 2002 and 2001 is $39,772
     and $53,919, respectively, more 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.

     Number of Limited Partner Units
     As  of  December  31,  2002, 2001 and 2000 there were
     10,484  limited partner units outstanding held by 569,
     569 and 564 partners.

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

<PAGE>
                Southwest Oil & Gas Income Fund X-A, L.P.
                      (a Delaware limited
partnership)
                      Notes to Financial
Statements
2.   Summary of Significant Accounting Policies - continued
     Fair Value of Financial Instruments
     The  carrying amount of cash and accounts receivable
     approximates fair value due to the short maturity of
     these instruments.

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

     Recent Accounting Pronouncements
     The FASB has issued Statement No. 143 "Accounting for
     Asset Retirement Obligations"  which  establishes
     requirements for  the  accounting  of removal-type costs
     associated with asset retirements.  The standard is
     effective for fiscal years beginning after June 15, 2002,
     with earlier application encouraged.  The new standard
     requires the Partnership  to recognize  a  liability for
     the present value of all legal obligations associated
     with the retirement of tangible long-lived assets  and
     to capitalize  an  equal amount as a cost of the asset
     and allocate  the additional  cost  over the estimated
     useful
life  of  the  asset.
On January  1,  2003, the Partnership recorded additional
     costs,  net  of accumulated depreciation,
     depletion and amortization, of approximately
     $159,604, a long term liability of
     approximately $139,208 and  a  gain of
     approximately  $20,396 for the cumulative
     effect on depreciation, depletion  and
     amortization  of the additional  costs  and
     accretion expense on the liability related to
     expected abandonment costs of  its oil and
     natural gas producing properties.
     Depletion Policy
     In  2002,  the Partnership changed methods of
     accounting for depletion of capitalized costs
     from the units-ofrevenue method to the units-
     ofproduction method. (See Note 3)

3.   Cumulative effect of a change in accounting
principle
     In  the  fourth  quarter of 2002, the
     Partnership changed methods  of accounting
     for  depletion  of capitalized costs  from
     the  units-ofrevenue  method to the units-of
     production method.  The newly  adopted
     accounting principle is preferable in the
     circumstances  because  the units-of-
     production method results in a better matching
     of the  costs of  oil  and  gas production
     against the related revenue  received  in
     periods of volatile prices for production as
     have been experienced  in recent periods.
     Additionally, the units-of-production method
     is the predominant  method used by full cost
     companies in
     the  oil  and  gas industry,  accordingly, the change
     improves the comparability  of  the Partnership's
     financial  statements  with  its  peer   group.
     The Partnership   adopted  the  units-of-production
     method
through       the
     recording  of a cumulative effect of a change in
     accounting  principle in  the  amount  of  $3,000
     effective as of  January  1,
     2002.   The Partnership's  depletion for the year ended
     2002 has  been
     calculated using  the  units-of-production method and
     prior years have  not  been restated.                              The
     pro  forma amounts for  2001  and  2000,  which  are
     presented  on  the face of the statements of operations,
reflect  the effect  of retroactive application of
                        the
     units-of-production  method. The  change  in
     method  had no effect on depletion  expense
     in  2002 however  the effect did decrease 2002
     net income by $3,000  ($.29  per limited
     partner unit).  See Note 10 for the effects of
     the change  in depletion method on the
     individual quarters of 2002.

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

<PAGE>
                Southwest Oil & Gas Income Fund
X-A, L.P.
                (a Delaware limited partnership)

            Notes to Financial Statements
4.   Liquidity - Managing General Partner - continued
     Based  on  current  production, commodity prices
     and  cash flow  from operations,  the Managing
     General Partner has adequate  cash  flow  to
     fund  debt  service, developmental projects and
     day to day operations, but it is not sufficient
     to build a cash balance which would allow the
     Managing  General  Partner  to  meet  its  debt
     principal maturities scheduled  for  2004.
     Therefore  the  Managing General  Partner  is
     currently  seeking  to  renegotiate the  terms
     of  its  obligations, including  extending
     maturity dates, or seek new  lenders  or  equity
     investors in order to satisfy its financial
     obligations  maturing  in 2004.
     There  can  be  no assurance that the Managing
     General Partner's  debt restructuring efforts
     will be successful. In the event these  efforts
     are  unsuccessful, the Managing General Partner
     would need to look  to other alternatives to
     meet its debt obligations, including potentially
     selling its  assets.  There can be no assurance,
     however,  that the sales  of  assets can be
     successfully accomplished on terms acceptable to
     the  Managing  General  Partner.
Please  see  the  Partnership's Quarterly Report on
Form 10Q for the quarterly period ended September 30,
2003,
     which  will  be  filed with the Commission  on
     or  before November  14,  2003, for updated
     information on the liquidity  of  the Managing
     General  Partner.  The liquidity  of  the
     Managing  General Partner, however, does not
     have a material impact on the operations of the
     Partnership.  The partnership agreement of the
     Partnership allows the limited partners to
     elect a successor managing general partner  to
     continue Partnership operations.

