25 of 25
                                FORM 10-Q


                    SECURITIES AND EXCHANGE COMMISSION
                         WASHINGTON, D.C.  20549

(MARK ONE)

(X)  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
     OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2003

                                    OR

(  ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
     OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ________________ to ________________

Commission File Number 33-47667-01

                SOUTHWEST OIL & GAS 1992-93 INCOME PROGRAM
                Southwest Oil & Gas Income Fund XI-A, L.P.
                  (Exact name of registrant as specified
                  in its limited partnership agreement)

Delaware                                                  75-2427267
(State or other jurisdiction of                       (I.R.S. Employer
incorporation or organization)                        Identification No.)


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

                             (432) 686-9927
                     (Registrant's telephone number,
                           including area code)

Indicate  by  check  mark  whether registrant (1)  has  filed  all  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 whether the registrant is an accelerated filer  (as
defined in Rule 12b-2 of the Exchange Act).

                                  Yes        No   X


        The total number of pages contained in this report is 25.

<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 the leasehold
or  working  interest  agrees to assign his interest  in  certain  specific
acreage  to  the assignee, retaining some interest, such as  an  overriding
royalty interest, subject to the drilling of one (1) or more wells or other
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.

<PAGE>
     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%.

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

     Proved properties. Properties with proved reserves.

     Proved  reserves. The estimated quantities of crude oil, natural  gas,
and  natural  gas liquids that geological and engineering data  demonstrate
with  reasonable  certainty to be recoverable in future  years  from  known
reservoirs under existing economic and operating conditions.

     Proved  undeveloped reserves. Proved undeveloped oil and gas  reserves
are  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. - FINANCIAL INFORMATION


Item 1. Financial Statements

The  unaudited  condensed financial statements included  herein  have  been
prepared  by  the Registrant (herein also referred to as the "Partnership")
in  accordance  with generally accepted accounting principles  for  interim
financial information and with the instructions to Form 10-Q and Rule 10-01
of Regulation S-X.  Accordingly, they do not include all of the information
and  footnotes  required  by generally accepted accounting  principles  for
annual financial statements.  In the opinion of management, all adjustments
necessary  for a fair presentation have been included and are of  a  normal
recurring  nature.  The financial statements should be read in  conjunction
with  the  audited financial statements and the notes thereto for the  year
ended December 31, 2002, which are found in the Registrant's Amendment  No.
1  to its Annual Report on Form 10-K for 2002 filed with the Securities and
Exchange  Commission on November 12, 2003.  The December 31,  2002  balance
sheet included herein has been derived from the Registrant's Amendment  No.
1  to  its Annual Report on Form 10-K for 2002.  Operating results for  the
three  and  six  month  periods ended June 30,  2003  are  not  necessarily
indicative of the results for the full year.

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

Introductory Note - Depletion Method
During  the fourth quarter of 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 Notes 4 and  5  to  the  Partnership's
financial statements.

This  change  in depletion method was applied as a cumulative effect  of  a
change  in  accounting  principle effective as of  January  1,  2002.   The
unaudited condensed financial statements of the Partnership for the periods
ended  June 30, 2002, included herein, have been restated (as described  in
Notes  4  and  5 to the Partnership's financial statements) using  the  new
depletion   method  and  differ  from  those  previously  issued   in   the
Partnership's Quarterly Report on Form 10-Q for the periods ended June  30,
2002.


<PAGE>
                Southwest Oil & Gas Income Fund XI-A, L.P.
                              Balance Sheets

                                 June 30,  December
                                             31,
                                   2003      2002
                                   ----      ----
                                 (unaudit
                                   ed)
Assets
---------
Current assets:
 Cash and cash equivalents    $  30,953    17,179
  Receivable  from  Managing     18,238    24,291
General Partner
                                 --------  --------
                                 -----     -----
   Total current assets          49,191    41,470
                                 --------  --------
                                 -----     -----
Oil  and  gas  properties  -
using the full-
 cost method of accounting       1,087,18  1,053,59
                                 8         6
       Less      accumulated
depreciation,
         depletion       and     824,236   838,555
amortization
                                 --------  --------
                                 -----     -----
      Net   oil   and    gas     262,952   215,041
properties
                                 --------  --------
                                 -----     -----
                              $  312,143   256,511
                                 =======   =======

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

Current liability:
 Distribution payable         $  -         46
                                 --------  --------
                                 -----     -----
Other long term liabilities      66,183    -
                                 --------  --------
                                 -----     -----

Partners' equity:
 General partners                (4,088)   (4,038)
 Limited partners                250,048   260,503
                                 --------  --------
                                 -----     -----
   Total partners' equity        245,960   256,465
                                 --------  --------
                                 -----     -----
                              $  312,143   256,511
                                 =======   =======