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

     Southwest,  as  Managing General Partner,
     evaluated several liquidity alternatives  for
     the partnerships in 2001 and 2002.   During
     2002, Southwest  specifically pursued the
     possible  roll-up  and  merger  of twenty-one
     (21) partnerships with the general partner.
     Because of the complexities  and  conflicts of
     interest in such  a transaction,  the Managing
     General  Partner did not make a formal
     repurchase  offer  in 2002  but  has  responded
     to limited partners desiring to  sell  their
     units  in  the partnerships  on an "as
     requested"  basis.   Southwest anticipates
     that  it will not make a formal repurchase
     offer  during 2003  because  the merger is
     still being contemplated and  Southwest's
     Registration Statement on Form S-4 relating to
     the merger is still  in the  review process
     with  the Securities  and  Exchange
     Commission. Repurchases by Southwest, however,
     will continue to be made
     on an  "as requested" basis.
     The  Partnership  is  subject  to various  federal,
     state and  local environmental  laws  and
     regulations, which establish  standards  and
     requirements  for  protection
  of the  environment.   The  Partnership cannot  predict
     the future impact of such standards and  requirements,
     which  are  subject to change and can have retroactive
     effectiveness. The  Partnership  continues to monitor
     the status of  these  laws  and regulations.

     As  of December 31, 2002, the Partnership has not been
     fined, cited or notified  of any environmental
     violations and management is not  aware of  any
     unasserted violations, which would have a  material
     adverse effect upon capital expenditures, earnings or
     the competitive position in  the  oil and gas
     industry.  However, the Managing General  Partner does
     recognize  by  the very nature of its business,
     material  costs could be incurred in the near term to
     bring the Partnership into total compliance.   The
     amount of such future expenditures is not  reliably
     determinable  due to several factors, including the
     unknown  magnitude of  possible contaminations, the
     unknown timing  and  extent  of  the corrective
     actions  which may be required, the
     determination  of  the Partnership's  liability in
     proportion to, other  responsible  parties and  the
     extent  to  which  such expenditures  are  recoverable
     from insurance  or  indemnifications  from prior
     owners of  Partnership's properties.

<PAGE>
                Southwest Oil & Gas Income Fund X-A, L.P.
             (a Delaware limited partnership)

               Notes to Financial Statements

6.   Related Party Transactions
     A  significant  portion  of the oil and gas properties
     in which  the Partnership  has  an interest are
     operated by and purchased  from  the Managing  General
     Partner.  As provided for in the operating agreement
     for  each respective oil and gas property in which the
     Partnership has an  interest,  the  operator  is  paid
     an  amount  for administrative overhead attributable
     to operating such properties, with such  amounts to
     Southwest  Royalties, Inc.  as  operator
     approximating  $40,700, $39,800  and $45,100 for the
     years ended December 31, 2002,  2001  and 2000,
     respectively.  The amounts for administrative overhead
     have been deducted from gross oil and gas revenues in
     the determination  of  net profit  interest. In
     addition, the  Managing  General  Partner  and certain
     officers and employees may have an interest in  some
     of the properties that the Partnership also
     participates.

     Certain  subsidiaries  or affiliates of the Managing
     General  Partner perform  various  oilfield  services
     for
properties      in  which
the
     Partnership  owns an interest.  Such services
     aggregated approximately $20,500,  $15,300 and $12,800
     for the years
     ended December  31,  2002, 2001  and  2000,
     respectively. The amounts  for  oilfield  services
     performed  for  the partnership by affiliates of the
     Managing  General Partner have  been deducted from
     gross oil and gas  revenues  in the determination of
     net profit interest.

     Southwest  Royalties,  Inc., the Managing General
     Partner,  was  paid $78,000  during  2002,  2001 and
     2000, as an administrative  fee,  for indirect
     general   and
administrative  overhead        expenses.
The
     administrative fees are included in general and
         administrative expense on the statement of operations.

     Payable to Southwest Royalties, Inc., the Managing General Partner,
     of approximately $19,400 and $6,800 are from oil and gas
     production,  net of lease operating costs and production taxes, as
     of December 31, 2002 and 2001, respectively.

7.   Major Customers
          No  material portion of the Partnership's business is
     dependent  on  a single  purchaser, or a very few purchasers, where
     the  loss  of  one would  have  a
material  adverse  impact      on  the  Partnership.                   Two
     purchasers  accounted for 75% of the Partnership's total
     oil  and  gas production  during  2002:
     Plains Marketing LP  for  50%  and  Navajo
     Refining  Company Inc. for 25%.  Contracts for 2002 with
     these  major purchasers  are month-to-month
                     contracts.
     Prices received from  these major  purchasers
     ranged from a low of $21.52 per Bbl  to      a
     high  of $21.95   per  Bbl.
     Three  purchasers  accounted  for  84%   of
     the Partnership's  total  oil      and  gas production
     during
2001:   Plains
     Marketing  LP  for 52%, Navajo Refining Company for 22%,
 Duke  Energy Field Services for 10%. Contracts for
                        2001
     with these major purchasers cover time periods
     ranging from month-to-month contracts up to
     year-toyear  contract periods.  Prices received
     from these major  purchasers ranged  from a low
     of $24.16 per Bbl to a high of $24.58 per  Bbl
     and $4.46 per mcf.  Four purchasers accounted
     for 85% of the Partnership's total  oil  and
     gas production during 2000:  Plains Marketing
     LP  for 27%,  Eaglewing Trading Inc. for 23%,
     Navajo Refining Company for  22% and Phillips
     66  for  13%.             Contracts for  2000
     with  these
     major purchasers cover time periods ranging
     from month-tomonth contracts up to  year-to-
     year contract periods. Prices received from
     these  major purchasers ranged from a low of
     $26.68 per Bbl to a high of $26.91 per Bbl.
     All purchasers of the Partnership's oil and gas
     production  are unrelated third parties.  In
     the event any of these purchasers were to
     discontinue  purchasing  the Partnership's
     production,  the  Managing General  Partner
     believes that a substitute purchaser  or
     purchasers could be located without delay.
     No other purchaser accounted for
     an amount equal to or greater than 10% of the
     Partnership's sales of  oil and gas production.