<PAGE>
                Southwest Oil & Gas Income Fund XI-A, L.P.
                         Statements of Operations
                               (unaudited)

                                   Three Months Ended   Six Months Ended
                                        June 30,            June 30,
                                     2003      2002      2003      2002
                                             (Restate            (Restate
                                                d)                  d)
                                    -----     -----     -----     -----
Revenues
--------
Oil and gas                     $  54,098    47,262    116,490   80,296
Interest                           45        27        72        51
Miscellaneous settlement           -         1,236     6         1,236
                                   --------  --------  --------  --------
                                   --        --        --        --
                                   54,143    48,525    116,568   81,583
                                   --------  --------  --------  --------
                                   --        --        --        --
Expenses
--------
Production                         23,923    24,614    50,635    38,853
General and administrative         11,346    4,293     15,666    8,489
Depreciation,  depletion   and     5,000     6,000     10,000    12,000
amortization
Accretion  of asset retirement     1,273     -         2,547     -
obligation
                                   --------  --------  --------  --------
                                   --        --        --        --
                                   41,542    34,907    78,848    59,342
                                   --------  --------  --------  --------
                                   --        --        --        --
Net  income  before cumulative     12,601    13,618    37,720    22,241
effects

Cumulative effect of change in
accounting
  principle - SFAS No.  143  -     -         -         (5,725)   -
See Note 3
Cumulative effect of change in
accounting principle
  - change in depletion method     -         -         -         1,000
- See Note4
                                   --------  --------  --------  --------
                                   --        --        --        --
Net income                      $  12,601    13,618    31,995    23,241
                                   ======    ======    ======    ======
Net income allocated to:
 Managing General Partner       $  1,584     1,766     3,780     3,082
                                   ======    ======    ======    ======
 General Partner                $  176       196       420       342
                                   ======    ======    ======    ======
 Limited partners               $  10,841    11,656    27,795    19,817
                                   ======    ======    ======    ======
   Per  limited  partner  unit  $     3.84
before cumulative effect                     4.13      11.68     6.67
    Cumulative   effects   per     -         -          (1.83)        .35
limited partner unit
                                   --------  --------  --------  --------
                                   --        --        --        --
  Per limited partner unit      $     3.84
                                             4.13      9.85      7.02
                                   ======    ======    ======    ======
Pro   forma  amounts  assuming
changes are applied
 retroactively (See Note 3):
  Net income before cumulative  $  -         12,445    -         19,897
effect
                                   ======    ======    ======    ======
   Per  limited  partner  unit  $  -                   -
(2,821.0)                                    3.76                5.92
                                   ======    ======    ======    ======
 Net income                     $  -         12,445    -         20,897
                                   ======    ======    ======    ======
   Per  limited  partner  unit  $  -                   -
(2,821.0)                                    3.76                6.27
                                   ======    ======    ======    ======
<PAGE>
                Southwest Oil & Gas Income Fund XI-A, L.P.
                         Statements of Cash Flows
                               (unaudited)

                                       Six Months Ended
                                           June 30,
                                        2003      2002
                                                (Restate
                                                   d)
                                       -----     -----
Cash    flows   from    operating
activities:
  Cash received from oil and  gas  $  111,537   73,890
sales
 Cash paid to suppliers               (55,295)  (62,597)
 Interest received                    72        51
 Miscellaneous settlement             6         1,236
                                      --------  --------
                                      ---       ---
   Net cash provided by operating     56,320    12,580
activities
                                      --------  --------
                                      ---       ---
Cash    flows   from    investing
activities:
 Sale of oil and gas properties       -         722
                                      --------  --------
                                      ---       ---
Cash   flows  used  in  financing
activities:
 Distributions to partners            (42,546)  (15,000)
                                      --------  --------
                                      ---       ---
Net  increase (decrease) in  cash     13,774    (1,698)
and cash equivalents

Beginning of period                   17,179    13,139
                                      --------  --------
                                      ---       ---
End of period                      $  30,953    11,441
                                      ======    ======
Reconciliation of net  income  to
net
cash    provided   by   operating
activities:

Net income                         $  31,995    23,241

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

Depreciation,    depletion    and     10,000    12,000
amortization
Accretion   of  asset  retirement     2,547     -
obligation
Cumulative  effect of  change  in
accounting
 principle - SFAS No. 143             5,725     -
Cumulative  effect of  change  in
accounting
  principle - change in depletion     -         (1,000)
method
Increase in receivables               (4,953)   (6,406)
Increase (decrease) in payables       11,006    (15,255)
                                      --------  --------
                                      ---       ---
Net  cash  provided by  operating  $  56,320    12,580
activities
                                      ======    ======
Noncash  investing and  financing
activities
   Increase   in  oil   and   gas
properties - Adoption
  of SFAS No. 143                  $  57,971    -
                                      ======    ======
      Decrease  in  oil  and  gas
properties - SFAS No. 143          $  60        -
         Sale of property             ======    ======

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

                      Notes to Financial Statements

1.   Organization
     Southwest  Oil  & Gas Income Fund XI-A, L.P. was organized  under  the
     laws  of  the  state of Delaware on May 5, 1992, 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 will sell  its  oil  and  gas
     production  to  a  variety of purchasers with the prices  it  receives
     being  dependent  upon the oil and gas economy.  Southwest  Royalties,
     Inc. serves as the Managing General Partner and H. H. Wommack, III, as
     the  individual general partner.  Partnership profits and  losses,  as
     well as all items of income, gain, loss, deduction, or credit, will be
     credited or charged as follows:

                              Limited   General
                              Partners  Partners
                                          (1)
                              --------  --------
Organization  and   offering  100%      -
expenses (2)
Acquisition costs             100%      -
Operating costs               90%       10%
Administrative costs (3)      90%       10%
Direct costs                  90%       10%
All other costs               90%       10%
Interest  income  earned  on
capital
 contributions                100%      -
Oil and gas revenues          90%       10%
Other revenues                90%       10%
Amortization                  100%      -
Depletion allowances          100%      -

          (1)   H.H.  Wommack,  III,  President  of  the  Managing  General
          Partner, is an additional general partner in the Partnership  and
          has  a  one percent interest in the Partnership.  Mr. Wommack  is
          the  majority  stockholder of the Managing General Partner  whose
          continued  involvement in Partnership management is important  to
          its  operations.  Mr. Wommack, as a general partner, shares  also
          in Partnership liabilities.

          (2)   Organization and Offering Expenses (including all  cost  of
          selling  and  organizing the offering) include a payment  by  the
          Partnership of an amount equal to three percent (3%)  of  Capital
          Contributions   for   reimbursement  of   such   expenses.    All
          Organization Costs (which excludes sales commissions and fees) in
          excess  of  three  percent  (3%) of  Capital  Contributions  with
          respect to the Partnership will be allocated to and paid  by  the
          Managing General Partner.

          (3)   Administrative  Costs will be paid from  the  Partnership's
          revenues;  however; Administrative Costs in the Partnership  year
          in  excess of two percent (2%) of Capital Contributions shall  be
          allocated to and paid by the Managing General Partner.

2.   Summary of Significant Accounting Policies
     The  interim  financial information as of June 30, 2003, and  for  the
     three  and  six  months  ended June 30, 2003, is  unaudited.   Certain
     information  and footnote disclosures normally included  in  financial
     statements  prepared in accordance with generally accepted  accounting
     principles  have been condensed or omitted in this Form 10-Q  pursuant
     to   the   rules  and  regulations  of  the  Securities  and  Exchange
     Commission.  However,  in  the opinion of  management,  these  interim
     financial  statements include all the necessary adjustments to  fairly
     present  the  results of the interim periods and all such  adjustments
     are  of a normal recurring nature.  The interim consolidated financial
     statements  should  be  read  in conjunction  with  the  Partnership's
     Amendment  No.  1 its Annual Report on Form 10-K for  the  year  ended
     December 31, 2002, filed with SEC on November 12, 2003.


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

                      Notes to Financial Statements

3.   Cumulative effect of change in accounting principle - SFAS No. 143
     On  January  1, 2003, the Partnership adopted Statement  of  Financial
     Accounting   Standards  No.  143,  Accounting  for  Asset   Retirement
     Obligations  ("SFAS No. 143").  Adoption of SFAS No. 143  is  required
     for  all  companies with fiscal years beginning after June  15,  2002.
     The new standard requires the Partnership to recognize a liability for
     the  present  value  of  all  legal obligations  associated  with  the
     retirement  of tangible long-lived assets and to capitalize  an  equal
     amount as a cost of the asset and depreciate the additional cost  over
     the  estimated  useful  life of the asset.  On January  1,  2003,  the
     Partnership    recorded   additional   costs,   net   of   accumulated
     depreciation,  of  approximately $57,971, a  long  term  liability  of
     approximately  $63,696  and  a loss of approximately  $5,725  for  the
     cumulative  effect  on  depreciation  of  the  additional  costs   and
     accretion  expense  on  the liability related to expected  abandonment
     costs  of  its oil and natural gas producing properties.  At June  30,
     2003, the asset retirement obligation was $66,183, and the increase in
     the  balance  from  January 1, 2003 is due  to  accretion  expense  of
     $2,547, offset slightly by the sale of an oil and gas property by $60.
     The  pro  forma  amounts for the three and six months ended  June  30,
     2002, which are presented on the face of the statements of operations,
     reflect the effect of retroactive application of SFAS No. 143.