<PAGE>
                Southwest Oil & Gas Income Fund X-A,
L.P.
          (a Delaware limited partnership)

            Notes to Financial Statements

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

                                Oil       Gas
                               (bbls)    (mcf)
                              --------  --------
                                ----      ----
Total Proved January 1, 2000
143,000         163,000
   Revisions   of   previous
21,000   20,000
estimates
             Production
         (14,000)  (16,000)
                              ----
--
                              --
--
                              ----
--
                              - --
December 31, 2000
150,000         167,000

   Revisions   of
previous (8,000)
(41,000)
estimates
             Production
         (13,000)
         (11,000)
   ----- --  -  -----         - --
December 31, 2001
129,000         115,000
 Revisions   of   previous
(16,000)
              (31,000)
estimates
             Production
         (11,000)  (14,000)

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

-- --
December 31, 2002
102,000         70,000

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


Oil    Gas
(bbls)           (mcf)
                              ----
--
                                --
                                --
--
                                --
--
                                --
-    ---
Proved developed reserves -
December 31, 2000
138,000         146,000

======   ======
December 31, 2001
126,000         102,000
                              ======    ======
December 31, 2002             99,000    57,000
                              ======    ======

     All  of  the Partnership's reserves are
     located within the continental United States.
     *Ryder Scott Company, L.P. prepared the
     reserve and present value data for  the
     Partnership's existing properties as of
     January 1, 2003.  The reserve  estimates were
     made in accordance with guidelines established
     by
     the Securities and Exchange Commission
     pursuant to Rule 410(a) of Regulation  S-X.
     Such guidelines require oil and gas reserve
     reports be  prepared under existing economic
     and operating conditions with  no provisions
     for  price and  cost  escalation  except  by
     contractual arrangements.
     Oil  price  adjustments  were made in the
individual
     evaluations  to reflect  oil quality,
     gathering and transportation costs. The
     results of  the  reserve report as of January
     1, 2003 are an average price  of $28.31 per
     barrel.
     Gas  price  adjustments  were made in the
individual
     evaluations  to reflect  BTU  content,
     gathering and transportation  costs  and  gas
     processing  and
          shrinkage. The results of the reserve  report  as  of
     January 1, 2003 are an average price of $4.71 per Mcf. <PAGE>
                Southwest Oil & Gas Income Fund X-A, L.P.
                    (a Delaware limited partnership)

                      Notes to Financial Statements

8.   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.  Basic
changes in past reserve estimates occur  annually. As  new data is
gathered during the subsequent year, the engineer must revise  his
earlier estimates.  A year of new information,  which  is pertinent  to
the  estimation  of future  recoverable  volumes,      is
     available during the subsequent year evaluation.  In applying
     industry standards  and  procedures,  the  new
data  may  cause  the  previous estimates  to be revised.             This
revision may increase or decrease  the
     earlier estimated volumes.  Pertinent information gathered
during  the year  may include actual production and
     decline rates, production from offset  wells
     drilled  to the same geologic formation,
     increased  or
     decreased  water production, workovers, and
     changes in lifting  costs, among others.
     Accordingly, reserve estimates are often
     different from the quantities of oil and gas
     that are ultimately recovered.
     The Partnership has reserves, which are
     classified as proved developed and  proved
     undeveloped.  All of the proved reserves are
     included  in the  engineering reports,  which
     evaluate the  Partnership's  present reserves.
     Because  the  Partnership does not engage in
     drilling activities,  the development  of
     proved undeveloped
reserves in conducted  pursuant  to farm-out
arrangements with the Managing General Partner or
unrelated third parties.  Generally, the
Partnership retains a carried interest such as an
overriding royalty interest under the terms of a
farm-out.
     The  standardized measure of discounted future
     net cash flows relating to  proved oil and gas
     reserves at December 31, 2002, 2001 and 2000
     is presented below:
                                   2002      2001      2000
                                  -----     -----     -----

Future cash inflows           $  3,207,00
2,419,00  5,321,00
                                 0         0         0
Production  and  development     1,673,00
1,379,00  2,497,00
costs                            0         0         0
                                 --------  ------
                                 --  -----------     ---- ----
Future net cash flows            1,534,00
1,040,00  2,824,00
                                 0         0         0
10%   annual  discount   for
estimated
timing of cash flows            667,000   461,000
                    1,262,00
                                                     0 ------
                                 --  ------------------   ---
                                 - ----
Standardized   measure    of
discounted
future net cash flows        $  867,000   579,000
                    1,562,00
                                                     0
                                 ======= ======= =======

<PAGE>
            Southwest Oil & Gas Income Fund X-
A, L.P.
               (a Delaware limited partnership)