4.    Cumulative  effect  of change in accounting  principle  -  change  in
depletion method
     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
     Partnership   adopted  the  units-of-production  method  through   the
     recording  of a cumulative effect of a change in accounting  principle
     in  the  amount  of  $1,000  effective as of  January  1,  2002.   The
     Partnership's  depletion for the three and six months ended  June  30,
     2003  and  2002  has  been  calculated using  the  units-of-production
     method.   The  effect of the change on the three and six months  ended
     June  30,  2002 was to increase and decrease income before  cumulative
     effect of a change in accounting principle by $1,000 and $1,000  ($.35
     and  $.35  per  limited partner unit), respectively and  increase  net
     income  by  $1,000  and $0 ($.35 and $.00 per limited  partner  unit),
     respectively.

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

                      Notes to Financial Statements

5.   June 30, 2002 Restatement
     During  the fourth quarter of 2002, the Partnership changed its method
     of  providing  for depletion from the units-of-revenue method  to  the
     units-of-production method as described in Note 4.

     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
     $1,000  from $216,041 to $215,041 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 three and six months ended June 30, 2002.

                           Three Months Ended      Six Months Ended
                                    Previousl               Previousl
                                        y                       y
                          Restated   Reported     Restated  Reported
  Depreciation,
  depletion and
  Amortization             $6,000   7,000         12,000    11,000
  Income before           13,618    12,618        22,241    23,241
  cumulative effect
Cumulative effect of
  change in
  accounting principle    -         -             1,000     -
  Net income              13,618    12,618        23,241    23,241
  Net income allocated
  to:
  Managing General        1,766     1,766         3,082     2,970
  Partner
  General partner         196       196           342       330
  Limited partners        11,656    10,656        19,817    19,941
   Income per limited
  partner
     unit before            4.13         3.78
  cumulative effect                               6.67      7.07
   Cumulative effect
  per limited
     partner unit              -         -                       -
                                                  .35
   Net income per
  limited
     partner unit           4.13         3.78
                                                  7.02      7.07

<PAGE>
Item 2.   Management's  Discussion and Analysis of Financial Condition  and
          Results of Operations

General

Southwest  Oil  & Gas Income Fund XI-A, L.P. was organized  as  a  Delaware
limited  partnership  on  May  5,  1992.   The  offering  of  such  limited
partnership  interests began August 20, 1992 as part of  a  shelf  offering
registered  under  the  name Southwest Oil & Gas  1992-93  Income  Program.
Minimum  capital  requirements for the Partnership were met  on  March  17,
1993,  with the offering of limited partnership interests concluding  April
30,  1993.   At  the  conclusion  of the offering  of  limited  partnership
interests, 122 limited partners had purchased 2,821 units for $1,410,500.

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 the net proceeds from operations to  the
limited  and  general partners.  Net revenues from producing  oil  and  gas
properties will not be reinvested in other revenue producing assets  except
to the extent that production facilities and wells are improved or reworked
or  where methods are employed to improve or enable more efficient recovery
of oil and gas reserves.

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, sales of properties, and 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 partners  is
therefore expected to fluctuate in later years based on these factors.

Based on current conditions, management anticipates performing no workovers
during  2003 to enhance production.  Additional workovers may be  performed
in  the  year  2004.   The Partnership may have an increase  in  production
volumes  for  the  year 2004, otherwise, the Partnership will  most  likely
experience the historical production decline, which has approximated 9% per
year.

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.

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.

Should the net capitalized costs exceed the estimated present value of  oil
and gas reserves, discounted at 10%, such excess costs would be charged  to
current  expense.  As of June 30, 2003, the net capitalized costs  did  not
exceed the estimated present value of oil and gas reserves.


<PAGE>
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  estimating  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  may  not be 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.

<PAGE>
Results of Operations

A.  General Comparison of the Quarters Ended June 30, 2003 and 2002

The  following  table  provides certain information  regarding  performance
factors for the quarters ended June 30, 2003 and 2002:

                                    Three Months
                                       Ended         Percenta
                                                        ge
                                      June 30,       Increase
                                   2003      2002    (Decreas
                                                        e)
                                   ----      ----    --------
                                                        --
Average price per barrel  of  $   26.38              9%
oil                                        24.12
Average price per mcf of gas  $    4.08              43%
                                           2.86
Oil production in barrels        1,000     1,000     -
Gas production in mcf            6,800     8,100     (16%)
Gross oil and gas revenue     $  54,098    47,262    14%
Net oil and gas revenue       $  30,175    22,648    33%
Partnership distributions     $  25,000    9,000     178%
Limited              partner  $  22,500    8,100     178%
distributions
Per  unit  distribution   to
limited
 partners                     $    7.98              178%
                                           2.87
Number  of  limited  partner     2,821     2,821
units