                 Notes to Financial Statements

8.   Estimated Oil and Gas Reserves (unaudited) -
continued
     The  principal  sources  of  change in  the
standardized
     measure  of discounted  future  net cash
     flows for the years  ended  December  31,
     2002, 2001 and 2000 are as follows:

                                   2002
2001   2000
                                  -----     ---
--   -----
Sales   of   oil   and   gas
produced,
    net of production costs      $  (62,000)
               (105,000  (216,000
                                           )         )
Changes   in   prices    and     465,000
(877,000  624,000
production costs                           )
Changes of production rates
    (timing) and others
(11,000)
               (99,000)
(74,000) Revisions of
previous
    quantities estimates
          (162,000
(58,000)  213,000
                                 ) Accretion of
discount  58,000
156,000  92,000
Discounted future net
 cash flows -
Beginning of year                579,000
1,562,00  923,000
                                           0
                                 --------  ------
                                 --  -----------
---- ----
End of year                   $  867,000   579,000   1,562,00
                                                     0
                                 =======   =======   =======

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

<PAGE>
                Southwest Oil & Gas Income Fund X-
A, L.P.
         (a Delaware limited partnership)

           Notes to Financial Statements

9.   December 31, 2002 Restatement
     During  2002,  the  Partnership changed its
     method  of providing  for depletion  from the
     units-of-revenue method to the units-of-
     production method as described in Note 3.

     Subsequent to the issuance of the
     Partnership's Annual Report on  Form 10-K  for
     the year ended December 31, 2002, the
     Partnership determined that the above change
     in accounting method should have been adopted
     by the Partnership  as  a  cumulative effect
     of a change  in accounting principle.  The
     Partnership had previously applied the change
     in  the method of providing for depletion
     prospectively as of October 1, 2002.

     This  change in the method used to implement
     the Partnership's  change in  the manner in
     which it determines depletion resulted in a
     decrease in the Partnership's previously
     reported net oil and gas properties of $3,000
     from $112,531to $109,531 as of December 31,
     2002 and  did  not effect the Partnership's
     2002 cash flows from operations, investing or
     financing activities.

     The  change  had the following effects on the
     Statement of Operations for the year ended
     December 31, 2002.  (Periods prior to 2002
     were not affected by the change).

                                        Restated
Previously
                                                       Reported
     Depreciation, depletion and      $10,000        10,000
     amortization
     Income (loss) before cumulative  (27,700)       (27,700)
     effect
   Cumulative effect of change in     (3,000)        -
     accounting principle
     Net income (loss)                (30,700)       (27,700)
     Net income (loss) allocated
     to:
     Managing General Partner         (1,593)        (1,593)
     General partner                  (177)          (177)
     Limited partners                 (28,930)       (25,930)
       Income (loss) per limited
     partner unit before
         cumulative effect            (2.47)         (2.47)
       Cumulative effect per          (.29)          -
     limited partner unit
       Net income (loss) per          (2.76)         (2.47)
     limited partner unit

<PAGE>
                Southwest Oil &
                     Gas Income
                     Fund X-A,
                     L.P. (a
                     Delaware
                     limited
                     partnershi
                     p)
                      Notes to
Financial Statements
10.  Selected Quarterly
Financial Results -
(unaudited)
  As  discussed  in Note 3, in 2002 the Partnership
                       changed
     methods  of accounting  for  depletion  of
     capitalized costs  from  the  units-ofrevenue
     method to the units-ofproduction method.  The
     2002 quarterly financial  results presented
     below have been restated to  reflect  the
     change in depletion method effective as of
     January 1, 2002.  See Notes 3 and 9 for a
     detailed discussion of the change in depletion
     method.
                                             Quarter
                              ----------------------
                              ----------------------
                              ----------------------
                              -------
                                                -
                               First     Second
Third
Fourth
                               ------   --------  --
----
- --------
                                          ---
-
2002:
 Total revenues             $ 68,977    91,715
72,618    78,840
    Total   expenses    as    82,258    75,773
99,671    82,148
originally reported
                              --------  --------  ----
--
                              --  -----------   ----
---- ----
   Net  income  (loss)  as    (13,281)  15,942
(27,053)  (3,308)
originally reported
   Income  (loss)   before
cumulative effect of
   a  change in accounting    (13,281)  15,942
(27,053)  (3,308)
principle
   Cumulative  effect   on
prior years (to
   December 31,  2001)  of
changing to a
     different   depletion    (3,000)   -         -         -
method
                              --------  --------  ------
                              --  -----------   ----
---- ----
   Net  income  (loss)  as  $ (16,281)  15,942
(27,053)  (3,308)
restated
                              =======   =======
=======         =======
  Per limited partner unit
amounts:
     Net   income   (loss)  $ (1.16)
originally reported                     1.34      (2.34)    (.31)
    Effect  of  change  in         -         -         -         -
depletion method
                              --------  --------  ------
                              --  -----------   ----
---- ----
   Income  (loss)   before
cumulative effect of a
    change  in  accounting    (1.16)
principle                               1.34      (2.34)    (.31)
   Cumulative  effect   on
prior years (to
   December 31,  2001)  of
changing to a
     different   depletion     (.29)         -         -         -
method
                              --------  --------  ------
                              --  -----------   ----
---- ---Net   income   (loss)   as  $ (1.45)
restated                                1.34
(2.34)          (.31)
                              =======   =======
=======         =======