Revenues

The  Partnership's oil and gas revenues increased to $54,098  from  $47,262
for the quarters ended June 30, 2003 and 2002, respectively, an increase of
14%.   The principal factors affecting the comparison of the quarters ended
June 30, 2003 and 2002 are as follows:

1.  The  average  price  for a barrel of oil received  by  the  Partnership
    increased  during the quarter ended June 30, 2003 as  compared  to  the
    quarter ended June 30, 2002 by 9%, or $2.26 per barrel, resulting in an
    increase  of  approximately $2,300 in revenues.  Oil sales  represented
    49%  of total oil and gas sales during the quarter ended June 30,  2003
    as compared to 51% during the quarter ended June 30, 2002.

    The  average  price  for  an  mcf of gas received  by  the  Partnership
    increased during the same period by 43%, or $1.22 per mcf, resulting in
    an increase of approximately $8,300 in revenues.

    The  total  increase in revenues due to the change in  prices  received
    from oil and gas production is approximately $10,600.  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 remained the same during the quarter ended June 30, 2003
    as compared to the quarter ended June 30, 2002.

    Gas production decreased approximately 1,300 mcf or 16% during the same
    period, resulting in a decrease of approximately $3,700 in revenues.

    The  total  decrease  in revenues due to the change  in  production  is
    approximately  $3,700.  The decrease in gas production is  due  to  one
    lease  that experienced downtime during the end of 2002 and  is  slowly
    coming back up to normal.

Costs and Expenses

Total costs and expenses increased to $41,542 from $34,907 for the quarters
ended  June  30,  2003  and 2002, respectively, an increase  of  19%.   The
increase  is  the result of higher general and administrative  expense  and
accretion,  partially  offset  by a decrease depletion  expense  and  lease
operating costs.

1.  Lease   operating  costs  and  production  taxes  were  3%  lower,   or
    approximately  $700  less during the quarter ended  June  30,  2003  as
    compared to the quarter ended June 30, 2002.

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
    164% or approximately $7,100 during the quarter ended June 30, 2003  as
    compared  to the quarter ended June 30, 2002.  The increase in  general
    and  administrative  expense  is  due to  an  increase  in  independent
    accounting review and audit fees.

3.  Depletion  expense decreased to $5,000 for the quarter ended  June  30,
    2003  from  $6,000  for  the same period in 2002.   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 units-of-production
    method is the predominant method used by full cost companies in the oil
    and gas industry, accordingly, the change improves the comparability of
    the Partnership's financial statements with its peer group.  The effect
    of  this  change  in method was to decrease depletion expense  for  the
    three months ended June 30, 2002 by $1,000 and increase net income  for
    the  three  months  ended  June 30, 2002 by $1,000.   The  contributing
    factor  to the decrease in depletion expense is in relation to the  BOE
    depletion  rate  for the quarter ended June 30, 2003, which  was  $2.34
    applied to 2,133 BOE as compared to $2.55 applied to 2,350 BOE for  the
    same period.

<PAGE>
B.   General  Comparison of the Six Month Periods Ended June 30,  2003  and
2002

The  following  table  provides certain information  regarding  performance
factors for the six month periods ended June 30, 2003 and 2002:

                                     Six Months
                                       Ended         Percenta
                                                        ge
                                      June 30,       Increase
                                   2003      2002    (Decreas
                                                        e)
                                   ----      ----    --------
                                                        --
Average price per barrel  of  $   29.09              33%
oil                                        21.86
Average price per mcf of gas  $    4.67              99%
                                           2.35
Oil production in barrels        1,900     1,900     -
Gas production in mcf            13,100    16,500    (21%)
Gross oil and gas revenue     $  116,490   80,296    45%
Net oil and gas revenue       $  65,855    41,443    59%
Partnership distributions     $  42,500    15,000    183%
Limited              partner  $  38,250    13,500    183%
distributions
Per  unit  distribution   to
limited
 partners                     $   13.56              183%
                                           4.79
Number  of  limited  partner     2,821     2,821
units

Revenues

The  Partnership's oil and gas revenues increased to $116,490 from  $80,296
for  the six months ended June 30, 2003 and 2002, respectively, an increase
of  45%.  The principal factors affecting the comparison of the six  months
ended June 30, 2003 and 2002 are as follows:

1.  The  average  price  for a barrel of oil received  by  the  Partnership
    increased during the six months ended June 30, 2003 as compared to  the
    six  months ended June 30, 2002 by 33%, or $7.23 per barrel,  resulting
    in  an  increase  of  approximately  $13,700  in  revenues.  Oil  sales
    represented 47% of total oil and gas sales during the six months  ended
    June  30, 2003 as compared to 52% during the six months ended June  30,
    2002.