 2001:
  Total revenues               $ 117,399   98,942
                      72,974
57,615
  Total expenses                 94,065    75,746
                      84,358
83,834
 Net income (loss)              23,334    23,196
(11,384)  (26,219)
 Net   income   (loss)   per
 limited
   partners unit                  1.97
                                          1.97
(1.02) (2.27)


tem 9.    Changes  in and Disagreements With
Accountants on
Accounting  and
          Financial Disclosure
None
<PAGE>
                     Part III

Item 10.  Directors and Executive Officers of the
Registrant

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

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

(1)  Member of the Compensation Committee

(2)  Member of the Audit Committee

H.  H.  Wommack, III has served as Chairman of the Board,
President,  Chief Executive Officer and a director since
Southwest's founding in 1983.  Since 1997  Mr.  Wommack  has
served as President, Chief Executive  Officer  and Chairman of
SRH, Southwest's former parent and current holder of 10% of its
voting  share capital.  SRH holds an equity investment in
Southwest and  in Basic  Energy Services.  Since 1997 Mr.
Wommack has served as  chairman  of the  board  of directors of
Midland Red Oak Realty, Inc.  Midland  Red  Oak Realty  owns
and  manages  commercial real  estate  properties,  including
shopping centers and office buildings, in secondary real estate
markets  in the Southwestern United States.  From 1997 until
December 2000, Mr. Wommack served as chairman of the board of
directors of Basic Energy Services, Inc. and  since  December
2000  has continued to  serve  on  Basic's  board  of
directors.  Basic provides certain well services for oil and
gas companies. Prior to Southwest's formation, Mr. Wommack was
a self-employed independent oil  and  gas  producer engaged in
the purchase and  sale  of  royalty  and working  interests in
oil and gas leases and the drilling  of  wells.   Mr.
Wommack graduated from the University of North Carolina at
Chapel Hill  and received his law degree from the University of
Texas.
James N. Chapman has served as a director since April 19,2002.
Mr. Chapman has  been involved in the investment banking
industry for 18 years.
Since
January  2002  he  has  acted as a capital markets and
strategic  planning consultant  with private and
public companies across a range of industries,
including  metals, mining, manufacturing,
aerospace, airline,  service  and healthcare.
Prior to establishing an independent consulting
practice, from 1997  to 2002 Mr. Chapman worked for
The Renco Group, Inc., a multi-billion private
corporation  in  New York, for which  Mr.  Chapman
developed  and implemented financing and merger and
acquisitions strategies  for  Renco's diverse
portfolio  of companies.  From 1990 to 1997,  Mr.
Chapman  was  a founding  principal of Fieldstone
Private Capital Group, a capital  markets advisory
firm.   From 1985 to 1990, Mr. Chapman worked for
Bankers  Trust Company,  most recently in the BT
Securities Capital  Markets  area.   Mr. Chapman
received an MBA degree with distinction from the
Amos Tuck  School at  Dartmouth College and was
elected an Edward Tuck Scholar.  He  received his
BA degree with distinction magna cum laude, at
Dartmouth College,  was elected to Phi Beta Kappa
and was a Rufus Choate Scholar.

William  P. Nicoletti has served as a director
since April 19, 2002.   Mr. Nicoletti  is Managing
Director of Nicoletti & Company Inc., an
investment banking  and financial advisory firm he
founded in 1991.  He was previously a  senior
officer and head of the Energy Investment Banking
Groups of E. F. Hutton  &  Company Inc. and Paine
Webber, Incorporated.   From March  1998 until June
1990 he was a managing director and cohead of
Energy Investment Banking  at  McDonald Investments
Inc.  Mr. Nicoletti has been Chairman  of the
board  of directors of Russell-Stanley Holdings,
Inc., a manufacturer and marketer  of  steel and
plastic industrial containers  since November 2001.
He  is  a  director of Mark WestEnergy
Partners, L.P.,  a  business engaged
in  the  gathering and  processing  of  natural  gas   and   the
fractionation and storage of natural gas liquids.  Mr.
Nicoletti is also  a Director  and  Chairman of the Audit
Committee of Star Gas Partners,  L.P., the  nation's largest
retail distributor of home heating oil  and  a  major retail
distributor of propane gas.  Mr. Nicoletti is a graduate  of
Seton Hall  University  and  received  an  MBA degree  from
Columbia  University Graduate School of Business.