    The  average  price  for  an  mcf of gas received  by  the  Partnership
    increased during the same period by 99%, or $2.32 per mcf, resulting in
    an increase of approximately $30,400 in revenues.

    The  total  increase in revenues due to the change in  prices  received
    from oil and gas production is approximately $44,100.  The market price
    for  oil and gas has been extremely volatile over the past decade,  and
    management  expects a certain amount of volatility to continue  in  the
    foreseeable future.

<PAGE>
2.  Oil  production remained the same during the six months ended June  30,
    2003 as compared to the six months ended June 30, 2002.

    Gas production decreased approximately 3,400 mcf or 21% during the same
    period, resulting in a decrease of approximately $8,000 in revenues.

    The  total  decrease  in revenues due to the change  in  production  is
    approximately  $8,000.  The decrease in gas production is  due  to  one
    lease  that experienced downtime during the end of 2002 and  is  slowly
    coming back up to normal.

Costs and Expenses

Total  costs  and expenses increased to $78,848 from $59,342  for  the  six
months ended June 30, 2003 and 2002, respectively, an increase of 33%.  The
increase  is the result of higher lease operating costs, accretion  expense
and  general and administrative expense, partially offset by a decrease  in
depletion expense.

1.  Lease  operating  costs  and  production  taxes  were  30%  higher,  or
    approximately $11,800 more during the six months ended June 30, 2003 as
    compared to the six months ended June 30, 2002.  The increase in  lease
    operating  expense and production taxes is due to several small  leases
    having  repairs and maintenance performed during 2003, and the increase
    in  production  taxes  due  to an increase in gross  revenues  received
    during the six months ended June 30, 2003.

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
    85%  or approximately $7,200 during the six months ended June 30,  2003
    as  compared  to  the six months ended June 30, 2002. The  increase  in
    general and administrative expense is due to an increase in independent
    accounting review and audit fees.

3.  Depletion  expense decreased to $10,000 for the six months  ended  June
    30,  2003 from $12,000 for the same period in 2002.  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 units-of-production
    method is the predominant method used by full cost companies in the oil
    and gas industry, accordingly, the change improves the comparability of
    the Partnership's financial statements with its peer group.  The effect
    of  this change in method was to increase depletion expense for the six
    months  ended June 30, 2002 by $1,000 and had no effect on  net  income
    for the six months ended June 30, 2002.  The contributing factor to the
    decrease in depletion expense is in relation to the BOE depletion  rate
    for  the  six  months ended June 30, 2003, which was $2.45  applied  to
    4,083  BOE  as  compared to $2.58 applied to 4,650  BOE  for  the  same
    period.

Cumulative effect of change in accounting principle

On  January  1,  2003,  the  Partnership  adopted  Statement  of  Financial
Accounting  Standards No. 143, Accounting for Asset Retirement  Obligations
("SFAS  No. 143").  Adoption of SFAS No. 143 is required for all  companies
with fiscal years beginning after June 15, 2002.  The new standard requires
the Partnership to recognize a liability for the present value of all legal
obligations  associated with the retirement of tangible  long-lived  assets
and to capitalize an equal amount as a cost of the asset and depreciate the
additional cost over the estimated useful life of the asset.  On January 1,
2003,  the  Partnership  recorded  additional  costs,  net  of  accumulated
depreciation,   of  approximately  $57,971,  a  long  term   liability   of
approximately $63,696 and a loss of approximately $5,725 for the cumulative
effect on depreciation of the additional costs and accretion expense on the
liability related to expected abandonment costs of its oil and natural  gas
producing  properties.   At June 30, 2003, the asset retirement  obligation
was $66,183, and the increase in the balance from January 1, 2003 is due to
accretion expense of $2,547, offset slightly by the sale of an oil and  gas
property by $60.  The pro forma amounts for the three and six months  ended
June  30,  2002,  which  are presented on the face  of  the  statements  of
operations, reflect the effect of retroactive application of SFAS No. 143.


<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 provided by operating activities were approximately $56,300  in
the six months ended June 30, 2003 as compared to approximately $12,600  in
the  six  months ended June 30, 2002.  The primary source of the 2003  cash
flow from operating activities was profitable operations.

Cash  flows  provided by investing activities were none in the  six  months
ended  June 30, 2003 compared to approximately $700 in the six months ended
June 30, 2002.