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

Richard  D.  Rinehart has served as a director
since April 19, 2002.   Mr. Rinehart is a founding
principal of PetroCap, Inc. and president of
Kestrel Resources,  Inc.   PetroCap, Inc. provides
investment and merchant  banking services  to  a
variety  of clients active in the oil  and  gas
industry. Kestrel Resources, Inc. is a privately
owned oil and gas operating company. He  served  as
Director of Coopers & Lybrand's Energy Systems and
Services Division prior to the founding of Kestrel
Resources, Inc. in 1992. Prior to joining Coopers &
Lybrand, he was chief executive officer/founder of
Dawn Information  Resources,  Inc., formed in 1986
and
acquired  by  Coopers  & Lybrand  in  early  1991.
Mr. Rinehart served as CEO  of  Terrapet  Energy
Corporation during the period 1982 through 1986.
Prior to the formation  of Terrapet in 1982, he was
employed as President of the Terrapet Division  of
E.I.  DuPont de Nemours and Company. Before its
acquisition by  DuPont,  he served  as  CEO and
President of Terrapet Corp., a privately owned  E
&  P company. Before the formation of Terrapet
Corp. in 1972, he was manager  of supplementary
recovery methods and senior evaluation engineer
with  H.  J. Gruy and Associates, Inc., Dallas,
Texas.
John  M. White has served as a director since April
19, 2002, Mr. White  is currently  an  oil and gas
analyst with BMO Nesbitt Burns, responsible  for
Fixed  Income research on oil, gas and energy
companies.  Prior to  joining BMO  Nesbitt Burns
in 1998, Mr. White was responsible  for  Fixed
Income research  on  the  oil  and  gas  industry
at  John  S. Herold,  Inc.,  an independent  oil
and gas research and
consulting firm, beginning  in  July 1996.  Mr.
White's experience also includes managing a
portfolio of oil and gas loans  for  The  Bank  of
Nova  Scotia,  which  included independent
exploration and production companies, oil service
companies, gas pipelines, gas  processors and
refiners from 1990 until July 1996.  From 1983 to
1990, Mr. White was with BP Exploration, where he
worked primarily in exploration and production.
Herbert  C. Williamson, III has served as a
director since April 19,  2002. At  present, Mr.
Williamson is self-employed as a consultant.   From
March 2001  to  March  2002  Mr. Williamson served
as an investment  banker  with Petrie
Parkman & Co.  From April 1999 to March 2001 Mr.
Williamson served as chief financial officer and
from August 1999 to March 2001 as a director of
Merlon  Petroleum  Company, a private oil and gas
company  involved  in exploration  and production
in Egypt.  Mr. Williamson served  as  executive
vice
president,  chief  financial  officer  and
director  of  Seven Seas Petroleum,  Inc., a
publicly traded oil and gas exploration  company,
from March  1998  to  April 1999.  From 1995
through April 1998,  he  served  as director  in
the Investment Banking Department  of  Credit
Suisse  First Boston.   Mr.  Williamson  served  as
vice  chairman  and executive  vice
president  of Parker and Parsley Petroleum Company,
a publicly traded  oil and  gas  exploration
company (now Pioneer Natural Resources Company)
from 1985 through 1995.

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

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

<PAGE>
Key Employees

Jon  P.  Tate,  age  45, has served as Vice
President, Land
and  Assistant Secretary  of the Managing General
Partner since 1989. From 1981  to  1989, Mr.  Tate
was employed by C.F. Lawrence & Associates, Inc.,
an independent oil  and  gas company, as land
manager. Mr. Tate is a member of the Permian Basin
Landman's Association.
R.  Douglas  Keathley, age 47, has served as Vice
President, Operations  of the  Managing  General
Partner since 1992. Before joining us, Mr.
Keathley worked  as a senior drilling engineer for
ARCO Oil and Gas Company  and  in similar
capacities for Reading & Bates Petroleum Co. and
Tenneco Oil Co.
In certain instances, the Managing General Partner
will engage professional petroleum   consultants
and  other  independent contractors,
including
engineers   and   geologists  in  connection  with
property acquisitions, geological  and  geophysical
analysis,  and
reservoir  engineering. The
Managing  General Partner believes that, in
addition to its own "in-house" staff,  the
utilization of such consultants and independent
contractors  in specific  instances  and  on  an
"as-needed"  basis  allows  for   greater
flexibility  and greater opportunity to perform its
oil and gas  activities more economically and
effectively.

Item 11.  Executive Compensation

The  Partnership  does  not  employ any directors,
executive officers  or employees.  The Managing
General Partner receives an administrative fee for
the  management of the Partnership. The Managing
General Partners received $78,000  during 2002,
2001 and 2000 as an annual administrative  fee.
The
executive officers of the Managing General Partner
do not receive any  form of  compensation, from the
Partnership; instead, their compensation is paid
solely  by  Southwest.  The executive officers,
however,  may  occasionally perform administrative
duties for the Partnership but receive no
additional compensation for this work.

Item 12.  Security Ownership of Certain Beneficial
Owners and Management

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

The  Managing  General Partner owns a nine percent
interest  as a  general partner.   Through prior
purchases, the Managing General Partner also  owns
171.0  limited  partner  units, or a 1.5% limited
partner  interest.      The
Managing  General  Partner  total  percentage
interest ownership  in  the Partnership is 10.5%.

No  officer or director of the Managing General
Partner owns Units  in  the Partnership.  H. H.
Wommack, III, as the individual general partner
of  the Partnership,  owns  a  one percent
interest as  a  general  partner.
The
officers  and  directors  of the Managing General
Partner  are considered beneficial  owners of the
limited partner units acquired  by  the  Managing
General Partner by virtue of their status as such.
Beneficial ownership  is determined  in accordance with
the rules of the  Securities  and  Exchange Commission
and  includes voting or investment power with respect
to  the limited partner units.  To our knowledge,
except under applicable community property  laws or as
otherwise indicated, the persons named  in  the  table
have sole  voting and sole investment control with
regard to  all limited partner  units beneficially
owned.  We are presenting ownership information as  of
March 1, 2003. A list of beneficial owners of limited
partner units, acquired by the Managing General
Partner, is as follows:

<PAGE>

                                                 Amount
                                                 and
                                                                  N
                                                                  a
                                                                  t
                                                                  u
                                                                  r
                                                                  e
                                                                  o
                                                                  f
                                                                  P
                                                                  e
                                                                  r
                                                                  c
                                                                  e
                                                                  n
                                                                  t
                  Name and Address of
Beneficial  of
  Title of Class         Beneficial Owner
Ownership
Class
-------------------    ---------------------     --------
-
-     ------
  --------------          --------------           ------
-----
Limited Partnership    Southwest  Royalties,     Directly
1.5%
Interest               Inc.                      Owns
                       Managing      General     171.0
                       Partner
Units
                       407   N.  Big  Spring
                      Street
                       Midland, TX 79701
Limited Partnership    H. H. Wommack, III
Indirectly      1.5%
Interest
Owns
                       Chairman    of    the
171.0
                       Board,
Units
                       President, and CEO
                       of          Southwest
                       Royalties, Inc.,
                       the  Managing General
                      Partner
                       407   N.  Big  Spring
                      Street
                       Midland, TX 79701


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

Item 13.  Certain Relationships and Related
Transactions
In 2002, the Managing General Partner received
$78,000 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 $40,700 for administrative  overhead
attributable to operating such properties during
2002.

Certain  subsidiaries or affiliates of the Managing
General Partner perform various  oilfield services
for properties in which the Partnership owns  an
interest.   Such  services aggregated approximately
$20,500  for  the  year ended December 31,    2002.
The  terms of the above transactions are similar to
ones, which would  have been  obtained  through
arm's length negotiations with  unaffiliated  third
parties.
Item 14.  Controls and Procedures
(a)  Evaluation of Disclosure Controls and
Procedures.  The chief executive officer  and
chief financial officer of the Partnership's
managing  general partner have evaluated the
effectiveness of the design and operation of the
Partnership's disclosure controls and procedures
(as defined  in  Exchange Act  Rule 13a-14(c)) as
of a date within 90 days of the filing date of
this annual  report. Based on that evaluation, the
chief executive  officer  and chief  financial
officer have concluded that the Partnership's
disclosure controls  and procedures are effective
to ensure that material  information
relating to the Partnership is made known to such
officers by others within these  entities,
particularly during the period this  annual  report
was prepared, in order to allow timely
decisions regarding required disclosure.
(b)  Changes  in  Internal Controls.  There have not
been  any
significant changes  in  the Partnership's internal
controls or in other  factors  that could
significantly affect these controls subsequent to
the date of  their evaluation.
<PAGE>
                       Part IV
Item 15.  Exhibits, Financial Statement Schedules
and Reports

      on Form 8-K (a)(1)  Financial Statements:

        Included in Part II of this report --

             Independent Auditors Report
                  Balance Sheets
              Statements of Operations
                  Statement of Changes in Partners'
                  Equity Statements of Cash Flows
            Notes to Financial Statements

                     (2)  Schedules required by
                  Article 12 of Regulation SX  are
                  either omitted because they are
                  not applicable  or because  the
                  required  information  is  shown
                  in   the financial statements or
                  the notes thereto.
             (3)  Exhibits:
                                      4      (a)
Certificate
of  Limited
                          Partnership of Southwest
                          Oil & Gas Income Fund XA,
                          L.P.,  dated January 29,
                          1990.  (Incorporated by
                          reference from
                          Partnership's Form 10-K
                          for the fiscal year ended
                          December 31, 1990.)

                                            (b)
Agreement
                          of   Limited Partnership
                          of Southwest Oil & Gas
                          Income Fund XA, L.P. dated
                          January 29, 1990.
                          (Incorporated by
reference  from Partnership's Form 10K  for  the
fiscal year ended
                          December 31, 1990.)

                  18.1 Letter re Change in
Accounting Principles

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

          (b)     Reports on Form 8-K

                  There  were  no  reports filed on
              Form  8-K during  the quarter ended
              December 31, 2002.

<PAGE>
                     Signatures


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


                          Southwest Oil & Gas Income
                          Fund X-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:  November 10, 2003

<PAGE>

                             POWER OF ATTORNEY

KNOW  ALL  MEN BY THESE PRESENTS, that each person
whose signature  appears below hereby constitutes
and appoints H.H. Wommack, III and Bill E. Coggin,
and each of them severally, his true and lawful
attorney-in-fact and agent, with  full power of
substitution and resubstitution, for him  and  in
his name,  place  and  stead, in any and all
capacities, to sign any  and  all amendment to this
Report, and to file the same, with all exhibits
thereto, and  other  documents  in connection
therewith, with  the  Securities  and Exchange
Commission, granting unto said attorney-in-fact  and
agent full power  and  authority  to  do and perform
each  and  every act  and  thing requisite and
necessary to be done as fully to all intents and
purposes  as he  might  or could do in person,
hereby ratifying and confirming that  all that said
attorney-infact and agent, or his substitute or
substitutes, may lawfully do or cause to be done by
virtue hereof.


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


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.