Cash  flows used in financing activities were approximately $42,500 in  the
six  months ended June 30, 2003 as compared to approximately $15,000 in the
six  months ended June 30, 2002.  The only use in financing activities  was
the distributions to partners.

Total  distributions during the six months ended June 30, 2003 were $42,500
of  which $38,250 was distributed to the limited partners and $4,250 to the
general partners.  The per unit distribution to limited partners during the
six  months ended June 30, 2003 was $13.56.  Total distributions during the
six  months  ended  June  30,  2002  were  $15,000  of  which  $13,500  was
distributed  to  the limited partners and $1,500 to the  general  partners.
The  per unit distribution to limited partners during the six months  ended
June 30, 2002 was $4.79.

The source for the 2003 distributions of $42,500 was oil and gas operations
of  approximately  $56,300, resulting in excess cash for  contingencies  or
subsequent  distributions.   The  sources for  the  2002  distributions  of
$15,000 were oil and gas operations of approximately $12,600 and the change
in  oil  and  gas properties of approximately $700, with the  balance  from
available cash on hand at the beginning of the period.

Since  inception of the Partnership, cumulative monthly cash  distributions
of  $1,310,418  have  been made to the partners.   As  of  June  30,  2003,
$1,192,545 or $422.74 per limited partner unit has been distributed to  the
limited partners, representing an 85% return of the capital contributed.

As  of  June 30, 2003, the Partnership had approximately $49,200 in working
capital.   The  Managing  General Partner knows of no  unusual  contractual
commitments.   Although the partnership held many long-lived properties  at
inception,  because of the restrictions on property development imposed  by
the partnership agreement, the Partnership cannot develop its non-producing
properties, if any.  Without continued development, the producing  reserves
continue  to  deplete.  Accordingly, as the Partnership's  properties  have
matured  and  depleted,  the  net  cash  flows  from  operations  for   the
partnership  has  steadily  declined, except in  periods  of  substantially
increased  commodity pricing.  Maintenance of properties and administrative
expenses for the Partnership are increasing relative to production.  As the
properties   continue   to   deplete,   maintenance   of   properties   and
administrative costs as a percentage of production are expected to continue
to increase.

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.
After   reviewing  various  alternatives,  the  Managing  General   Partner
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.


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

Based   on  current  production,  commodity  prices  and  cash  flow   from
operations,  the Managing General Partner has adequate cash  flow  to  fund
debt  service, developmental projects and day to day operations, but it  is
not  sufficient  to  build a cash balance which would  allow  the  Managing
General  Partner to meet its debt principal maturities scheduled for  2004.
Therefore  the Managing General Partner 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.

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.

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.   This statement has been adopted by the Partnership  effective
January 1, 2003.  The transition adjustment resulting from the adoption  of
SFAS  No.  143  has been reported as a cumulative effect  of  a  change  in
accounting principle.

In  April 2003, the FASB issued Statement of Financial Accounting Standards
No.  149,  Amendment  of  Statement No. 133 on Derivative  Instruments  and
Hedging Activities ("SFAS No. 149").  SFAS No. 149 amendments require  that
contracts  with  comparable  characteristics be  accounted  for  similarly,
clarifies   when   a  contract  with  an  initial  investment   meets   the
characteristic  of  a  derivative and clarifies when a derivative  requires
special  reporting  in  the  statement of cash  flows.   SFAS  No.  149  is
effective  for  hedging relationships designated and for contracts  entered
into or modified after June 30, 2003, except for provisions that relate  to
SFAS  No. 133 Statement Implementation Issues that have been effective  for
fiscal  quarters  prior to June 15, 2003, should be applied  in  accordance
with  their  respective effective dates and certain provisions relating  to
forward  purchases or sales of when-issued securities or  other  securities
that  do not yet exist, should be applied to existing contracts as well  as
new contracts entered into after June 30, 2003.  Assessment by the Managing
General  Partner  revealed this pronouncement to  have  no  impact  on  the
Partnership.

In  May  2003, the FASB issued Statement of Financial Accounting  Standards
No.150,  Accounting for Certain Financial Instruments with  Characteristics
of  both  Liabilities  and  Equity  ("SFAS  150").   SFAS  150  establishes
standards  for  how  an  issuer classifies and measures  certain  financial
instruments  with  characteristics of  both  liabilities  and  equity.   It
requires that an issuer classify a financial instrument that is within  the
scope of SFAS 150 as a liability (or an asset in some circumstances).  Many
of those instruments were previously classified as equity.  The application
of  SFAS 150 is not expected to have a material effect on the Partnership's
consolidated  financial  statements.   This  Statement  is  effective   for
financial  instruments entered into or modified after  May  31,  2003,  and
otherwise  is  effective  at  the beginning of  the  first  interim  period
beginning after June 15, 2003.