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

Date:     November 6, 2003                   Date:
November   6,
                                             2003


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

Date:     November 10, 2003                  Date:
November   6,
                                             2003
/s/ Richard D. Rinehart                      /s/
Joseph
J.  Radecki,
                                             Jr. ------
--------------------                       ------------
--
----------
--------------------                         ----------
--
-----------
Richard     D.    Rinehart,                  Joseph J.
Radecki,  Jr.,
Director                                     Director

Date:     November 7, 2003                   Date:
November   4,
                                             2003


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

Date:     November 7, 2003                   Date:
<PAGE>
                    CERTIFICATIONS

     I, H.H. Wommack, III, certify that:
     1.   I have reviewed this annual report on Form 10-
K/A of
Southwest Oil &
Gas Income Fund X-A, L.P.;

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

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

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

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

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

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

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

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

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

 6.   The registrant's other certifying officers and I have
indicated in
this annual report whether or not there were significant
changes in internal
controls or
in other
factors that
could
significantl
y affect
internal
controls
subsequent
to the date
of our most recent evaluation, including any
corrective actions with regard to significant
deficiencies and material weaknesses. Date: November
10,
2003
/s/ H.H.
Wommack, III
H. H. Wommack, III
Chairman, President, Director and Chief Executive
Officer
  of Southwest Royalties, Inc., the
  Managing General Partner of
  Southwest Oil & Gas Income Fund X-A, L.P.

<PAGE>
                   CERTIFICATIONS

     I, Bill E. Coggin, certify that:
     1.   I have reviewed this annual report on Form
10-K/A of
Southwest Oil &
Gas Income Fund X-A, L.P.;

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

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

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

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

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

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

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

          a)   all significant deficiencies in the design or
operation
    of internal controls which could adversely affect the
          registrant's ability to record, process,
          summarize and report financial data and have
          identified for the registrant's auditors any
          material weaknesses in internal controls; and
          b)   any fraud, whether or not material, that
          involves management or other employees who have a
          significant role in the registrant's internal
          controls; and
     6.   The registrant's other certifying officers and I
have indicated in this annual report whether or not there
were significant changes in
internal controls or in other factors that could
significantly affect internal controls subsequent
to the
date of our most recent evaluation, including any
corrective actions with regard to significant
deficiencies and material weaknesses.


Date:  November 10, 2003




/s/ Bill E. Coggin
Bill E. Coggin
Executive Vice President
  and Chief Financial Officer of
          Southwest Royalties, Inc., the
  Managing General Partner of
Southwest Oil & Gas Income Fund X-A, L.P.
<PAGE>
                   Exhibit Index


Item No.     Description
Page No.
               Exhibit  18.1  Letter  re  Change
in
Accounting  Principle 48
             Exhibit 99.1 Certification pursuant to
             18 U.S.C. 49 Section 1350, as adopted
             pursuant to Section 906
         of the Sarbanes-Oxley Act of 2002

             Exhibit 99.2 Certification pursuant to
             18 U.S.C. 50 Section 1350, as adopted
             pursuant to Section 906
         of the Sarbanes-Oxley Act of 2002

<PAGE>

EXHIBIT 18.1
June 4, 2003

Southwest Royalties, Inc. (As Managing General
Partner of the Partnerships)

Midland, Texas


Ladies and Gentlemen:

We  have audited the balance sheets of the
Southwest Royalties, Inc. public partnerships (see
attached listing) (the "Partnerships") as of
December 31, 2002  and  2001,  and the
related statements of operations,  statements  of
changes  in partners' equity, and cash flows for
each of the years  in  the three-year period ended
December 31, 2002, and have reported thereon  under
date  of  March 14, 2003.  The aforementioned
financial statements and  our audit  report  thereon
are included in each of the individual Partnership's
annual reports on Form 10-K/A for the year ended
December 31, 2002.
As stated in Note 2 to those financial statements,
the Partnerships changed their  method of accounting
for amortization of capitalized costs from  the
units-of-revenue method to the units-of-production
method,  and  that  the newly adopted  accounting
principle is preferable  in  the circumstances
because the units-of-production method results in a
better matching of  the
costs  of  oil and gas production against the
related revenue
received  in
periods  of  volatile  prices for production as have
been experienced  in recent  periods.
Additionally,  the  units-ofproduction  method  is
the predominant method used by full
cost companies in the oil and gas industry,
accordingly,  the change improves the comparability
of  the  Partnerships' financial statements with
its peer group.  In accordance with your request,
we have reviewed and discussed with Partnership
officials the circumstances and  business  judgment
and planning upon which the decision to  make  this
change in the method of accounting was based.

With regard to the aforementioned accounting
change, authoritative criteria have  not  been
established  for evaluating  the  preferability  of
one acceptable  method of accounting over another
acceptable method.   However, for purposes of the
Partnership's compliance with the requirements of
the Securities and Exchange Commission, we are
furnishing this letter.

Based  on our review and discussion, with reliance
on
management's business
judgment  and  planning,  we  concur  that  the
newly  adopted method  of accounting is preferable
in the Partnerships' circumstances.

Very truly yours,

KPMG LLP


<PAGE>

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


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

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

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


Date:  November 10, 2003
/s/ H.H. Wommack, III
H. H. Wommack, III
Chairman, President, Director and
  Chief Executive Officer of
  Southwest Royalties, Inc., the
  Managing General Partner of
Southwest Oil & Gas Income Fund X-A,
                L.P.

<PAGE>

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


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

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

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


Date: November 10, 2003




/s/ Bill E. Coggin
Bill E. Coggin
Executive Vice President
  and Chief Financial Officer of
Southwest Royalties, Inc., the
 Managing General
    Partner of
Southwest Oil & Gas
Income Fund X-A,
L.P.

<PAGE>