<PAGE>
Item 3.   Quantitative and Qualitative Disclosures About Market Risk

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

Item 4.   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
quarterly 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 and the Partnership's consolidated subsidiaries
is   made   known  to  such  officers  by  others  within  these  entities,
particularly during the period this quarterly 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 II. - OTHER INFORMATION


Item 1.    Legal Proceedings

           None

Item 2.    Changes in Securities

           None

Item 3.    Defaults Upon Senior Securities

           None

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

           None

Item 5.    Other Information

           None

Item 6.    Exhibits and Reports on Form 8-K

        (a)  Exhibits:

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

        (b)  Reports on Form 8-K:

              No  reports  on Form 8-K were filed during the quarter  ended
June 30, 2003.
<PAGE>
                                SIGNATURES


Pursuant  to the requirements of the Securities Exchange Act of  1934,  the
registrant  has duly caused this report to be signed on its behalf  by  the
undersigned thereunto duly authorized.

                                 SOUTHWEST OIL & GAS
                                 INCOME FUND XI-A, L.P.
                                 a Delaware limited partnership


                                 By:   Southwest Royalties, Inc.
                                       Managing General Partner


                                 By:   /s/ Bill E. Coggin
                                       ------------------------------------
---
                                       Bill E. Coggin, Vice President
                                       and Chief Financial Officer

Date: November 12, 2003

<PAGE>
                    SECTION 302 CERTIFICATION                Exhibit 31.1


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

1.    I have reviewed this quarterly report on Form 10-Q of Southwest Oil &
Gas Income Fund XI-A, L.P.

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

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

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

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

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

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

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

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

  a)All  significant deficiencies and material weaknesses in the design  or
     operation   of  internal  controls  over  financial  reporting   which
     reasonably  likely  to  adversely affect the registrant's  ability  to
     record, process, summarize and report financial information; and

  b)Any  fraud, whether or not material, that involves management or  other
     employees  who  have  a significant role in the registrant's  internal
     controls over financial reporting.


Date:  November 12, 2003           /s/ H.H. Wommac, III
                                   H. H. Wommack, III
                                    Chairman, President and Chief Executive
Officer
                                   of Southwest Royalties, Inc., the
                                   Managing General Partner of
                                    Southwest  Oil & Gas Income Fund  XI-A,
L.P.



<PAGE>
                    SECTION 302 CERTIFICATION                Exhibit 31.2


I, Bill E. Coggin, certify that:

1.    I have reviewed this quarterly report on Form 10-Q of Southwest Oil &
Gas Income Fund XI-A, L.P.

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

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

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

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

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

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

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

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

  a)All  significant deficiencies and material weaknesses in the design  or
     operation   of  internal  controls  over  financial  reporting   which
     reasonably  likely  to  adversely affect the registrant's  ability  to
     record, process, summarize and report financial information; and

  b)Any  fraud, whether or not material, that involves management or  other
     employees  who  have  a significant role in the registrant's  internal
     controls over financial reporting.


Date:  November 12, 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  XI-A,
L.P.



<PAGE>

                          CERTIFICATION PURSUANT TO
                               Exhibit 32.1
                          19 U.S.C. SECTION 1350,
                          AS ADOPTED PURSUANT TO
               SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002


      In connection with the Quarterly Report of Southwest Oil & Gas Income
Fund  XI-A, Limited Partnership (the "Company") on Form 10-Q for the period
ending  June 30, 2003 as filed with the Securities and Exchange  Commission
on  the  date hereof (the "Report"), I, H.H. Wommack, III, Chief  Executive
Officer  of the Managing General Partner of the Company, certify,  pursuant
to  18 U.S.C.  1350, as adopted pursuant to  906 of the Sarbanes-Oxley  Act
of 2002, that:

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

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


Date:  November 12, 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 XI-A, L.P.

<PAGE>
              CERTIFICATION PURSUANT TO            Exhibit 32.2
                          19 U.S.C. SECTION 1350,
                          AS ADOPTED PURSUANT TO
               SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002


   In  connection with the Quarterly Report of Southwest Oil &  Gas  Income
Fund  XI-A, Limited Partnership (the "Company") on Form 10-Q for the period
ending  June 30, 2003 as filed with the Securities and Exchange  Commission
on  the  date  hereof  (the "Report"), I, Bill E. Coggin,  Chief  Financial
Officer  of the Managing General Partner of the Company, certify,  pursuant
to  18 U.S.C.  1350, as adopted pursuant to  906 of the Sarbanes-Oxley  Act
of 2002, that:

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

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


Date:  November 12, 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 XI-A, L.P.


<PAGE>